10-K 1 d43782e10vk.htm FORM 10-K e10vk
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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, 2006
    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 or 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
4.90% Exchangeable Debentures, due 2008
  The New York Stock Exchange
4.95% Exchangeable Debentures, due 2008
  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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ     Accelerated filer o     Non-accelerated filer o     
 
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 stock held by non-affiliates of the registrant as of June 30, 2006, was $26,464,653,232.
 
On February 15, 2007, 444,461,491 shares of common stock were outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2007 annual meeting of stockholders — Part III
 


 

 
TABLE OF CONTENTS
 
                 
        Page
 
  Business   5
  Risk Factors   11
  Unresolved Staff Comments   14
  Properties   14
  Legal Proceedings   25
  Submission of Matters to a Vote of Security Holders   25
 
  Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   26
  Selected Financial Data   27
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   29
  Quantitative and Qualitative Disclosures About Market Risk   60
  Financial Statements and Supplementary Data   62
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   119
  Controls and Procedures   119
  Other Information   121
 
  Directors, Executive Officers and Corporate Governance   122
  Executive Compensation   122
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   122
  Certain Relationships and Related Transactions, and Director Independence   122
  Principal Accounting Fees and Services   122
 
  Exhibits and Financial Statement Schedules   123
  128
   
EXHIBITS
       
 Severance Agreement
 Statement of Computation of Ratios of Earnings to Fixed Charges
 Registrant's Significant Subsidiaries
 Consent of KPMG LLP
 Consent of LaRoche Petroleum Consultants
 Consent of Ryder Scott Company LP
 Consent of AJM Petroleum Consultants
 Certification of J. Larry Nichols Pursuant to Section 302
 Certification of Danny J. Heatly Pursuant to Section 302
 Certification of J. Larry Nichols Pursuant to Section 906
 Certification of Danny J. Heatly Pursuant to Section 906


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DEFINITIONS
 
As used in this document:
 
“Bbl” or “Bbls” means barrel or barrels.
 
“Bcf” means billion cubic feet.
 
“Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
 
“FPSO” means floating, production, storage and offloading facilities.
 
“Btu” means British Thermal units, a measure of heating value.
 
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
 
“LIBOR” means London Interbank Offered Rate.
 
“MBbls” means thousand barrels.
 
“MMBbls” means million barrels.
 
“MBoe” means thousand Boe.
 
“MMBoe” means million Boe.
 
“MMBtu” means million Btu.
 
“Mcf” means thousand cubic feet.
 
“MMcf” means million cubic feet.
 
“NGL” or “NGLs” means natural gas liquids.
 
“NYMEX” means New York Mercantile Exchange.
 
“Oil” includes crude oil and condensate.
 
“SEC” means United States Securities and Exchange Commission.
 
“Domestic” means the properties of Devon in the onshore continental United States and the offshore Gulf of Mexico.
 
“U.S. Onshore” means the properties of Devon in the continental United States.
 
“U.S. Offshore” means the properties of Devon in the Gulf of Mexico.
 
“Canada” means the division of Devon encompassing oil and gas properties located in Canada.
 
“International” means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.
 
DISCLOSURE 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 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 which was used to prepare the December 31, 2006 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 the negative thereof or variations thereon or similar


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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;
 
  •  production levels, including Canadian production subject to government royalties which fluctuate with prices and international production governed by payout agreements which affect reported production;
 
  •  reserve levels;
 
  •  competitive conditions;
 
  •  technology;
 
  •  the availability of capital resources;
 
  •  capital expenditure and other contractual obligations;
 
  •  the supply and demand for oil, natural gas, NGLs and other products or services;
 
  •  the price of oil, natural gas, NGLs and other products or services;
 
  •  currency exchange rates;
 
  •  the weather;
 
  •  inflation;
 
  •  the availability of goods and services;
 
  •  drilling risks;
 
  •  future processing volumes and pipeline throughput;
 
  •  general economic conditions, either internationally or 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;
 
  •  the securities or capital markets; 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 oil and gas exploration, development and production, the transportation of oil, gas, and NGLs and the processing of natural gas. We own oil and gas properties principally in the United States and Canada and, to a lesser degree, various regions located outside North America, including Azerbaijan, Brazil and China. We also own properties in West Africa and Egypt that we intend to sell in 2007. In addition to our oil and gas operations, we have marketing and midstream operations primarily in North America. These include marketing natural gas, crude oil and NGLs, and constructing and operating pipelines, storage and treating facilities and gas processing plants. A detailed description of our significant properties and associated 2006 developments can be found under “Item 2. Properties.”
 
We began operations in 1971 as a privately held company. In 1988, our common stock began trading publicly on the American Stock Exchange under the symbol “DVN.” In October 2004, we transferred our common stock listing to 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
 
We have a two-pronged operating strategy. First, we invest the vast majority of our capital budget in low-risk exploitation and development projects on our extensive North American property base which provides reliable and repeatable production and reserves additions. To supplement that strategy, we annually invest a measured amount of capital in high-impact, long cycle-time projects to replenish our development inventory for the future. The philosophy that underlies the execution of this strategy is to strive to increase value on a per share basis by:
 
  •  building oil and gas reserves and production;
 
  •  exercising capital discipline;
 
  •  preserving financial flexibility;
 
  •  maintaining a low unit-cost structure; and
 
  •  improving performance through our marketing and midstream operations.
 
Development of Business
 
During 1988, we expanded our capital base with our first issuance of common stock to the public. This transaction began a substantial expansion program that has continued through the subsequent years. This expansion is attributable to both a focused mergers and acquisitions program spanning a number of years and an active ongoing exploration and development drilling program. Total proved reserves increased from 8 MMBoe1 at year-end 1987 to 2,376 MMBoe2 at year-end 2006.
 
During the same time period, we have grown proved reserves from 0.66 Boe1 per diluted share at the end of 1987 to 5.30 Boe2 per diluted share at the end of 2006. This represents a compound annual growth rate of 12%. We have also increased production from 0.09 Boe1 per diluted share in 1987 to 0.48 Boe2 per diluted share in 2006, for a compound annual growth rate of 9%. This per share growth is a direct result of successful execution of our strategic plan and other key transactions and events.
 
 
1 Excludes the effects of mergers in 1998 and 2000 that were accounted for as poolings of interests.
2 Excludes reserves in Egypt that are held for sale and classified as discontinued operations as of December 31, 2006.


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We achieved a number of significant accomplishments in our operations during 2006, including those discussed below.
 
  •  Barnett Shale Expansion — We dramatically increased our presence in the Barnett Shale area of north Texas in 2006 with our $2.2 billion acquisition of Chief Holdings LLC (“Chief”). The acquired properties included estimated proved reserves of approximately 600 Bcf of natural gas equivalent and leasehold totaling 169,000 net acres with some 2,000 additional drilling locations.
 
  •  U.S. Onshore Production and Reserves Growth — Our U.S. onshore properties, including the Barnett Shale and the Groesbeck and Carthage areas in east Texas, showed strong production growth in 2006. These three areas, which accounted for a little over one-half of our U.S. onshore production, had production growth in 2006 of 11% compared to 2005.
 
In addition to production growth, our U.S. onshore properties also demonstrated significant growth in proved reserves. U.S onshore production in 2006 of 110 MMBoe was more than offset by 265 MMBoe of additions from extensions and discoveries during the year, as well as 105 MMBoe added through acquisitions, primarily the Chief acquisition. The additional reserves added by drilling and acquisition activities caused our 2006 U.S. onshore proved reserves to increase 21% compared to the end of 2005.
 
  •  Gulf of Mexico Exploration and Development — We continued to achieve success in 2006 with our deepwater Gulf of Mexico exploration program. To date, we have drilled four discovery wells in the Lower Tertiary trend — Cascade in 2002, St. Malo in 2003, Jack in 2004 and Kaskida in the third quarter of 2006. Also in the third quarter of 2006, we announced the successful production test of the Jack No. 2 well in the Lower Tertiary. These achievements support our positive view of the Lower Tertiary and demonstrate the growth potential of our high-impact exploration strategy on long-term production, reserves and value.
 
Specific Gulf of Mexico developments in 2006 included the following:
 
  •  Along with our partners, we conducted a successful production test of the deepwater Jack No. 2 well in the Lower Tertiary trend. The successful production test was an important milestone in moving the Jack project, originally discovered in 2004, toward sanctioning and development. We have a 25% working interest in the Jack prospect.
 
  •  Also in the Lower Tertiary trend, we increased our working interest in the Cascade project, discovered in 2002, from 25% to 50%. We and our partner plan to develop Cascade using an FPSO vessel. We anticipate first production from Cascade in late 2009.
 
  •  Elsewhere in the Lower Tertiary, we and our partners announced an oil discovery on the Kaskida prospect. Kaskida is our fourth discovery in the Lower Tertiary trend and our first in the Keathley Canyon deepwater lease area. We have identified 19 additional exploratory prospects in the Lower Tertiary, and 12 of these prospects are on our Keathley Canyon acreage. We believe that Kaskida, in which we own a 20% working interest, is the largest of our four Lower Tertiary discoveries to date.
 
  •  In addition to our Lower Tertiary success, we also announced a Miocene-aged oil discovery on the Mission Deep prospect in the fourth quarter of 2006. The well, in 7,300 feet of water, was drilled to 25,000 feet and encountered more than 250 feet of net oil pay. We have 15 additional prospects in our deepwater Miocene inventory. Our working interest in the Mission Deep prospect is 50%.
 
  •  We secured long-term contracts for two deepwater drilling rigs in 2006. One of the rigs is scheduled for delivery in mid-2007, and the other is scheduled for delivery in mid-2008. With these two deepwater rigs under contract, we will have additional capacity and flexibility to test, appraise and develop multiple prospects in the Lower Tertiary and Miocene trends.
 
  •  Jackfish — During 2006, facilities construction and drilling continued at our 100% owned Jackfish thermal heavy oil project in Canada. We expect to commence steam injection at Jackfish in the second quarter of 2007, with estimated full production of 35,000 barrels of oil per day anticipated by the end of 2008.


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  •  Polvo — Construction and fabrication for the Polvo oil development project offshore Brazil continued on schedule throughout 2006. We expect first production from Polvo in mid-2007. We operate Polvo with a 60% working interest.
 
On November 14, 2006, we announced our plans to divest our operations in Egypt. At December 31, 2006, our Egyptian operations had proved reserves of eight million Boe. Subsequently, on January 23, 2007, we announced our plans to divest our operations in West Africa, including Equatorial Guinea, Cote d’Ivoire, and other countries in the region. At December 31, 2006, our West African operations had proved reserves of 90 million Boe. We anticipate completing the sale of our Egyptian operations in the first half of 2007 and our West African operations in the third quarter of 2007. Divesting these properties will allow us to redeploy our financial and intellectual capital to the significant growth opportunities we have developed onshore in North America and in the deepwater Gulf of Mexico. Additionally, we will sharpen our focus in North America and concentrate our international operations in Brazil and China, where we have established competitive advantages.
 
Pursuant to accounting rules for discontinued operations, our Egyptian operations were classified as discontinued operations at the end of 2006. Accordingly, we have classified all amounts related to our operations in Egypt as discontinued. Therefore, all amounts for all periods presented in this document related to our continuing operations exclude Egypt. Our West African operations did not meet the criteria to be considered discontinued operations at the end of 2006. Therefore, all amounts related to our operations in West Africa are still presented in this document as part of our continuing operations. Beginning in 2007, our operations in West Africa will be considered and classified as discontinued.
 
Financial Information about Segments and Geographical Areas
 
Notes 14 and 15 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 and Natural Gas Marketing
 
The spot market for oil and gas is subject to volatility as supply and demand factors fluctuate. We may periodically enter into financial hedging arrangements, fixed-price contracts or firm delivery commitments 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 (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. All of our oil production is sold at variable or market-sensitive prices.
 
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 February 2007, approximately 75% of our natural 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 23% of our production was committed under various long-term contracts which dedicate the natural gas to a purchaser for an extended period of time but still at market sensitive prices. Our remaining gas production was sold under long-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 and gas production in a timely and efficient manner. Our most significant marketing and midstream asset is the Bridgeport


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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 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. Existing 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.
 
During 2006, revenues received from ExxonMobil and its affiliates were $1.1 billion, or 10% of our consolidated revenues. No purchaser accounted for over 10% of our revenues in 2005 or 2004.
 
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.
 
Government Regulation
 
The oil and gas industry is subject to various types of regulation throughout the world. Legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, 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. Inasmuch as new legislation affecting the oil and gas industry is commonplace and 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.
 
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, local and international laws and regulations, including regulations related to the acquisition of seismic data; the location of wells; drilling and casing of wells; well production; spill prevention plans; the 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; the calculation and disbursement of royalty payments and production taxes; the plugging and abandoning of wells; the transportation of production; and, in international operations, minimum investments in the country of operations.
 
Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells which may be drilled in a unit; the rate of production allowable from oil and natural gas wells; and the unitization or pooling of oil and natural 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 natural 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. oil and natural gas 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 natural 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 have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.
 
Pricing and Marketing in Canada
 
An order from Canada’s National Energy Board (“NEB”) is required for oil and natural gas exports from Canada. Any oil or natural gas export to be made pursuant to an export contract of a certain duration or covering a certain quantity requires an exporter to obtain an export license from the NEB, which requires the approval of the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts meet certain criteria prescribed by the 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 based on such factors as reserve availability, transportation arrangements and market considerations.


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Investment Canada Act
 
The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval.
 
Production Sharing Contracts
 
Many 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 partner to retain higher fractions of revenue.
 
Environmental and Occupational Regulations
 
We are subject to various federal, state, provincial, local and international laws and regulations concerning occupational safety and health and 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 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, are required to be implemented for some international oil and gas operations.
 
In 1997, numerous countries participated in an international conference under the United Nations Framework Convention on Climate Change and adopted an agreement known as the Kyoto Protocol (the “Protocol”). The Protocol became effective February 14, 2005, and requires reductions of certain emissions that contribute to atmospheric levels of greenhouse gases. Certain countries in which we operate (but not the United States) have ratified the Protocol. Presently, it is not possible to accurately estimate the costs we could incur to comply with any laws or regulations developed to achieve such emissions reductions, but such expenditures could be substantial. In 2006, Devon published its Corporate Climate Change Position and Strategy. Key components of the strategy include initiation of energy conservation measures, tracking emerging climate changes legislation and publication of a corporate greenhouse gas emission inventory by the end of 2007. All provisions of the strategy are in progress.
 
We consider the costs of environmental protection and safety and health compliance necessary and manageable parts of our business. With the efforts of our Environmental, Health and Safety Department, we have been able to plan for and comply with environmental and safety and health initiatives without materially altering our operating strategy. We anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. While our unreimbursed expenditures in 2006 concerning such matters were immaterial, 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.
 
Employees
 
As of December 31, 2006, we had approximately 4,600 employees. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.


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Competition
 
See “Item 1A. Risk Factors.”
 
Availability of Reports
 
Through our website, http://www.devonenergy.com, we make available electronic copies of the charters of the committees of our Board of Directors, other documents related to Devon’s corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer), and documents Devon files or furnishes 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. Although we have a diversified asset base, a strong balance sheet and a history of generating sufficient cash to fund capital expenditure and investment programs and to pay dividends, if any of the following risk factors should occur, our profitability, financial condition and/or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
 
Oil, Natural Gas and NGL Prices are Volatile
 
Our financial results are highly dependent on the prices of and demand for oil, natural gas and NGLs. A significant downward movement of the prices for these commodities could have a material adverse effect on our estimated proved reserves, revenues and operating cash flows, as well as the level of planned drilling activities. Such a downward price movement could also have a material adverse effect on our profitability, the carrying value of our oil and gas properties 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, natural gas and NGLs;
 
  •  conservation efforts;
 
  •  OPEC production restraints;
 
  •  weather;
 
  •  regional market pricing differences;
 
  •  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, natural gas and NGLs;
 
  •  the price and availability of alternative fuels;
 
  •  the overall economic environment; and
 
  •  governmental regulations and taxes.
 
Estimates of Oil, Natural 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


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estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Additional discussion of our policies regarding estimating and recording reserves is described in “Item 2. Properties — Proved Reserves and Estimated Future Net Revenue.”
 
Discoveries or Acquisitions of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production
 
The production rate from oil and gas properties generally declines 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 methods of transportation;
 
  •  environmental hazards or liabilities; and
 
  •  shortages or delays in the 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.


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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. Higher recent commodity prices have increased drilling and operating costs of existing properties. Higher prices have also increased the costs of properties available for acquisition, and there are a greater number of publicly traded companies and private-equity firms with the financial resources to pursue acquisition opportunities. Certain of our competitors have financial and other resources substantially larger than ours, and they have also established strategic long-term positions and maintain strong governmental relationships in countries 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 natural gas production, such as changing worldwide prices and levels of production, 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, China and various countries in West Africa. As a result, we face political and economic risks and other uncertainties that are less prevalent 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 in 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 operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines,


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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.
 
Government Laws and Regulations Can Change
 
Our operations are subject to federal laws and regulations in the United States, Canada and the other international countries in which we operate. In addition, we are also subject to the laws and regulations of various states, provinces and local governments. Pursuant to such legislation, 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 legislation have affected, and at times in the future could affect, our future 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 such legislation 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 or lessee and operator of oil and gas properties, we are subject to various federal, state, provincial, 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 laws or regulations 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, natural 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 marketplace following the 2005 hurricanes in the Gulf of Mexico, we currently have only a de minimis amount of coverage for any damage that may be caused by future named windstorms in the Gulf of Mexico.
 
Item 1B.   Unresolved Staff Comments
 
Not applicable.
 
Item 2.   Properties
 
Substantially all of our properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage located in our core operating areas. These interests entitle us to drill for and produce oil, natural gas and NGLs from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral and 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 2,700 miles of pipeline, two gas processing plants with 680 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator.


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Proved Reserves and Estimated Future Net Revenue
 
The SEC defines proved oil and gas reserves as the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
 
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, and assign responsibilities for reserves bookings to our Reserve Evaluation Group (the “Group”). Our policies also require that reserve estimates be made by qualified reserves estimators (“QREs”), as defined by the Society of Petroleum Engineers’ standards. A list of our QREs is kept by the Senior Advisor — Corporate Reserves. All QREs are required to receive education covering the fundamentals of SEC proved reserves assignments.
 
The Group is responsible for internal reserves evaluation and certification and includes the Manager — E&P Budgets and Reserves and the Senior Advisor — Corporate Reserves. The Group reports independently of any of our operating divisions. The Vice President — Planning and Evaluation is directly responsible for overseeing the Group and reports to the President of Devon. No portion of the Group’s compensation is 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.
 
In addition to internal audits, we engage three independent petroleum consulting firms to both prepare and audit a significant portion of our proved reserves. Ryder Scott Company, L.P. prepared the 2006 reserves estimates for all our offshore Gulf of Mexico properties and for 99% of our International proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2006 reserves estimates for 87% of our domestic onshore properties. AJM Petroleum Consultants prepared estimates covering 46% of our 2006 Canadian reserves and audited an additional 39% of our Canadian reserves.
 
Set forth below is a summary of the reserves which were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2006, 2005 and 2004.
 
                                                 
    2006     2005     2004  
    Prepared     Audited     Prepared     Audited     Prepared     Audited  
 
U.S. 
    7 %     81 %     9 %     79 %     16 %     61 %
Canada
    46 %     39 %     46 %     26 %     22 %      
International
    99 %           98 %           98 %      
Total
    28 %     61 %     31 %     54 %     28 %     35 %
 
“Prepared” reserves are those quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves which 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.


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In addition to internal and external reviews, three independent members of our Board of Directors have been assigned to a Reserves Committee. The Reserves Committee meets at lease 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 Reserves Committee assists the Board of Directors with the oversight of the following:
 
  •  the annual review and evaluation of our consolidated oil, gas and NGL reserves;
 
  •  the integrity of our reserves evaluation and reporting system;
 
  •  our compliance with legal and regulatory requirements related to reserves evaluation, preparation, and disclosure;
 
  •  the qualifications and independence of our independent engineering consultants; and
 
  •  our business practices and ethical standards in relation to the preparation and disclosure of reserves.


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The following table sets forth our estimated proved reserves and the related estimated pre-tax future net revenues, pre-tax 10% present value and after-tax standardized measure of discounted future net cash flows as of December 31, 2006. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 15 to our consolidated financial statements included herein.
 
                         
    Total
    Proved
    Proved
 
    Proved
    Developed
    Undeveloped
 
    Reserves     Reserves     Reserves  
 
Total Reserves
                       
Oil (MMBbls)
    708       358       350  
Gas (Bcf)
    8,356       6,518       1,838  
NGLs (MMBbls)
    275       229       46  
MMBoe(1)
    2,376       1,674       702  
Pre-tax future net revenue (in millions)(2)
  $ 44,428       32,471       11,957  
Pre-tax 10% present value (in millions)(2)
  $ 24,095       19,168       4,927  
Standardized measure of discounted future net cash flows (in millions)(2)(3)
  $ 16,573                  
U.S. Reserves
                       
Oil (MMBbls)
    170       147       23  
Gas (Bcf)
    6,355       4,916       1,439  
NGLs (MMBbls)
    233       196       37  
MMBoe(1)
    1,462       1,163       299  
Pre-tax future net revenue (in millions)(2)
  $ 24,203       20,504       3,699  
Pre-tax 10% present value (in millions)(2)
  $ 12,639       11,503       1,136  
Standardized measure of discounted future net cash flows (in millions)(2)(3)
  $ 8,677                  
Canadian Reserves
                       
Oil (MMBbls)
    329       112       217  
Gas (Bcf)
    1,896       1,560       336  
NGLs (MMBbls)
    42       33       9  
MMBoe(1)
    687       405       282  
Pre-tax future net revenue (in millions)(2)
  $ 12,749       8,499       4,250  
Pre-tax 10% present value (in millions)(2)
  $ 6,714       4,872       1,842  
Standardized measure of discounted future net cash flows (in millions)(2)(3)
  $ 4,817                  
International Reserves
                       
Oil (MMBbls)
    209       99       110  
Gas (Bcf)
    105       42       63  
NGLs (MMBbls)
                 
MMBoe(1)
    227       106       121  
Pre-tax future net revenue (in millions)(2)
  $ 7,476       3,468       4,008  
Pre-tax 10% present value (in millions)(2)
  $ 4,742       2,793       1,949  
Standardized measure of discounted future net cash flows (in millions)(2)(3)
  $ 3,079                  
 
 
(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 natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. NGL reserves are converted to Boe on a one-to-one basis with oil.
 
(2)  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 non-property related expenses such as debt service and future income tax expense or to depreciation, depletion and amortization.


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These amounts were calculated using prices and costs in effect for each individual property as of December 31, 2006. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yield average prices over the life of our properties of $46.11 per Bbl of oil, $5.06 per Mcf of natural gas and $27.63 per Bbl of NGLs. These prices compare to the December 31, 2006, NYMEX cash price of $61.05 per Bbl for crude oil and the Henry Hub spot price of $5.64 per MMBtu for natural gas.
 
The present value of after-tax future net revenues discounted at 10% per annum (“standardized measure”) was $16.6 billion at the end of 2006. Included as part of standardized measure were discounted future income taxes of $7.5 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10% present value”) was $24.1 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors which are more consistent from company to company. We also understand that securities analysts use the pre-tax 10% present value measure in similar ways.
 
(3) See Note 15 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
 
As presented in the previous table, we had 1,674 MMBoe of proved developed reserves at December 31, 2006. 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, 2006.
 
                         
    Total
    Proved
    Proved
 
    Proved
    Developed
    Developed
 
    Developed
    Producing
    Non-Producing
 
    Reserves     Reserves     Reserves  
 
Total Reserves
                       
Oil (MMBbls)
    358       298       60  
Gas (Bcf)
    6,518       5,784       734  
NGLs (MMBbls)
    229       208       21  
MMBoe
    1,674       1,470       204  
U.S. Reserves
                       
Oil (MMBbls)
    147       123       24  
Gas (Bcf)
    4,916       4,337       579  
NGLs (MMBbls)
    196       178       18  
MMBoe
    1,163       1,024       139  
Canadian Reserves
                       
Oil (MMBbls)
    112       93       19  
Gas (Bcf)
    1,560       1,410       150  
NGLs (MMBbls)
    33       30       3  
MMBoe
    405       358       47  
International Reserves
                       
Oil (MMBbls)
    99       82       17  
Gas (Bcf)
    42       37       5  
NGLs (MMBbls)
                 
MMBoe
    106       88       18  
 
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 the last fiscal year except in filings with the SEC and


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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.
 
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, 2006. 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.
 
Production, Revenue and Price History
 
Certain information concerning oil, natural gas and NGL production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 2006, is set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
Drilling Activities
 
The following tables summarize the results of our development and exploratory drilling activity for the past three years. The tables do not include our Egyptian operations that were classified as discontinued at the end of 2006.
 
Development Well Activity
 
                                                                 
    Wells Drilling at
       
    December 31,
    Net Wells Completed(2)  
    2006     2006     2005     2004  
    Gross(1)     Net(2)     Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. 
    210       151.4       877.1       12.5       782.3       8.2       719.4       11.7  
Canada
    12       7.1       593.2       3.3       546.8       5.2       413.2       17.7  
International
    20       2.3       8.5             10.3             22.5        
                                                                 
Total
    242       160.8       1,478.8       15.8       1,339.4       13.4       1,155.1       29.4  
                                                                 
 
Exploratory Well Activity
 
                                                                 
    Wells Drilling at
       
    December 31,
    Net Wells Completed(2)  
    2006     2006     2005     2004  
    Gross(1)     Net(2)     Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. 
    28       10.1       24.5       10.3       18.6       6.5       11.2       6.8  
Canada
    8       5.3       82.1       1.0       144.2       12.4       145.7       12.1  
International
    7       3.4             2.1       0.5       3.3       0.5       0.4  
                                                                 
Total
    43       18.8       106.6       13.4       163.3       22.2       157.4       19.3  
                                                                 
 
 
(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 therein.


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For the wells being drilled as of December 31, 2006 presented in the tables above, the following table summarizes the results of such wells as of February 1, 2007.
 
                                                 
    Productive     Dry     Still in Progress  
    Gross     Net     Gross     Net     Gross     Net  
 
U.S. 
    92       59.7       4       2.2       142       99.6  
Canada
    14       7.6                   6       4.8  
International
    2       0.1                   25       5.6  
                                                 
Total
    108       67.4       4       2.2       173       110.0  
                                                 
 
Well Statistics
 
The following table sets forth our producing wells as of December 31, 2006. The table does not include our Egyptian operations that were classified as discontinued at the end of 2006.
 
                                                 
    Oil Wells     Gas Wells     Total Wells  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
 
U.S.
                                               
Onshore
    8,494       2,751       16,588       11,415       25,082       14,166  
Offshore
    452       316       235       151       687       467  
                                                 
Total U.S. 
    8,946       3,067       16,823       11,566       25,769       14,633  
Canada
    2,885       1,983       4,506       2,569       7,391       4,552  
International
    526       217       4       2       530       219  
                                                 
Grand Total
    12,357       5,267       21,333       14,137       33,690       19,404  
                                                 
 
 
(1) Gross wells are the total number of wells in which we own a working interest.
 
(2) Net wells are gross wells multiplied by our fractional working interests therein.
 
Developed and Undeveloped Acreage
 
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2006. The table does not include our Egyptian operations that were classified as discontinued at the end of 2006.
 
                                 
    Developed     Undeveloped  
    Gross(1)     Net(2)     Gross(1)     Net(2)  
    (In thousands)  
 
U.S.
                               
Onshore
    3,364       2,162       5,893       3,026  
Offshore
    416       223       3,125       1,499  
                                 
Total U.S. 
    3,780       2,385       9,018       4,525  
Canada
    3,392       2,124       10,257       6,304  
International
    552       299       15,222       9,440  
                                 
Grand Total
    7,724       4,808       34,497       20,269  
                                 
 
 
(1) Gross acres are the total number of acres in which we own a working interest.
 
(2) Net acres are gross acres multiplied by our fractional working interests therein.
 
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.


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We are the operator of 22,434 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.
 
Organization Structure and Property Profiles
 
Our properties are located within the U.S. onshore and offshore regions, Canada, and certain locations outside North America. The following table presents proved reserve information for our significant properties as of December 31, 2006, along with their production volumes for the year 2006. Included in the table are certain U.S. offshore properties which currently have no proved reserves or production. Such properties are considered significant because they may be the source of significant growth in proved reserves and production in the future. Also included in the table are properties located in West Africa that we intend to sale in 2007. The table does not include our Egyptian operations that were classified as discontinued at the end of 2006. Additional summary profile information for our significant properties is provided following the table.
 
                                 
    Proved
    Proved
             
    Reserves
    Reserves
    Production
    Production
 
    (MMBoe)(1)     %(2)     (MMBoe)(1)     %(2)  
 
U.S.
                               
Barnett Shale
    608       25.6 %     38       17.7 %
Carthage
    161       6.8 %     14       6.6 %
Permian Basin, Texas
    111       4.7 %     9       4.2 %
Washakie
    104       4.4 %     6       2.6 %
Groesbeck
    65       2.7 %     5       3.0 %
Permian Basin, New Mexico
    44       1.9 %     6       3.2 %
Other U.S. Onshore
    260       10.9 %     32       14.3 %
                                 
Total U.S. Onshore
    1,353       57.0 %     110       51.6 %
                                 
Deepwater Producing
    67       2.8 %     14       6.5 %
Deepwater Development
                       
Deepwater Exploration
                       
Other U.S. Offshore
    42       1.8 %     8       3.8 %
                                 
Total U.S. Offshore
    109       4.6 %     22       10.3 %
                                 
Total U.S. 
    1,462       61.6 %     132       61.9 %
                                 
Canada
                               
Jackfish
    186       7.8 %            
Deep Basin
    97       4.1 %     12       5.5 %
Lloydminster
    84       3.6 %     9       4.1 %
Peace River Arch
    75       3.1 %     8       3.6 %
Northeast British Columbia
    59       2.5 %     9       4.1 %
Other Canada
    186       7.8 %     20       9.6 %
                                 
Total Canada
    687       28.9 %     58       26.9 %
                                 
International
                               
Azerbaijan
    84       3.5 %     4       1.7 %
China
    17       0.7 %     4       2.1 %
Brazil
    9       0.4 %            
Other
    27       1.1 %     2       0.9 %
Assets to be sold in 2007(3):
                               
Equatorial Guinea
    67       2.8 %     11       5.2 %
Other West Africa assets
    23       1.0 %     3       1.3  
                                 
Total International
    227       9.5 %     24       11.2 %
                                 
Grand Total
    2,376       100.0 %     214       100.0 %
                                 


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(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 natural gas to oil, which rate is not necessarily indicative of the relationship of gas to 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.
 
(3) In January 2007, we announced our plans to sell our assets in West Africa.
 
U.S. Onshore
 
Barnett Shale — The Barnett Shale, located in north central Texas, is our largest property both in terms of production and proved reserves. Our leases include approximately 725,000 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 natural gas liquids. We have an average working interest in the Barnett Shale of greater than 90%.
 
During 2006, we acquired additional Barnett Shale assets from Chief. The Chief acquisition added approximately 100 MMBoe of proved reserves, 169,000 net acres and some 2,000 additional drilling locations to our Barnett Shale holdings. We drilled 383 gross wells in the Barnett Shale in 2006 and expect to drill 385 gross wells in the area in 2007.
 
Carthage — The Carthage area in east Texas includes primarily Harrison, Marion, Panola and Shelby counties. We hold approximately 126,000 net acres in the area. Our Carthage area wells produce primarily natural gas and natural gas liquids from conventional reservoirs. Our average working interest in this area is about 85%. We drilled 122 gross wells at Carthage in 2006 and plan to drill 150 gross wells in the area in 2007.
 
Permian Basin, Texas — Our oil and gas properties in the Permian Basin of west Texas comprise approximately 1.2 million net acres. Our acreage is located primarily in Andrews, Crane, Martin, Terry, Ward and Yoakum counties. The Permian Basin produces both oil and natural gas from conventional reservoirs. Our average working interest in these properties is about 40%. We drilled 95 gross wells in the Permian Basin of west Texas in 2006, and we plan to drill another 100 gross wells in the area in 2007.
 
Washakie — Our Washakie area leases are concentrated in Carbon and Sweetwater counties in southern Wyoming. We hold about 157,000 net acres in the Washakie area. Washakie produces primarily natural gas from conventional reservoirs. Our average working interest in the Washakie area is about 76%. In 2006, we drilled 137 wells at Washakie, and we plan to drill another 105 wells in the area in 2007.
 
Groesbeck — The Groesbeck area of east Texas includes portions of Freestone, Leon, Limestone and Robertson counties. We hold about 173,000 net acres of land in the Groesbeck area. Groesbeck produces primarily natural gas from conventional reservoirs. Our average working interest in the area is approximately 72%. In 2006, we drilled 31 gross wells in the area. Our plans anticipate drilling 34 additional gross wells in the Groesbeck area in 2007.
 
Permian Basin, New Mexico — We also own oil and gas properties in the Permian Basin in south eastern New Mexico. We hold about 342,000 net acres concentrated in Eddy and Lea counties. We produce conventional oil and natural gas from the Permian Basin in New Mexico, and have an average working interest of about 75% in these properties. In 2006, we drilled 82 gross wells in this area, and we expect to drill another 44 gross wells in 2007.
 
U.S. Offshore
 
Deepwater Producing — Our assets in the Gulf of Mexico include four significant producing properties located in deep water (greater than 600 feet). These properties are Magnolia, Nansen, Red Hawk and Zia. They are all located on federal leases and total approximately 48,000 net acres. The properties produce both crude oil and natural gas. Our working interest is 65% in Zia and 50% in each of the other three properties.


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We drilled a total of two gross deepwater producing wells in 2006 and expect to drill four additional gross wells in 2007.
 
Deepwater Development — In addition to our four significant deepwater producing properties, we are in the process of developing two other deepwater projects, Merganser and Cascade. Merganser and Cascade are located on federal leases encompassing a total of approximately 11,500 net acres. We have 50% working interests in both properties.
 
We drilled two producing wells at Merganser in 2006. These wells are expected to commence producing natural gas in mid-2007. No additional drilling is planned at Merganser.
 
We announced in 2006 our plans to develop the 2002 Cascade discovery using an FPSO vessel. Cascade is expected to begin producing primarily oil in late 2009. Additional drilling at Cascade is in the planning stage.
 
Deepwater Exploration — Our exploration program in the Gulf of Mexico is focused primarily on deepwater opportunities. Our deepwater exploratory prospects include Miocene-aged objectives (five million to 24 million years) and older and deeper Lower Tertiary objectives. We hold federal leases comprising approximately 1.2 million net acres in our deepwater exploration inventory.
 
In 2006, various drilling and testing operations provided evidence that our Lower Tertiary properties may be a source of meaningful reserve and production growth in the future. Prior to 2006, we had drilled three discovery wells in the Lower Tertiary. These include Cascade in 2002 (see “Deepwater Development” above), St. Malo in 2003 and Jack in 2004. Operations in 2006 included a successful production test of the Jack No. 2 well and participation in the Kaskida discovery, which is our fourth Lower Tertiary discovery. We currently hold 273 blocks in the Lower Tertiary and have identified 19 additional prospects to date.
 
At St. Malo, in which our working interest is 22.5%, we plan to drill a second delineation well in late 2007 or early 2008. At Jack, where our working interest is 25%, we continue to evaluate with our partners our development options following the successful production test in 2006.
 
In addition to the 2006 Kaskida discovery, a subsequent sidetrack well at Kaskida was drilled in 2006 and another well operation is planned for 2007. Our working interest in Kaskida is 20%, and we believe Kaskida is the largest of our four Lower Tertiary discoveries to date. The Kaskida discovery was our first in the Keathley Canyon deepwater lease area. Twelve of the 19 additional Lower Tertiary exploratory prospects we have identified to date are on our Keathley Canyon acreage.
 
Also in 2006, we participated in a Miocene discovery on the Mission Deep prospect in which we have a 50% working interest. We have fifteen additional prospects in our deepwater Miocene inventory.
 
In total, we drilled three exploratory and delineation wells in the deepwater Gulf of Mexico in 2006, and plan to drill six such wells in 2007. Our working interests in these exploratory opportunities range from 20% to 100%.
 
Canada
 
Jackfish — We are currently developing our 100%-owned Jackfish thermal heavy oil project in the non-conventional oil sands of east central Alberta. We will employ steam-assisted gravity drainage at Jackfish, and we expect to begin steam injection in the second quarter of 2007. Production is expected to eventually reach 35,000 barrels per day by the end of 2008 We drilled 19 pairs of producing and steam-injection wells in 2006, bringing the total number of well-pairs to 24. We hold approximately 80,000 net acres in the entire Jackfish area, which can support expansion of the original project. We requested regulatory approval in late September 2006 to increase the scope and size of the original project. We expect to decide in 2007 whether to proceed with this expansion, which could eventually add an additional 35,000 barrels per day of production.
 
Deep Basin  — Our properties in Canada’s Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 646,000 net acres in the Deep Basin. The area produces primarily natural gas and natural gas liquids from conventional reservoirs. Our average working interest in the


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Deep Basin is 46%. We drilled 115 gross wells in the Deep Basin in 2006 and plan to drill 57 gross wells in the area in 2007.
 
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 2.1 million net acres and have a 97% average working interest in our Lloydminster properties. In 2006, we drilled 397 gross wells in the area and plan to drill 395 gross wells in 2007.
 
Peace River Arch — The Peace River Arch is located in west central Alberta. We hold approximately 476,000 net acres in the area, which produces primarily natural gas and natural gas liquids from conventional reservoirs. Our average working interest in the area is about 69%. We drilled 82 gross wells in the Peace River Arch in 2006, and we expect to drill 62 additional wells here in 2007.
 
Northeast British Columbia — Our Northeast British Columbia properties are located primarily in British Columbia and to a lesser extent in north western Alberta. We hold approximately 1.2 million net acres in the area. These properties produce principally natural gas from conventional reservoirs. We hold a 72% average working interest in these properties. We drilled 64 gross wells in the area in 2006, and we plan to drill 68 wells here in 2007.
 
International
 
Azerbaijan — Outside North America, Devon’s largest international property in terms of proved reserves is the Azeri-Chirag-Gunashli (“ACG”) oil field located offshore Azerbaijan in the Caspian Sea. Our production from ACG increased significantly in late 2006 following the payout of carried interest agreements with various partners in the field. Our production will increase again in 2007 as we benefit from a full year of the higher ownership interest after these payouts. We expect our share of ACG production in 2007 to total approximately 12 MMBoe. ACG produces crude oil from conventional reservoirs. We hold approximately 6,000 net acres in the ACG field and have a 5.6% working interest. In 2006, we participated in drilling 15 gross wells at ACG and expect to drill 13 gross wells in 2007.
 
China — Our production in China is from the Panyu field in the Pearl River Mouth Basin in the South China Sea. Panyu produces oil from conventional reservoirs. In addition to Panyu, which is located on block 15/34, we also hold leases in two exploratory blocks offshore China. In total, we have 4.4 million net acres under lease in China. We have a 24.5% working interest at Panyu and 100% working interests in the exploratory blocks. We drilled six gross wells in China in 2006, all in the Panyu field. In 2007, we expect to drill seven gross wells in the Panyu field.
 
Brazil — We expect to commence oil production in Brazil in 2007 from our Polvo field. Polvo, which we operate with a 60% interest, is located offshore in block BM-C-8. In addition to our development project at Polvo, we also hold acreage in nine exploratory blocks. In aggregate, we have 835,000 net acres in Brazil. Our working interests range from 18% to 100% in these blocks. We drilled three gross wells in Brazil in 2006 and plan to drill 11 gross wells in Brazil in 2007.
 
Equatorial Guinea — All of our oil production from the West African country of Equatorial Guinea is from the offshore Zafiro field in the Gulf of Guinea. Zafiro is located on block B, and we also have interests in three additional exploratory blocks. We hold 518,000 net acres in the four blocks combined. Zafiro produces crude oil from conventional reservoirs. Our working interests (participating interests under the terms of the production sharing contracts) range from 24% to 38% in the four blocks. In 2006, we drilled 10 gross wells in Equatorial Guinea, all in the Zafiro field. In 2007, we plan to drill 10 gross wells in Equatorial Guinea. Equatorial Guinea is included in the West African assets we intend to sell during 2007.
 
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, generally including 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
 
Royalty Matters
 
Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. On February 1, 2006, the Court entered a scheduling order in which trial is set for November 2007. We believe we have acted reasonably, have legitimate and strong defenses to all allegations in the suit, and have paid royalties in good faith. We do not currently believe that we are subject to material exposure in association with this lawsuit and no related liability has been recorded in our consolidated financial statements.
 
Equatorial Guinea Investigation
 
The SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, we received a subpoena issued by the SEC pursuant to a formal order of investigation. We have cooperated fully with the SEC’s requests for information in this inquiry. After responding in 2005 to such requests for information, we have not been contacted by the SEC. In the event that we receive any further inquiries, we will work with the SEC in connection with its investigation.
 
Other Matters
 
We are involved in other various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no other 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 2006.


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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, 2007, there were 16,228 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 and dividends paid per share.
 
                         
    Price Range of Common
       
    Stock     Dividends
 
    High     Low     per Share  
 
2005:
                       
Quarter Ended March 31, 2005
  $ 49.42       36.48       0.0750  
Quarter Ended June 30, 2005
  $ 52.31       40.60       0.0750  
Quarter Ended September 30, 2005
  $ 70.35       50.75       0.0750  
Quarter Ended December 31, 2005
  $ 69.79       54.01       0.0750  
2006:
                       
Quarter Ended March 31, 2006
  $ 69.97       55.31       0.1125  
Quarter Ended June 30, 2006
  $ 65.25       48.94       0.1125  
Quarter Ended September 30, 2006
  $ 74.65       57.19       0.1125  
Quarter Ended December 31, 2006
  $ 74.48       58.55       0.1125  
 
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.
 
Issuer Purchases of Equity Securities
 
On August 3, 2005, we announced that our Board of Directors had authorized the repurchase of up to 50 million shares of our common stock. As of the end of the fourth quarter of 2006, 43.5 million shares remain available for purchase under this program. We suspended this stock repurchase program during the second quarter of 2006 in conjunction with our acquisition of Chief. In conjunction with the sales of our Egyptian and West African assets in 2007, we expect to resume this program in late 2007 by using a portion of the sale proceeds to repurchase common stock. Although this program expires at the end of 2007, it could be extended if necessary.


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Item 6.   Selected Financial Data
 
The following selected financial information (not covered by the report of 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,  
    2006     2005     2004     2003     2002  
    (In millions, except per share data, ratios, prices and per Boe amounts)  
 
Operating Results
                                       
Total revenues
  $ 10,578       10,622       9,086       7,309       4,316  
Total expenses and other income, net
    6,566       6,117       5,810       5,020       4,450  
                                         
Earnings (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle
    4,012       4,505       3,276       2,289       (134 )
Total income tax expense (benefit)
    1,189       1,606       1,095       527       (193 )
                                         
Earnings from continuing operations before cumulative effect of change in accounting principle
    2,823       2,899       2,181       1,762       59  
Earnings (loss) from discontinued operations
    23       31       5       (31 )     45  
                                         
Earnings before cumulative effect of change in accounting principle
    2,846       2,930       2,186       1,731       104  
Cumulative effect of change in accounting principle, net of tax
                      16        
                                         
Net earnings
  $ 2,846       2,930       2,186       1,747       104  
                                         
Net earnings applicable to common stockholders
  $ 2,836       2,920       2,176       1,737       94  
                                         
Basic net earnings per share:
                                       
Earnings from continuing operations
  $ 6.37       6.31       4.50       4.19       0.16  
Earnings (loss) from discontinued operations
    0.05       0.07       0.01       (0.07 )     0.15  
Cumulative effect of change in accounting principle
                      0.04        
                                         
Net earnings
  $ 6.42       6.38       4.51       4.16       0.31  
                                         
Diluted net earnings per share:
                                       
Earnings from continuing operations
  $ 6.29       6.19       4.37       4.07       0.16  
Earnings (loss) from discontinued operations
  $ 0.05       0.07       0.01       (0.07 )     0.14  
Cumulative effect of change in accounting principle
                      0.04        
                                         
Net earnings
  $ 6.34       6.26       4.38       4.04       0.30  
                                         


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    Year Ended December 31,  
    2006     2005     2004     2003     2002  
    (In millions, except per share data, ratios, prices and per Boe amounts)  
 
Cash dividends per common share
  $ 0.45       0.30       0.20       0.10       0.10  
Weighted average common shares outstanding — Basic
    442       458       482       417       309  
Weighted average common shares outstanding — Diluted
    448       470       499       433       313  
Ratio of earnings to fixed charges(1)
    8.63       8.24       6.70       4.95       N/A  
Ratio of earnings to combined fixed charges and preferred stock dividends(1)
    8.38       8.04       6.53       4.82       N/A  
Cash Flow Data
                                       
Net cash provided by operating activities
  $ 5,993       5,612       4,816       3,768       1,754  
Net cash used in investing activities
  $ (7,449 )     (1,652 )     (3,634 )     (2,773 )     (2,046 )
Net cash provided by (used in) financing activities
  $ 593       (3,543 )     (1,001 )     (414 )     401  
Production, Price and Other Data(2)
                                       
Production:
                                       
Oil (MMBbls)
    55       62       74       60       42  
Gas (Bcf)
    815       827       891       863       761  
NGLs (MMBbls)
    23       24       24       22       19  
MMBoe(3)
    214       224       247       226       188  
Average prices:
                                       
Oil (Per Bbl)
  $ 58.30       38.00       28.22       25.82       21.71  
Gas (Per Mcf)
  $ 6.06       6.99       5.32       4.51       2.80  
NGLs (Per Bbl)
  $ 32.10       28.96       23.04       18.65       14.05  
Per Boe(3)
  $ 41.51       39.48       29.92       25.93       17.61  
Production and operating expenses per Boe(3)
  $ 8.54       7.42       6.13       5.65       4.71  
Depreciation, depletion and amortization of oil and gas properties per Boe(3)
  $ 10.59       8.86       8.41       7.25       5.88  
 
                                         
    December 31,  
    2006     2005     2004     2003     2002  
    (In millions)  
 
Balance Sheet Data
                                       
Total assets
  $ 35,063       30,273       30,025       27,162       16,225  
Long-term debt
  $ 5,568       5,957       7,031       8,580       7,562  
Stockholders’ equity
  $ 17,442       14,862       13,674       11,056       4,653  
 
 
(1) 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, dividends on subsidiary’s preferred stock, distributions on preferred securities of subsidiary trust, amortization of costs relating to indebtedness and the preferred securities of subsidiary trust, 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 outstanding preferred stock. For the year 2002, earnings were insufficient to cover fixed charges by $135 million, and were insufficient to cover combined fixed charges and preferred stock dividends by $151 million.

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(2) The amounts presented under “Production, Price and Other Data” exclude the amounts related to discontinued operations in Egypt. The price data presented includes the effect of derivative financial instruments and fixed-price physical delivery contracts.
 
(3) 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 natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas 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. Reference is made to “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data.” Our discussion and analysis will relate to the following subjects:
 
  •  Overview of Business
 
  •  Overview of 2006 Results and Outlook
 
  •  Results of Operations
 
  •  Capital Resources, Uses and Liquidity
 
  •  Contingencies and Legal Matters
 
  •  Critical Accounting Policies and Estimates
 
  •  Recently Issued Accounting Standards Not Yet Adopted
 
  •  2007 Estimates
 
Overview of Business
 
Devon is one of the largest U.S. based independent oil and gas producers and processors of natural gas and natural gas liquids in North America. Our portfolio of oil and gas properties provides stable production and a platform for future growth. About 90 percent of our production is from North America. We also operate in selected international areas, including Azerbaijan, Brazil and China. Our production mix is about 65 percent natural gas and 35 percent oil and natural gas liquids such as propane, butane and ethane. We are currently producing about 2.3 billion cubic feet of natural gas each day, or about 3 percent of all the gas consumed in North America.
 
In managing our global operations, we have an operating strategy that is focused on creating and increasing value per share. Key elements of this strategy are replacing oil and gas reserves, growing production and exercising capital discipline. We must also control operating costs and manage commodity pricing risks to achieve long-term success. The discussion and analysis of our results of operations and other related information will refer to these factors.
 
  •  Oil and gas reserve replacement — Our financial condition and profitability are significantly affected by the amount of proved reserves we own. Oil and gas properties are our most significant asset, and the reserves that relate to such properties are key to our future success. To increase our proved reserves, we must replace reserves that have been produced with additional reserves from successful exploration and development activities or property acquisitions.
 
  •  Production growth — Our profitability and operating cash flows are largely dependent on the amount of oil, gas and NGLs we produce. Furthermore, growing production from existing properties is difficult because the rate of production from oil and gas properties generally declines as reserves are depleted.


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  As a result, we constantly drill for new proved reserves and develop proved undeveloped 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. Therefore, maintaining a disciplined approach to investing in capital projects is important to our profitability and financial condition. Also, 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. Approximately 82% of our planned 2007 investment in capital projects is dedicated to a foundation of low-risk projects primarily in North America. The remainder of our capital is invested in high-impact projects primarily in the Gulf of Mexico, Brazil and China. 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.
 
  •  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 when commodity prices rise significantly. Our base North American production is focused in core areas of our operations where we can achieve economies of scale to assist our management of operating costs.
 
  •  Commodity pricing risks — Our profitability is highly dependent on the prices of oil, natural gas and NGLs. Prices for oil, gas and NGLs 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 in the past, we have utilized financial hedging arrangements and fixed-price contracts on a portion of our production and may use such instruments in the future.
 
Overview of 2006 Results and Outlook
 
2006 was one of the best years in Devon’s history. We achieved key operational successes and continued to execute our strategy to increase value per share. As a result, we delivered record amounts for earnings per share and operating cash flow and grew proved reserves to a new all-time high. Key measures of our financial and operating performance for 2006, as well as certain operational developments, are summarized below:
 
  •  Net earnings declined 3% from $2.9 billion to $2.8 billion
 
  •  Diluted net earnings per share increased 1% to $6.34 per diluted share
 
  •  Net cash provided by operating activities reached $6.0 billion
 
  •  Estimated proved reserves at December 31, 2006 reached a record amount of 2.4 billion Boe
 
  •  Estimated proved reserves increased 533 million Boe through drilling, extensions, performance revisions and acquisitions
 
  •  Capital expenditures for oil and gas exploration and development activities were $7.7 billion, including the $2.2 billion acquisition of Chief
 
  •  Combined realized price for oil, gas and NGLs per Boe increased 5% to $41.51
 
  •  Marketing and midstream margin remained flat at $448 million for 2006
 
We produced 214 million Boe in 2006, representing a 4% decrease compared to 2005. Excluding the effects of production lost due to the sale of non-core properties in the first half of 2005, our year-over-year production remained constant. Operating costs increased due to inflationary pressure driven by the effects of


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higher commodity prices and due to the weakened U.S. dollar compared to the Canadian dollar. Per unit lease operating expenses increased 17% to $6.95 per Boe.
 
During 2006, we utilized cash on hand, cash flow from operations, and $1.8 billion of commercial paper borrowings to fund our capital expenditures, repay $862 million in debt and repurchase $253 million of our common stock. We ended the year with $1.3 billion of cash and short-term investments.
 
From an operational perspective, our deepwater Gulf of Mexico exploration program has reached several important milestones related to the Lower Tertiary trend. To date, we have drilled four discovery wells in the Lower Tertiary — Cascade in 2002, St. Malo in 2003, Jack in 2004 and Kaskida in the third quarter of 2006. Also in the third quarter of 2006, we announced the successful production test of the Jack No. 2 well in the Lower Tertiary. We currently hold 273 blocks in the Lower Tertiary and have identified 19 additional exploratory prospects within these blocks to date. These achievements support our positive view of the Lower Tertiary and demonstrate the growth potential of our high-impact exploration strategy on long-term production, reserves and value.
 
On June 29, 2006, we acquired Chief’s oil and gas assets located in the Barnett Shale area of Texas for $2.2 billion. This transaction added 99.7 million Boe of proved reserves and 169,000 net acres to our Barnett Shale assets. This acquisition combined with our organic growth continues to extend our leadership position in the Barnett Shale and provides years of additional drilling inventory.
 
On November 14, 2006, we announced our plans to divest our operations in Egypt. At December 31, 2006, Egypt had proved reserves of eight million Boe. Subsequently, on January 23, 2007, we announced our plans to divest our operations in West Africa, including Equatorial Guinea, Cote d’Ivoire, and other countries in the region. At December 31, 2006, our West Africa operations had proved reserves of 90 million Boe, or 4% of total proved reserves. We anticipate completing the sale of our Egyptian assets in the first half of 2007 and our West African assets in the third quarter of 2007. Divesting these properties will allow us to redeploy our financial and intellectual capital to the significant growth opportunities we have developed onshore in North America and in the deepwater Gulf of Mexico. Additionally, we will sharpen our focus in North America and concentrate our international operations in Brazil and China, where we have established competitive advantages.
 
Looking to 2007, we intend to use the proceeds from the sales of our operations in Egypt and West Africa to repay our outstanding commercial paper and resume common stock repurchases. In addition, our operational accomplishments to date have laid the foundation for continued growth in future years, at competitive unit costs, that we expect will continue to create additional value for our investors. In 2007, we expect to deliver reserve additions of 350 to 370 million Boe with related capital expenditures in the range of $5.3 to $5.7 billion. We expect production related to our continuing operations to increase approximately 10% from 2006 to 2007, which reflects the significant reserve additions in 2005 and 2006, and those expected in 2007.


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Results of Operations
 
Revenues
 
Changes in oil, gas and NGL production, prices and revenues from 2004 to 2006 are shown in the following tables. The amounts for all periods presented exclude our Egyptian operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
 
                                         
    Total  
    Year Ended December 31,  
          2006 vs
          2005 vs
       
    2006     2005(2)     2005     2004(2)     2004  
 
Production
                                       
Oil (MMBbls)
    55       −11 %     62       −17 %     74  
Gas (Bcf)
    815       −1 %     827       −7 %     891  
NGLs (MMBbls)
    23       −2 %     24       −1 %     24  
Oil, gas and NGLs (MMBoe)(1)
    214       −4 %     224       −9 %     247  
Average Prices
                                       
Oil (per Bbl)
  $ 58.30       +53 %     38.00       +35 %     28.22  
Gas (per Mcf)
  $ 6.06       −13 %     6.99       +32 %     5.32  
NGLs (per Bbl)
  $ 32.10       +11 %     28.96       +26 %     23.04  
Oil, gas and NGLs (per Boe)(1)
  $ 41.51       +5 %     39.48       +32 %     29.92  
Revenues ($ in millions)
                                       
Oil
  $ 3,205       +36 %     2,359       +12 %     2,099  
Gas
    4,932       −15 %     5,784       +22 %     4,732  
NGLs
    749       +9 %     687       +24 %     554  
                                         
Oil, gas and NGLs
  $ 8,886       +1 %     8,830       +20 %     7,385  
                                         
 
                                         
    Domestic  
    Year Ended December 31,  
          2006 vs
          2005 vs
       
    2006     2005(2)     2005     2004(2)     2004  
 
Production
                                       
Oil (MMBbls)
    19       −23 %     25       −19 %     31  
Gas (Bcf)
    566       +2 %     555       −8 %     602  
NGLs (MMBbls)
    19       +3 %     18       −4 %     19  
Oil, gas and NGLs (MMBoe)(1)
    132       −3 %     136       −10 %     151  
Average Prices
                                       
Oil (per Bbl)
  $ 62.23       +49 %     41.64       +35 %     30.84  
Gas (per Mcf)
  $ 6.09       −14 %     7.08       +30 %     5.43  
NGLs (per Bbl)
  $ 29.42       +10 %     26.68       +24 %     21.47  
Oil, gas and NGLs (per Boe)(1)
  $ 39.31       −2 %     40.21       +31 %     30.80  
Revenues ($ in millions)
                                       
Oil
  $ 1,218       +15 %     1,062       +9 %     976  
Gas
    3,445       −12 %     3,929       +20 %     3,261  
NGLs
    548       +13 %     484       +19 %     405  
                                         
Oil, gas and NGLs
  $ 5,211       −5 %     5,475       +18 %     4,642  
                                         
 


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    Canada  
    Year Ended December 31,  
          2006 vs
          2005 vs
       
    2006     2005(2)     2005     2004(2)     2004  
 
Production
                                       
Oil (MMBbls)
    13       −2 %     13       −5 %     14  
Gas (Bcf)
    241       −8 %     261       −6 %     279  
NGLs (MMBbls)
    4       −11 %     6       +8 %     5  
Oil, gas and NGLs (MMBoe)(1)
    58       −7 %     62       −5 %     65  
Average Prices
                                       
Oil (per Bbl)
  $ 46.94       +75 %     26.88       +24 %     21.60  
Gas (per Mcf)
  $ 6.05       −13 %     6.95       +35 %     5.15  
NGLs (per Bbl)
  $ 42.67       +15 %     37.19       +27 %     29.23  
Oil, gas and NGLs (per Boe)(1)
  $ 39.21       +3 %     38.17       +33 %     28.80  
Revenues ($ in millions)
                                       
Oil
  $ 603       +71 %     353       +18 %     299  
Gas
    1,456       −20 %     1,814       +26 %     1,437  
NGLs
    201       +2 %     196       +38 %     143  
                                         
Oil, gas and NGLs
  $ 2,260       −4 %     2,363       +26 %     1,879  
                                         
 
                                         
    International  
    Year Ended December 31,  
          2006 vs
          2005 vs
       
    2006     2005(2)     2005     2004(2)     2004  
 
Production
                                       
Oil (MMBbls)
    23       −4 %     24       −19 %     29  
Gas (Bcf)
    8       −25 %     11       +6 %     10  
NGLs (MMBbls)
          N/M             N/M        
Oil, gas and NGLs (MMBoe)(1)
    24       −7 %     26       −17 %     31  
Average Prices
                                       
Oil (per Bbl)
  $ 61.36       +52 %     40.26       +41 %     28.53  
Gas (per Mcf)
  $ 3.95       +5 %     3.75       +13 %     3.33  
NGLs (per Bbl)
  $       N/M       22.81       +8 %     21.12  
Oil, gas and NGLs (per Boe)(1)
  $ 59.24       +53 %     38.80       +39 %     27.99  
Revenues ($ in millions)
                                       
Oil
  $ 1,384       +47 %     944       +15 %     824  
Gas
    31       −21 %     41       +20 %     34  
NGLs
          N/M       7       +12 %     6  
                                         
Oil, gas and NGLs
  $ 1,415       +43 %     992       +15 %     864  
                                         
 
 
(1) Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas 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 this table.
 
N/M Not meaningful.

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The average prices shown in the preceding tables include the effect of our oil and gas price hedging activities. Following is a comparison of our average prices with and without the effect of hedges for each of the last three years.
 
                                                 
    With Hedges     Without Hedges  
    2006     2005     2004     2006     2005     2004  
 
Oil (per Bbl)
  $ 58.30       38.00       28.22       58.30       48.43       36.02  
Gas (per Mcf)
  $ 6.06       6.99       5.32       6.01       7.04       5.34  
NGLs (per Bbl)
  $ 32.10       28.96       23.04       32.10       28.96       23.04  
Oil, gas and NGLs (per Boe)
  $ 41.51       39.48       29.92       41.34       42.55       32.37  
 
The following table details the effects of changes in volumes and prices on our oil, gas and NGL revenues between 2004 and 2006.
 
                                 
    Oil     Gas     NGL     Total  
    (In millions)  
 
2004 revenues
  $ 2,099       4,732       554       7,385  
Changes due to volumes
    (347 )     (337 )     (8 )     (692 )
Changes due to prices
    607       1,389       141       2,137  
                                 
2005 revenues
    2,359       5,784       687       8,830  
Changes due to volumes
    (270 )     (86 )     (11 )     (367 )
Changes due to prices
    1,116       (766 )     73       423  
                                 
2006 revenues
  $ 3,205       4,932       749       8,886  
                                 
 
Oil Revenues
 
2006 vs. 2005 Oil revenues decreased $270 million due to a seven million barrel decrease in production. Production lost from properties divested in 2005 accounted for four million barrels of the decrease. A contractual reduction of our share of production from one of our international properties in mid-2005 also lowered 2006 volumes. These decreases were partially offset by a three million barrel increase in production resulting from reaching payout of certain carried interests in Azerbaijan.
 
Oil revenues increased $1.1 billion as a result of a 53% increase in our realized price. The expiration of oil hedges at the end of 2005 and a 17% increase in the average NYMEX West Texas Intermediate index price caused the increase in our realized oil price.
 
2005 vs. 2004 Oil revenues decreased $347 million due to a 12 million barrel decrease in production. Production lost from the 2005 property divestitures accounted for seven million barrels of the decrease. We also suspended certain domestic production in 2005 and 2004 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The volumes suspended in 2005 were one million barrels more than in 2004. The remainder of the decrease is due to certain international properties in which our ownership interest decreased after we recovered our costs under the applicable production sharing contracts.
 
Higher realized prices caused oil revenues to increase $607 million in 2005. Our 2005 oil prices rose primarily due to a 37% increase in the average NYMEX West Texas Intermediate index price.
 
Gas Revenues
 
2006 vs. 2005 A 12 Bcf decrease in production caused gas revenues to decrease by $86 million. Production lost from the 2005 property divestitures caused a decrease of 35 Bcf. As a result of the previously mentioned hurricanes, gas volumes suspended in 2006 were three Bcf more than those suspended in 2005. These decreases were partially offset by the June 2006 Chief acquisition, which contributed 10 Bcf of production during the last half of 2006, and additional production from new drilling and development in our U.S. onshore and offshore properties.


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A 13% decline in average prices caused gas revenues to decrease $766 million in 2006.
 
2005 vs. 2004 A 64 Bcf decrease in production caused gas revenues to decrease by $337 million. Production associated with the 2005 property divestitures caused a decrease of 89 Bcf. We also suspended certain domestic gas production in 2005 and 2004 due to the previously mentioned hurricanes. The volumes suspended in 2005 were 12 Bcf more than in 2004. These decreases were partially offset by new drilling and development and increased performance in U.S. onshore and offshore properties.
 
A 32% increase in average gas prices contributed $1.4 billion of additional revenues in 2005.
 
Marketing and Midstream Revenues and Operating Costs and Expenses
 
The following table details the changes in our marketing and midstream revenues and operating costs and expenses between 2004 and 2006. The changes due to prices in the table represent the net effect on both revenues and expenses due to changes in the market prices for natural gas and NGLs.
 
                 
    Revenues     Expenses  
    (In millions)  
 
2004 marketing & midstream
  $ 1,701       1,339  
Changes due to volumes
    (351 )     (303 )
Changes due to prices
    442       306  
                 
2005 marketing & midstream
    1,792       1,342  
Changes due to volumes
    159       117  
Changes due to prices
    (259 )     (215 )
                 
2006 marketing & midstream
  $ 1,692       1,244  
                 
 
2006 vs. 2005 Volume increases in our gas pipeline, gas sales and NGL marketing activities caused both revenues and expenses to increase in 2006. This additional activity was primarily due to our continued growth in the Barnett Shale and higher natural gas deliveries from third-party producers.
 
2005 vs. 2004 Volume decreases in 2005 caused both revenues and expenses to decline in 2005. The lower activity was primarily attributable to the sale of certain non-core assets in 2004 and 2005.
 
Oil, Gas and NGL Production and Operating Expenses
 
The details of the changes in oil, gas and NGL production and operating expenses between 2004 and 2006 are shown in the table below.
 
                                         
    Year Ended December 31,  
          2006 vs
          2005 vs
       
    2006     2005(1)     2005     2004(1)     2004  
 
Production and operating expenses ($ in millions):
                                       
Lease operating expenses
  $ 1,488       +12 %     1,324       + 5 %     1,259  
Production taxes
    341       + 2 %     335       +31 %     255  
                                         
Total production and operating expenses
  $ 1,829       +10 %     1,659       +10 %     1,514  
                                         
Production and operating expenses per Boe:
                                       
Lease operating expenses
  $ 6.95       +17 %     5.92       +16 %     5.10  
Production taxes
    1.59       + 6 %     1.50       +46 %     1.03  
                                         
Total production and operating expenses per Boe
  $ 8.54       +15 %     7.42       +21 %     6.13  
                                         
 
 
(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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2006 vs. 2005 Lease operating expenses increased $164 million in 2006 largely due to higher commodity prices. Commodity price increases in 2005 and the first half of 2006 contributed to industry-wide inflationary pressures on materials and personnel costs. Additionally, consideration of higher commodity prices contributed to our decision to perform more well workovers and maintenance projects to maintain or improve production volumes. Commodity price increases also caused operating costs such as ad valorem taxes, power and fuel costs to rise.
 
A higher Canadian-to-U.S. dollar exchange rate in 2006 caused a $34 million increase in our costs. Lease operating expenses also increased $33 million due to the June 2006 Chief acquisition and the payouts of our carried interests in Azerbaijan in the last half of 2006. The increases in our lease operating expenses were partially offset by a decrease of $82 million related to properties that were sold in 2005.
 
The factors described above were also the primary factors causing lease operating expenses per Boe to increase during 2006. Although we divested properties in 2005 that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar had a greater effect on our per unit costs than the property divestitures.
 
2005 vs. 2004 Lease operating expenses increased $65 million in 2005 largely due to higher commodity prices. As addressed above, commodity price increases led to overall industry inflation. Additionally, a higher Canadian-to-U.S. dollar exchange rate in 2005 caused a $30 million increase in 2005. Partially offsetting these increases was a decrease of $144 million in lease operating expenses related to properties that were sold in 2005.
 
The increases described above were also the primary factors causing lease operating expenses per Boe to increase. Although we divested properties that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar had a greater effect on our per unit costs than the property divestitures.
 
The following table details the changes in production taxes between 2004 and 2006. The majority of our production taxes are assessed on our onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the changes due to revenues in the table primarily relate to changes in oil, gas and NGL revenues from our U.S. onshore properties.
 
         
    (In millions)  
 
2004 production taxes
  $ 255  
Change due to revenues
    50  
Change due to rate
    30  
         
2005 production taxes
    335  
Change due to revenues
    (23 )
Change due to rate
    29  
         
2006 production taxes
  $ 341  
         
 
2006 vs. 2005 Production taxes increased $29 million due to an increase in the effective production tax rate in 2006. A new Chinese “Special Petroleum Gain” tax was the primary contributor to the higher rate.
 
2005 vs. 2004 Production taxes increased $30 million due to an increase in the effective production tax rate in 2005. An increase in Russian export tax rates was the primary contributor to the higher rate.
 
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 the net capitalized investment plus future development costs in those reserves. Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by


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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 following table details the changes in DD&A of oil and gas properties between 2004 and 2006. The changes due to volumes in the table represent the effect on DD&A due to decreases in combined oil, gas and NGL production.
 
         
    (In millions)  
 
2004 DD&A
  $ 2,077  
Change due to volumes
    (195 )
Change due to rate
    99  
         
2005 DD&A
    1,981  
Change due to volumes
    (85 )
Change due to rate
    370  
         
2006 DD&A
  $ 2,266  
         
 
2006 vs. 2005 Oil and gas property related DD&A increased $370 million in 2006 due to an increase in the DD&A rate from $8.86 per Boe in 2005 to $10.59 per Boe in 2006. The largest contributor to the rate increase was inflationary pressure on both the costs incurred during 2006 as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase include the June 2006 Chief acquisition and the transfer of previously unproved costs to the depletable base as a result of 2006 drilling activities. A reduction in reserve estimates due to the effects of 2006 year-end commodity prices also contributed to the rate increase.
 
2005 vs. 2004 Oil and gas property related DD&A increased $99 million in 2005 due to an increase in the DD&A rate from $8.41 per Boe in 2004 to $8.86 per Boe in 2005. The largest contributor to the rate increase was the effect of inflationary pressure on finding and development costs for reserve discoveries and extensions. Changes in the Canadian-to-U.S. dollar exchange rate also caused the rate to increase. These increases were partially offset by a decrease in the rate as a result of our 2005 property divestitures.
 
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 reduced by two offsetting 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 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,  
          2006 vs
          2005 vs
       
    2006     2005     2005     2004     2004  
    ($ in millions)  
 
Gross G&A
  $ 769       +33 %     577       +6 %     545  
Capitalized G&A
    (269 )     +49 %     (181 )     +9 %     (166 )
Reimbursed G&A
    (103 )     −2 %     (105 )     +3 %     (102 )
                                         
Net G&A
  $ 397       +36 %     291       +5 %     277  
                                         


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2006 vs. 2005 Gross G&A increased $192 million. Higher employee compensation and benefits costs caused gross G&A to increase $149 million. Of this increase, $34 million represented stock option expense recognized pursuant to our adoption in 2006 of Statement of Financial Accounting Standard No. 123(R), Share-Based Payment. An additional $28 million of the increase related to higher restricted stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $11 million increase in costs.
 
2005 vs. 2004 Gross G&A increased $32 million. Higher employee compensation and benefits costs caused gross G&A to increase $35 million. Of this increase, $17 million related to higher restricted stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $9 million increase in costs. These increases were partially offset by an $8 million decrease in rent expense resulting primarily from the abandonment of certain Canadian office space in 2004.
 
The factors discussed above were also the primary factors that caused the $88 million and $15 million increases in capitalized G&A in 2006 and 2005, respectively.
 
Interest Expense
 
The following schedule includes the components of interest expense between 2004 and 2006.
 
                         
    Year Ended December 31,  
    2006     2005     2004  
    (In millions)  
 
Interest based on debt outstanding
  $ 486       507       513  
Capitalized interest
    (79 )     (70 )     (70 )
Other interest
    14       96       32  
                         
Total interest expense
  $ 421       533       475  
                         
 
Interest based on debt outstanding decreased from 2004 to 2006 primarily due to the net effect of debt repayments during 2005 and 2006. This was partially offset by the effect of increased commercial paper borrowings during the last half of 2006 related to the acquisition of the Chief properties.
 
During 2005, we redeemed our $400 million 6.75% notes due March 15, 2011 and our zero coupon convertible senior debentures prior to their scheduled maturity dates. The other interest category in the table above includes $81 million in 2005 related to these early retirements.
 
During 2004, we repaid the balance under our $3 billion term loan credit facility prior to the scheduled repayment date. The other interest category in the table above includes $16 million in 2004 related to this early repayment.
 
Reduction of Carrying Value of Oil and Gas Properties
 
During 2006 and 2005, we reduced the carrying value of certain of our oil and gas properties due to full cost ceiling limitations and unsuccessful exploratory activities. A detailed description of how full cost ceiling limitations are determined is included in the “Critical Accounting Policies and Estimates” section of this report. A summary of these reductions and additional discussion is provided below.
 


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    Year Ended December 31,  
    2006     2005  
          Net of
          Net of
 
    Gross     Taxes     Gross     Taxes  
    (In millions)  
 
Unsuccessful exploratory reductions:
                               
Nigeria
  $ 85       85              
Brazil
    16       16       42       42  
Angola
                170       119  
Ceiling test reduction — Russia
    20       10              
                                 
Total
  $ 121       111       212       161  
                                 
 
2006 Reductions
 
We have committed to drill four wells in Nigeria. The first two wells were unsuccessful. After drilling the second unsuccessful well in the first quarter of 2006, we determined that the capitalized costs related to these two wells should be impaired. Therefore, in the first quarter of 2006, we recognized an $85 million impairment of our investment in Nigeria equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There was no tax benefit related to this impairment.
 
During the second quarter of 2006, we drilled two unsuccessful exploratory wells in Brazil and determined that the capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, we recognized a $16 million impairment of our investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There was no tax benefit related to this impairment. The two wells were unrelated to Devon’s Polvo development project in Brazil.
 
As a result of a decline in projected future net cash flows, the carrying value of our Russian properties exceeded the full cost ceiling by $10 million at the end of the third quarter of 2006. Therefore, we recognized a $20 million reduction of the carrying value of our oil and gas properties in Russia, offset by a $10 million deferred income tax benefit.
 
2005 Reductions
 
Our interests in Angola were acquired through the 2003 Ocean Energy merger. Our Angolan drilling program discovered no proven reserves. After drilling three unsuccessful wells in the fourth quarter of 2005, we determined that all of the Angolan capitalized costs should be impaired.
 
Prior to the fourth quarter of 2005, we were capitalizing the costs of previous unsuccessful efforts in Brazil pending the determination of whether proved reserves would be recorded in Brazil. We have been successful in our drilling efforts on block BM-C-8 in Brazil and are currently developing the Polvo project on this block. The ultimate value of the Polvo project is expected to be in excess of the sum of its related costs, plus the costs of the previous unrelated unsuccessful efforts in Brazil which were capitalized. However, the Polvo proved reserves will be recorded over a period of time. At the end of 2005, it was expected that a small initial portion of the proved reserves ultimately expected at Polvo would be recorded in 2006. Based on preliminary estimates developed in the fourth quarter of 2005, the value of this initial partial booking of proved reserves was not sufficient to offset the sum of the related proportionate Polvo costs plus the costs of the previous unrelated unsuccessful efforts. Therefore, we determined that the prior unsuccessful costs unrelated to the Polvo project should be impaired. These costs totaled approximately $42 million. There was no tax benefit related to this Brazilian impairment.

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Change in Fair Value of Derivative Financial Instruments
 
The details of the changes in fair value of derivative financial instruments between 2004 and 2006 are shown in the table below.
 
                         
    2006     2005     2004  
    (In millions)  
 
Option embedded in exchangeable debentures
  $ 181       54       58  
Non-qualifying commodity hedges
          39        
Ineffectiveness of commodity hedges
          5       5  
Interest rate swaps
    (3 )     (4 )     (1 )
                         
Total
  $ 178       94       62  
                         
 
The change in the fair value of the embedded option relates to the debentures exchangeable into shares of Chevron Corporation common stock. These expenses were caused primarily by increases in the price of Chevron Corporation’s common stock.
 
In 2005, we recognized a $39 million loss on certain oil derivative financial instruments that no longer qualified for hedge accounting because the hedged production exceeded actual and projected production under these contracts. The lower than expected production was caused primarily by hurricanes that affected offshore production in the Gulf of Mexico.
 
Other Income, Net
 
The following schedule includes the components of other income between 2004 and 2006.
 
                         
    2006     2005     2004  
    (In millions)  
 
Interest and dividend income
  $ 100       95       45  
Net gain on sales of non-oil and gas property and equipment
    6       150       33  
Loss on derivative financial instruments
          (48 )      
Gains from changes in foreign exchange rates
          2       23  
Other
    9       (1 )     25  
                         
Total
  $ 115       198       126  
                         
 
Interest and dividend income increased from 2004 to 2005 primarily due to an increase in cash and short-term investment balances and higher interest rates.
 
During 2005, we sold certain non-core midstream assets for a net gain of $150 million. Also during 2005, we incurred a $55 million loss on certain commodity hedges that no longer qualified for hedge accounting and were settled prior to the end of their original term. These hedges related to U.S. and Canadian oil production from properties sold as part of our 2005 property divestiture program. This loss was partially offset by a $7 million gain related to interest rate swaps that were settled prior to the end of their original term in conjunction with the early redemption of the $400 million 6.75% senior notes in 2005.
 
The gains in 2005 and 2004 from changes in foreign exchange rates were primarily related to $400 million of Canadian subsidiary debt that was denominated in U.S. dollars. The debt was retired in 2005.


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Income Taxes
 
The following table presents our total income tax 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 2004 to 2006, and differ from the U.S. statutory rate, are discussed below.
 
                         
    2006     2005     2004  
 
Total income tax expense (In millions)
  $ 1,189       1,606       1,095  
                         
U.S. statutory income tax rate
    35 %     35 %     35 %
Canadian statutory rate reductions
    (6 )%           (1 )%
Texas income-based tax
    1 %            
United States manufacturing deduction
          (1 )%      
Repatriation of Canadian earnings
          1 %      
Other
          1 %     (1 )%
                         
Effective income tax rate
    30 %     36 %     33 %
                         
 
In 2006, 2005 and 2004, deferred income taxes were reduced $243 million, $14 million and $36 million, respectively, due to Canadian statutory rate reductions that were enacted in each such year.
 
In 2006, deferred income taxes increased $39 million due to the effect of a new income-based tax enacted by the state of Texas that replaces a previous franchise tax. The new tax is effective January 1, 2007.
 
In 2006 and 2005, income taxes were reduced $12 million and $25 million, respectively, due to a new U.S. tax deduction for companies with domestic production activities, including oil and gas extraction.
 
In 2005, we recognized $28 million of taxes related to our repatriation of $545 million to the U.S. The cash was repatriated due to tax legislation that allowed qualifying companies to repatriate cash from foreign operations at a reduced income tax rate. Substantially all of the cash repatriated by us in 2005 related to earnings of our Canadian subsidiary.
 
Results of Discontinued Operations
 
On November 14, 2006, we announced our plans to divest our operations in Egypt. We anticipate completing the sale of our Egyptian operations in the first half of 2007. Pursuant to accounting rules for discontinued operations, Egypt is considered a discontinued operation at the end of 2006. As a result, the Egypt financial results for 2006 and all prior periods have been reclassified and are presented as discontinued operations.
 
Following are the components of the results of discontinued operations between 2004 and 2006.
 
                         
    2006     2005     2004  
    (In millions)  
 
Earnings from discontinued operations before income taxes
  $ 22       46       17  
Income tax (benefit) expense
    (1 )     15       12  
                         
Earnings from discontinued operations
  $ 23       31       5  
                         
 
Capital Resources, Uses and Liquidity
 
The following discussion of capital resources and liquidity should be read in conjunction with the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”


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Sources and Uses of Cash
 
The following table presents the sources and uses of our cash and cash equivalents from 2004 to 2006. The table presents capital expenditures on a cash basis. Therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this document. Additional discussion of these items follows the table.
 
                         
    2006     2005     2004  
    (In millions)  
 
Sources of cash and cash equivalents:
                       
Operating cash flow — continuing operations
  $ 5,936       5,514       4,789  
Sales of property and equipment
    40       2,151       95  
Net commercial paper borrowings
    1,808              
Stock option exercises
    73       124       268  
Net decrease in short-term investments
    106       287        
Other
    36              
                         
Total sources of cash and cash equivalents
    7,999       8,076       5,152  
                         
Uses of cash and cash equivalents:
                       
Capital expenditures
    (7,551 )     (4,026 )     (3,058 )
Debt repayments
    (862 )     (1,258 )     (973 )
Repurchases of common stock
    (253 )     (2,263 )     (189 )
Dividends
    (209 )     (146 )     (107 )
Net increase in short-term investments
                (626 )
                         
Total uses of cash and cash equivalents
    (8,875 )     (7,693 )     (4,953 )
                         
Increase (decrease) from continuing operations
    (876 )     383       199  
Increase (decrease) from discontinued operations
    13       34       (18 )
Effect of foreign exchange rates
    13       37       39  
                         
Net increase (decrease) in cash and cash equivalents
  $ (850 )     454       220  
                         
Cash and cash equivalents at end of year
  $ 756       1,606       1,152  
                         
Short-term investments at end of year
  $ 574       680       967  
                         
 
Operating Cash Flow — Continuing Operations
 
Net cash provided by operating activities (“operating cash flow”) is our primary source of capital and liquidity. Changes in operating cash flow 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, property impairments, derivative fair value changes and deferred income tax expense. As a result, our operating cash flow increased in 2006 and 2005 compared to the previous years largely due to increases in net earnings, as discussed in the “Results of Operations” section of this report.
 
Sales of Property and Equipment
 
In 2005, we generated $2.2 billion in pre-tax proceeds from sales of property and equipment. These consisted of $2.0 billion related to the sale of non-core oil and gas properties and $0.2 billion related to the sale of non-core midstream assets. Net of related income taxes, these proceeds were $1.8 billion for oil and gas properties and $0.1 billion for midstream assets.


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Net Commercial Paper Borrowings
 
On June 29, 2006, we acquired Chief for $2 billion of cash and the assumption of $0.2 billion of liabilities. We funded a portion of the purchase price with $1.4 billion of borrowings issued under our commercial paper program. As a result of the Chief acquisition and success in other onshore U.S. locations, we accelerated certain oil and gas development activities into the last half of 2006. We borrowed an additional $0.4 billion of commercial paper to fund this accelerated development.
 
Capital Expenditures
 
The increases in operating cash flow have enabled us to invest larger amounts in capital projects. As a result, excluding the acquisition of the Chief properties, our capital expenditures increased 38% in 2006. The majority of this increase related to our expenditures for the acquisition, drilling or development of oil and gas properties, which totaled $5.0 billion in 2006, excluding the Chief acquisition. Inflationary pressure driven by higher commodity prices and increased drilling activities in the Barnett Shale, Gulf of Mexico, Carthage and Groesbeck areas of the U.S. contributed to the increase. In addition, the payouts of our carried interests in Azerbaijan in the last half of 2006 and the weaker U.S. dollar impact on our Canadian operations also contributed to the increase.
 
Capital expenditures in 2005 increased 32% compared to 2004 primarily due to an increase in our expenditures for the acquisition, drilling or development of oil and gas properties, which totaled $3.9 billion in 2005. Increased drilling activities in the Barnett Shale, the approximately $200 million acquisition of Iron River acreage in Canada and the $74 million purchase of the Serpentina FPSO in offshore Equatorial Guinea were large contributors to the increase. Inflationary pressure driven by higher commodity prices and the weaker U.S. dollar also caused our expenditures to increase from 2004 to 2005.
 
Debt Repayments
 
Our net debt retirements were $0.9 billion, $1.3 billion and $1.0 billion in 2006, 2005 and 2004, respectively. These amounts consisted of payments at the scheduled maturity dates with the exception of the following payments. The 2006 amount includes $0.2 billion related to the repayment of debt acquired in the Chief acquisition. The 2005 amount includes $0.8 billion related to the retirement of zero coupon convertible debentures due in 2020 and 6.75% notes due in 2011. The 2004 amount includes $635 million for the payment of the outstanding balance under a $3 billion term loan credit facility due in 2006.
 
Repurchases of Common Stock
 
In August 2005, we completed a share repurchase program that began in October 2004. Under this program, we repurchased 49.6 million shares of our common stock at a total cost of $2.3 billion, or $46.69 per share. In August 2005, we announced another program to repurchase up to an additional 50 million shares of our common stock. During 2005 and 2006, we repurchased 6.5 million shares for $387 million, or $59.80 per share, under this program.
 
Dividends
 
Our common stock dividends were $199 million, $136 million and $97 million in 2006, 2005 and 2004, respectively. We also paid $10 million of preferred stock dividends in 2006, 2005 and 2004. The 2006 and 2005 increases in common stock dividends were primarily related to a 50% increase in the dividend rate in the first quarter of both 2006 and 2005, partially offset by a decrease in outstanding shares due to share repurchases.
 
Changes in Short-Term Investments
 
To maximize our income on available cash balances, we invest in highly liquid, short-term investments. The purchase and sale of these short-term investments will cause cash and cash equivalents to decrease and


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increase, respectively. Short-term investment balances decreased $106 million and $287 million in 2006 and 2005, respectively, and increased $626 million in 2004.
 
Liquidity
 
Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain a revolving line 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 and long-term debt. During 2007, another major source of liquidity will be proceeds from the sales of our operations in Egypt and West Africa. We expect the combination of these sources of capital will be more than adequate to fund future capital expenditures, debt repayments, common stock repurchases, and other contractual commitments as discussed later in this section.
 
Operating Cash Flow
 
Our operating cash flow has increased nearly 25% since 2004, reaching a total of $5.9 billion in 2006. We expect operating cash flow to continue to be our primary source of liquidity. Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities 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 are beyond our control and are difficult to predict.
 
We periodically believe it appropriate to mitigate some of the risk inherent in oil and natural gas prices. We have used a variety of avenues to achieve this partial risk mitigation. We have utilized price collars to set minimum and maximum prices on a portion of our production. We have also utilized various price swap contracts and fixed-price physical delivery contracts to fix the price to be received for a portion of future oil and natural gas production. Based on contracts currently in place, approximately 5% of our estimated 2007 natural gas production (3% of our total Boe production) is subject to either price collars, swaps or fixed-price contracts.
 
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.
 
Credit Lines
 
Another source of liquidity is our $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes a five-year 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 of December 31, 2006, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of December 31, 2006, net of $1.8 billion of outstanding commercial paper and $284 million of outstanding letters of credit, was approximately $408 million.
 
The Senior Credit Facility matures on April 7, 2011, and all amounts outstanding will be due and payable at that time 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. We are working to obtain lender approval to extend the current maturity date of April 7, 2011 to April 7, 2012. If successful, this maturity date extension will be effective April 7, 2007, provided we have not experienced a “material adverse effect,” as defined in the Senior Credit Facility agreement, at that date.
 
The Senior Credit Facility contains 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 our


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consolidated financial statements. As defined in the agreement, total funded debt excludes the debentures that are exchangeable into shares of Chevron Corporation common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2006, our debt to capitalization ratio as calculated pursuant to this covenant was 27.3%.
 
Our access to funds from the Senior Credit 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 Senior Credit Facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.
 
We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $2 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven 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 December 31, 2006, we had $1.8 billion of commercial paper debt outstanding at an average rate of 5.37%.
 
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 positive outlook by Standard & Poor’s, Baa2 with a positive outlook by Moody’s and BBB with a positive outlook by Fitch.
 
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 for the Senior Credit Facility from LIBOR plus 45 basis points to a new rate of LIBOR plus 65 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2006, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.
 
Capital Expenditures
 
In February 2007, we provided guidance for our 2007 capital expenditures which are expected to range from $5.7 billion to $6.2 billion. This represents the largest planned use of our 2007 operating cash flow, with the high end of the range being 11% higher than our 2006 capital expenditures, excluding the Chief acquisition. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if oil and natural gas prices fluctuate from current estimates, we could choose to defer a portion of these planned 2007 capital expenditures until later periods, or accelerate capital expenditures planned for periods beyond 2007 to achieve the desired balance between sources and uses of liquidity. Based upon current oil and natural gas price expectations for 2007, we anticipate having adequate capital resources to fund our 2007 capital expenditures.


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Common Stock Repurchase Program
 
In August 2005, we announced a program to repurchase up to 50 million shares of our common stock. We had repurchased 6.5 million shares under this program through the middle of 2006 when the program was suspended as a result of the Chief acquisition. In conjunction with the sales of our Egyptian and West African operations, we expect to resume this repurchase program in late 2007 by using a portion of the sales proceeds to repurchase common stock. Although this program expires at the end of 2007, it could be extended if necessary.
 
Contractual Obligations
 
A summary of our contractual obligations as of December 31, 2006, 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)  
 
Long-term debt(1)
  $ 7,770       2,208       937       2,100       2,525  
Interest expense(2)
    5,797       492       764       690       3,851  
Drilling and facility obligations(3)
    2,993       886       1,137       844       126  
Asset retirement obligations(4)
    894       61       75       143       615  
Firm transportation agreements(5)
    574       123       173       106       172  
Lease obligations(6)
    595       80       163       123       229  
Other
    37       28       5       4        
                                         
Total
  $ 18,660       3,878       3,254       4,010       7,518  
                                         
 
 
(1)  Long-term debt amounts represent scheduled maturities of our debt obligations at December 31, 2006, excluding $5 million of fair value adjustments and $8 million of net premiums included in the carrying value of debt. The “Less than 1 Year” amount includes $1.8 billion of short-term commercial paper borrowings. We intend to use the proceeds from the sales of our Egyptian and West African assets to repay our outstanding commercial paper. The “1-3 Years” amount includes $760 million related to our debentures exchangeable into shares of Chevron Corporation common stock. As of December 31, 2006, we beneficially owned approximately 14.2 million shares of Chevron common stock for possible exchange for the exchangeable debentures. In addition, $284 million of letters of credit that have been issued by commercial banks on our behalf are excluded from the table. The majority of these letters of credit, if funded, would become borrowings under our revolving credit facility. Most of these letters of credit have been granted by financial institutions to support our international and Canadian drilling commitments.
 
(2)  Interest expense amounts represent the scheduled fixed-rate and variable-rate cash payments related to our debt. Interest on our variable-rate debt was estimated based upon expected future interest rates as of December 31, 2006.
 
(3)  Drilling and facility obligations represent contractual agreements with third party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. Included in the $3.0 billion total is $1.9 billion which relates to long-term contracts for three deepwater drilling rigs and certain other contracts for onshore drilling and facility obligations in which drilling or facilities construction has not commenced. The $1.9 billion represents the gross commitment under these contracts. Our ultimate payment for these commitments will be reduced by the amounts billed to our working interest partners. Payments for these commitments, net of amounts billed to partners, will be capitalized as a component of oil and gas properties.
 
(4)  Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2006 balance sheet.


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(5)  Firm transportation agreements represent “ship or pay” arrangements whereby we have committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. We have entered into these agreements to aid the movement of our production to market. We expect to have sufficient production to utilize the majority of these transportation services.
 
(6)  Lease obligations consist of operating leases for office space and equipment, an offshore platform spar and FPSO’s. Office and equipment leases represent non-cancelable leases for office space and equipment used in our daily operations.
 
    We have an offshore platform spar that is being used in the development of the Nansen field in the Gulf of Mexico. This spar is subject to a 20-year lease and contains various options whereby we may purchase the lessors’ interests in the spars. We have guaranteed that the spar will have a residual value at the end of the term equal to at least 10% of the fair value of the spar at the inception of the lease. The total guaranteed value is $14 million in 2022. However, such amount may be reduced under the terms of the lease agreements. In 2005, we sold our interests in the Boomvang field in the Gulf of Mexico, which has a spar lease with terms similar to those of the Nansen lease. As a result of the sale, we are subleasing the Boomvang Spar. The table above does not include any amounts related to the Boomvang spar lease. However, if the sublessee were to default on its obligation, we would continue to be obligated to pay the periodic lease payments and any guaranteed value required at the end of the term.
 
    We also lease two FPSO’s that are being used in the Panyu project offshore China and the Polvo project offshore Brazil. The Panyu FPSO lease term expires in September 2009. The Polvo FPSO lease term expires in 2014.
 
Pension Funding and Estimates
 
Funded Status.  As compared to the “projected benefit obligation,” our qualified and nonqualified defined benefit plans were underfunded by $178 million and $133 million at December 31, 2006 and 2005, respectively. A detailed reconciliation of the 2006 changes to our underfunded status is included in Note 6 to the accompanying consolidated financial statements. Of the $178 million underfunded status at the end of 2006, $156 million is attributable to various nonqualified defined benefit plans which have no plan assets. However, we have established certain trusts to fund the benefit obligations of such nonqualified plans. As of December 31, 2006, these trusts had investments with a fair value of $59 million. The value of these trusts is included in noncurrent other assets in our accompanying consolidated balance sheets.
 
As compared to the “accumulated benefit obligation,” our qualified defined benefit plans were overfunded by $59 million at December 31, 2006. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. Our current intentions are to provide sufficient funding in future years to ensure the accumulated benefit obligation remains fully funded. The actual amount of contributions required during this period will depend on investment returns from the plan assets. Required contributions also depend upon changes in actuarial assumptions made during the same period, particularly the discount rate used to calculate the present value of the accumulated benefit obligation. For 2007, we anticipate the accumulated benefit obligation will remain fully funded without contributing to our defined benefit plans. Therefore, we don’t expect to contribute to the plans during 2007.
 
Pension Estimate Assumptions.  Our pension expense is recognized on an accrual basis over employees’ approximate service periods and is generally calculated independent of funding decisions or requirements. We recognized expense for our defined benefit pension plans of $31 million, $26 million and $26 million in 2006, 2005 and 2004, respectively. We estimate that our pension expense will approximate $43 million in 2007.
 
The calculation of pension expense and pension liability requires the use of a number of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. We believe that the two most critical assumptions affecting pension expense and liabilities are the expected long-term rate of return on plan assets and the assumed discount rate.
 
We assumed that our plan assets would generate a long-term weighted average rate of return of 8.40% at both December 31, 2006 and 2005. We developed these expected long-term rate of return assumptions by


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evaluating input from external consultants and economists as well as long-term inflation assumptions. The expected long-term rate of return on plan assets is based on a target allocation of investment types in such assets. The target investment allocation for our plan assets is 50% U.S. large cap equity securities; 15% U.S. small cap equity securities, equally allocated between growth and value; 15% international equity securities, equally allocated between growth and value; and 20% debt securities. We expect our long-term asset allocation on average to approximate the targeted allocation. We regularly review our actual asset allocation and periodically rebalance the investments to the targeted allocation when considered appropriate.
 
Pension expense increases as the expected rate of return on plan assets decreases. A decrease in our long-term rate of return assumption of 100 basis points (from 8.40% to 7.40%) would increase the expected 2007 pension expense by $6 million.
 
We discounted our future pension obligations using a weighted average rate of 5.72% at both December 31, 2006 and 2005. The discount rate is determined at the end of each year based on the rate at which obligations could be effectively settled. This rate is based on high-quality bond yields, after allowing for call and default risk. We consider high quality corporate bond yield indices, such as Moody’s Aa, when selecting the discount rate.
 
The pension liability and future pension expense both increase as the discount rate is reduced. Lowering the discount rate by 25 basis points (from 5.72% to 5.47%) would increase our pension liability at December 31, 2006, by $25 million, and increase estimated 2007 pension expense by $3 million.
 
At December 31, 2006, we had actuarial losses of $214 million which will be recognized as a component of pension expense in future years. These losses are primarily due to reductions in the discount rate since 2001 and increases in participant wages. We estimate that approximately $15 million and $13 million of the unrecognized actuarial losses will be included in pension expense in 2007 and 2008, respectively. The $15 million estimated to be recognized in 2007 is a component of the total estimated 2007 pension expense of $43 million referred to earlier in this section.
 
Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our defined benefit pension plans will impact future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.
 
On August 17, 2006, the Pension Protection Act was signed into law. Beginning in 2008, this act will cause extensive changes in the determination of both the minimum required contribution and the maximum tax deductible limit. Because the new required contribution will approximate our current policy of fully funding the accumulated benefit obligation, the changes are not expected to have a significant impact on future cash flows.
 
Beginning with our December 31, 2006 balance sheet, Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R), requires us to recognize on our consolidated balance sheet the funded status of our defined benefit plans. The funded status is measured as the difference between the projected benefit obligation and the fair value of plan assets. As a result, we recognized as liabilities the actuarial losses and other costs that were previously unrecognized under prior accounting rules, and the net effect was also recorded as a reduction to stockholders’ equity on December 31, 2006. This reduction was $140 million, or less than 1% of our stockholders’ equity.
 
Contingencies and Legal Matters
 
For a detailed discussion of contingencies and legal matters, see “Item 3. Legal Proceedings” and Note 8 of the accompanying consolidated financial statements.
 
Critical Accounting Policies and Estimates
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported


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amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known.
 
The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regard to estimates used. Our critical accounting policies and significant judgments and estimates related to those policies are described below. We have reviewed these critical accounting policies with the Audit Committee of the Board of Directors.
 
Full Cost Ceiling Calculations
 
Policy Description
 
We follow the full cost method of accounting for our oil and gas properties. The full cost method subjects companies to quarterly calculations of a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense, except as discussed in the following paragraph. The ceiling limitation is imposed separately for each country in which we have oil and gas properties.
 
If, subsequent to the end of the quarter but prior to the applicable financial statements being published, prices increase to levels such that the ceiling would exceed the costs to be recovered, a writedown otherwise indicated at the end of the quarter is not required to be recorded. A writedown indicated at the end of a quarter is also not required if the value of additional reserves proved up on properties after the end of the quarter but prior to the publishing of the financial statements would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end of the quarter. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
 
Judgments and Assumptions
 
The discounted present value of future net revenues for our proved oil, natural gas and NGL reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Certain of our reserve estimates are prepared or audited by outside petroleum consultants, while other reserve estimates are prepared by our engineers. See Note 15 of the accompanying consolidated financial statements.
 
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. In the past five years, annual revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 1% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A.
 
While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that a 10% discount factor be used


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and that prices and costs in effect as of the last day of the period are held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs. Rather, they are based on such prices and costs in effect as of the end of each quarter when the ceiling calculation is performed. In calculating the ceiling, we adjust the end-of-period price by the effect of cash flow hedges in place. This adjustment requires little judgment as the end-of-period price is adjusted using the contract prices for our cash flow hedges. We had no such hedges outstanding at December 31, 2006.
 
Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been volatile. On any particular day at the end of a quarter, prices can be either substantially higher or lower than our long-term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
 
Derivative Financial Instruments
 
Policy Description
 
The majority of our historical derivative instruments have consisted of commodity financial instruments used to manage our cash flow exposure to oil and gas price volatility. We have also entered into interest rate swaps to manage our exposure to interest rate volatility. The interest rate swaps mitigate either the cash flow effects of interest rate fluctuations on interest expense for variable-rate debt instruments, or the fair value effects of interest rate fluctuations on fixed-rate debt. We also have an embedded option derivative related to the fair value of our debentures exchangeable into shares of Chevron Corporation common stock.
 
All derivatives are recognized at their current fair value on our balance sheet. Changes in the fair value of derivative financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. If such criteria are met for cash flow hedges, the effective portion of the change in the fair value is recorded directly to accumulated other comprehensive income, a component of stockholders’ equity, until the hedged transaction occurs. The ineffective portion of the change in fair value is recorded in the statement of operations. If hedge accounting criteria are met for fair value hedges, the change in the fair value is recorded in the statement of operations with an offsetting amount recorded for the change in fair value of the hedged item.
 
A derivative instrument qualifies for hedge accounting treatment if we designate the instrument as such on the date the derivative contract is entered into or the date of an acquisition or business combination which includes derivative contracts. Additionally, we must document the relationship between the hedging instrument and hedged item, as well as the risk-management objective and strategy for undertaking the instrument. We must also assess, both at the instrument’s inception and on an ongoing basis, whether the derivative is highly effective in offsetting the change in cash flow of the hedged item.
 
Judgments and Assumptions
 
The estimates of the fair values of our commodity derivative instruments require substantial judgment. For these instruments, we obtain forward price and volatility data for all major oil and gas trading points in North America from independent third parties. These forward prices are compared to the price parameters contained in the hedge agreements. The resulting estimated future cash inflows or outflows over the lives of the hedge contracts are discounted using LIBOR and money market futures rates for the first year and money market futures and swap rates thereafter. In addition, we estimate the option value of price floors and price caps using an option pricing model. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices, regional price differentials and interest rates. Fair values of our other derivative instruments require less judgment to estimate and are primarily based on quotes from independent third parties such as counterparties or brokers.


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Quarterly changes in estimates of fair value have only a minimal impact on our liquidity, capital resources or results of operations, as long as the derivative instruments qualify for hedge accounting treatment. Changes in the fair values of derivatives that do not qualify for hedge accounting treatment can have a significant impact on our results of operations, but generally will not impact our liquidity or capital resources. Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding the effects that changes in market prices will have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.’’
 
Business Combinations
 
Policy Description
 
We have grown substantially during recent years through acquisitions of other oil and natural gas companies. Most of these acquisitions have been accounted for using the purchase method of accounting, and recent accounting pronouncements require that all future acquisitions will be accounted for using the purchase method.
 
Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill is assessed for impairment at least annually.
 
Judgments and Assumptions
 
There are various assumptions we make in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by our engineers and that of outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.
 
However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies end-of-period price and cost information to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a business combination must be based on our estimates of future oil, natural gas and NGL prices. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.
 
We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the business combination based upon our cost of capital.
 
We also apply these same general principles to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we consider to be an appropriate risk-weighting factor in each particular instance. It is common for the discounted future net


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revenues of probable and possible reserves to be reduced by factors ranging from 30% to 80% to arrive at what we consider to be the appropriate fair values.
 
Generally, in our business combinations, the determination of the fair values of oil and gas properties requires much more judgment than the fair values of other assets and liabilities. The acquired companies commonly have long-term debt that we assume in the acquisition, and this debt must be recorded at the estimated fair value as if we had issued such debt. However, significant judgment on our behalf is usually not required in these situations due to the existence of comparable market values of debt issued by peer companies.
 
Except for the 2002 Mitchell merger, our mergers and acquisitions have involved other entities whose operations were predominantly in the area of exploration, development and production activities related to oil and gas properties. However, in addition to exploration, development and production activities, Mitchell’s business also included substantial marketing and midstream activities. Therefore, a portion of the Mitchell purchase price was allocated to the fair value of Mitchell’s marketing and midstream facilities and equipment. This consisted primarily of natural gas processing plants and natural gas pipeline systems.
 
The Mitchell midstream assets primarily served gas producing properties that we also acquired from Mitchell. Therefore, certain of the assumptions regarding future operations of the gas producing properties were also integral to the value of the midstream assets. For example, future quantities of natural gas estimated to be processed by natural gas processing plants were based on the same estimates used to value the proved and unproved gas producing properties. Future expected prices for marketing and midstream product sales were also based on price cases consistent with those used to value the oil and gas producing assets acquired from Mitchell. Based on historical costs and known trends and commitments, we also estimated future operating and capital costs of the marketing and midstream assets to arrive at estimated future cash flows. These cash flows were discounted at rates consistent with those used to discount future net cash flows from oil and gas producing assets to arrive at our estimated fair value of the marketing and midstream facilities and equipment.
 
In addition to the valuation methods described above, we perform other quantitative analyses to support the indicated value in any business combination. These analyses include information related to comparable companies, comparable transactions and premiums paid.
 
In a comparable companies analysis, we review the public stock market trading multiples for selected publicly traded independent exploration and production companies with comparable financial and operating characteristics. Such characteristics are market capitalization, location of proved reserves and the characterization of those reserves that we deem to be similar to those of the party to the proposed business combination. We compare these comparable company multiples to the proposed business combination company multiples for reasonableness.
 
In a comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. We compare these comparable transaction multiples to the proposed business combination transaction multiples for reasonableness.
 
In a premiums paid analysis, we use a sample of selected independent exploration and production company transactions in addition to selected transactions of all publicly traded companies announced recently, to review the premiums paid to the price of the target one day, one week and one month prior to the announcement of the transaction. We use this information to determine the mean and median premiums paid and compare them to the proposed business combination premium for reasonableness.
 
While these estimates of fair value for the various assets acquired and liabilities assumed have no effect on our liquidity or capital resources, they can have an effect on the future results of operations. Generally, the higher the fair value assigned to both the oil and gas properties and non-oil and gas properties, the lower future net earnings will be as a result of higher future depreciation, depletion and amortization expense. Also, a higher fair value assigned to the oil and gas properties, based on higher future estimates of oil and gas prices, will increase the likelihood of a full cost ceiling writedown in the event that subsequent oil and gas


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prices drop below our price forecast that was used to originally determine fair value. A full cost ceiling writedown would have no effect on our liquidity or capital resources in that period because it is a noncash charge, but it would adversely affect results of operations. As discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources, Uses and Liquidity,” in calculating our debt-to-capitalization ratio under our credit agreement, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or goodwill impairments.
 
Our estimates of reserve quantities are one of the many estimates that are involved in determining the appropriate fair value of the oil and gas properties acquired in a business combination. As previously disclosed in our discussion of the full cost ceiling calculations, during the past five years, our annual revisions to our reserve estimates have averaged approximately 1%. As discussed in the preceding paragraphs, there are numerous estimates in addition to reserve quantity estimates that are involved in determining the fair value of oil and gas properties acquired in a business combination. The inter-relationship of these estimates makes it impractical to provide additional quantitative analyses of the effects of changes in these estimates.
 
Valuation of Goodwill
 
Policy Description
 
Goodwill is tested for impairment at least annually. This requires us to estimate the fair values of our own assets and liabilities in a manner similar to the process described above for a business combination. Therefore, considerable judgment similar to that described above in connection with estimating the fair value of an acquired company in a business combination is also required to assess goodwill for impairment.
 
Judgments and Assumptions
 
Generally, the higher the fair value assigned to both the oil and gas properties and non-oil and gas properties, the lower goodwill would be. A lower goodwill value decreases the likelihood of an impairment charge. However, unfavorable changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.
 
Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates, other than to note the historical average changes in our reserve estimates previously set forth.
 
Recently Issued Accounting Standards Not Yet Adopted
 
In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. Interpretation No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. This Interpretation is effective for fiscal years beginning after December 15, 2006, and we will adopt it in the first quarter of 2007. We do not expect the adoption of Interpretation No. 48 to have a material impact on our financial statements and related disclosures.
 
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements. Statement No. 157 provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. However, this Statement does not require any new fair value measurements. Statement No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently assessing the effect, if any, the adoption of Statement No. 157 will have on our financial statements and related disclosures.
 
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R). Statement No. 158 requires the recognition of the overfunded or underfunded status of a defined benefit postretirement plan in the balance sheet. We adopted this recognition requirement


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as of December 31, 2006. The effects of this adoption are summarized in Note 6 of the accompanying consolidated financial statements. Statement No. 158 also requires the measurement of plan assets and benefit obligations as of the date of the employer’s fiscal year-end. The Statement provides two alternatives to transition to a fiscal year-end measurement date. This measurement requirement is effective for fiscal years ending after December 15, 2008. We have not yet adopted this measurement requirement, but we do not expect such adoption to have a material effect on our results of operations, financial condition, liquidity or compliance with debt covenants.
 
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. Statement No. 159 permits entities to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which we elect the fair value measurement option would be reported in earnings. Statement No. 159 is effective for fiscal years beginning after November 15, 2007. However, early adoption is permitted for fiscal years beginning on or before November 15, 2007, provided we also elect to apply the provisions of Statement No. 157, Fair Value Measurements, at the same time. We are currently assessing the effect, if any, the adoption of Statement No. 159 will have on our financial statements and related disclosures.
 
2007 Estimates
 
The forward-looking statements provided in this discussion are based on our examination of historical operating trends, the information which was used to prepare the December 31, 2006 reserve reports and other data in our possession or available from third parties. These forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for our oil, natural gas and NGLs during 2007 will be substantially similar to those of 2006, unless otherwise noted. We make reference to the “Disclosure Regarding Forward-Looking Statements” at the beginning of this report. Amounts related to Canadian operations have been converted to U.S. dollars using a projected average 2007 exchange rate of $0.89 U.S. dollar to $1.00 Canadian dollar.
 
On November 14, 2006, we announced our intent to divest our Egyptian oil and gas assets and terminate our operations in Egypt. We expect to complete this asset sale during the first half of 2007. Subsequently on January 23, 2007, we announced our intent to divest our West African oil and gas assets and terminate our operations in West Africa. We expect to complete this asset sale by the end of the third quarter in 2007. All Egyptian and West African related revenues, expenses and capital will be reported as discontinued operations in our 2007 financial statements. Accordingly, all forward-looking estimates in the following discussion exclude amounts related to our operations in Egypt and West Africa, unless otherwise noted. The assets held for sale represented less than five percent of our 2006 production and December 31, 2006 proved reserves.
 
Oil, Gas and NGL Production
 
Set forth in the following paragraphs are individual estimates of oil, gas and NGL production for 2007. We estimate, on a combined basis, that our 2007 oil, gas, and NGL production will total approximately 219 to 221 MMBoe. Of this total, approximately 92% is estimated to be produced from reserves classified as “proved” at December 31, 2006. The following estimates for oil, gas and NGL production are calculated at the midpoint of the estimated range for total production.


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Oil Production
 
Oil production in 2007 is expected to total approximately 55 MMBbls. Of this total, approximately 99% is estimated to be produced from reserves classified as “proved” at December 31, 2006. The expected production by area is as follows:
 
         
    (MMBbls)  
 
U.S. Onshore
    10  
U.S. Offshore
    9  
Canada
    15  
International
    21  
 
Oil Prices
 
We have not fixed the price we will receive on any of our 2007 oil production. Our 2007 average prices for each of our areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is the monthly average of settled prices on each trading day for benchmark West Texas Intermediate crude oil delivered at Cushing, Oklahoma.
 
     
    Expected Range of Oil Prices
    as a % of NYMEX Price
 
U.S. Onshore
  86% to 96%
U.S. Offshore
  90% to 100%
Canada
  60% to 70%
International
  83% to 93%
 
Gas Production
 
Gas production in 2007 is expected to total approximately 841 Bcf. Of this total, approximately 88% is estimated to be produced from reserves classified as “proved” at December 31, 2006. The expected production by area is as follows:
 
         
    (Bcf)  
 
U.S. Onshore
    557  
U.S. Offshore
    75  
Canada
    207  
International
    2  
 
Gas Prices
 
Our 2007 average prices for each of our areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is determined to be the first-of-month South Louisiana Henry Hub price index as published monthly in Inside FERC.
 
Based on contracts currently in place, we will have approximately 116 MMcf per day of gas production in 2007 that is subject to either fixed-price contracts, swaps, floors or collars. These amounts represent approximately 5% of our estimated gas production for 2007. Therefore, these various pricing arrangements are not expected to have a material impact on the ranges of estimated gas price realizations set forth in the following table.
 
     
    Expected Range of Gas Prices
    as a % of NYMEX Price
 
U.S. Onshore
  80% to 90%
U.S. Offshore
  96% to 106%
Canada
  80% to 90%
International
  100% to 110%


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NGL Production
 
We expect our 2007 production of NGLs to total approximately 25 MMBbls. Of this total, approximately 95% is estimated to be produced from reserves classified as “proved” at December 31, 2006. The expected production by area is as follows:
 
         
    (MMBbls)  
 
U.S. Onshore
    20  
U.S. Offshore
    1  
Canada
    4  
 
Marketing and Midstream Revenues and Expenses
 
Marketing and midstream revenues and expenses are derived primarily from our natural gas processing plants and natural gas transport pipelines. These revenues and expenses vary in response to several factors. The factors include, but are not limited to, changes in production from wells connected to the pipelines and related processing plants, changes in the absolute and relative prices of natural gas and NGLs, provisions of the contract agreements and the amount of repair and workover activity required to maintain anticipated processing levels.
 
These factors, coupled with uncertainty of future natural gas and NGL prices, increase the uncertainty inherent in estimating future marketing and midstream revenues and expenses. Given these uncertainties, we estimate that marketing and midstream revenues will be between $1.70 billion and $2.10 billion, and marketing and midstream expenses will be between $1.31 billion and $1.67 billion.
 
Production and Operating Expenses
 
Our production and operating expenses include lease operating expenses, transportation costs and production taxes. These expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from the property base, changes in the general price level of services and materials that are used in the operation of the properties, the amount of repair and workover activity required and changes in production tax rates. Oil, natural gas and NGL prices also have an effect on lease operating expenses and impact the economic feasibility of planned workover projects. Given these uncertainties, we estimate that 2007 lease operating expenses (including transportation costs) will be between $1.70 billion and $1.77 billion. Additionally, we estimate our production taxes for 2007 to be between 3.6% and 4.1% of consolidated oil, natural gas and NGL revenues.
 
Depreciation, Depletion and Amortization (“DD&A”)
 
The 2007 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition efforts in 2007 compared to the costs incurred for such efforts, and the revisions to our year-end 2006 reserve estimates that, based on prior experience, are likely to be made during 2007.
 
Given these uncertainties, we expect our oil and gas property related DD&A rate will be between $11.00 per Boe and $11.50 per Boe. Based on these DD&A rates and the production estimates set forth earlier, oil and gas property related DD&A expense for 2007 is expected to be between $2.42 billion and $2.53 billion.
 
Additionally, we expect our depreciation and amortization expense related to non-oil and gas property fixed assets to total between $210 million and $220 million.
 
Accretion of Asset Retirement Obligation
 
Accretion of asset retirement obligation in 2007 is expected to be between $45 million and $55 million.


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General and Administrative Expenses (“G&A”)
 
Our G&A includes employee compensation and benefits costs and the costs of many different goods and services used in support of our business. G&A varies with the level of our operating activities and the related staffing and professional services requirements. In addition, employee compensation and benefits costs vary due to various market factors that affect the level and type of compensation and benefits offered to employees. Also, goods and services are subject to general price level increases or decreases. Therefore, significant variances in any of these factors from current expectations could cause actual G&A to vary materially from the estimate.
 
Given these limitations, G&A in 2007 is expected to be between $460 million and $480 million. This estimate includes approximately $60 million of noncash, share-based compensation, net of related capitalization in accordance with the full cost method of accounting for oil and gas properties.
 
Reduction of Carrying Value of Oil and Gas Properties
 
We follow the full cost method of accounting for our oil and gas properties described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.” Reductions to the carrying value of our oil and gas properties are largely dependent on the success of drilling results and oil and natural gas prices at the end of our quarterly reporting periods. Due to the uncertain nature of future drilling efforts and oil and natural gas prices, we are not able to predict whether we will incur such reductions in 2007.
 
Interest Expense
 
Future interest rates and debt outstanding have a significant effect on our interest expense. We can only marginally influence the prices we will receive in 2007 from sales of oil, natural gas and NGLs and the resulting cash flow. These factors increase the margin of error inherent in estimating future outstanding debt balances and related interest expense. Other factors which affect outstanding debt balances and related interest expense, such as the amount and timing of capital expenditures and proceeds from the sale of our assets in Egypt and West Africa, are generally within our control.
 
Based on the information related to interest expense set forth below, we expect our 2007 interest expense to be between $400 million and $410 million. This estimate assumes no material changes in prevailing interest rates. This estimate also assumes no material changes in our expected level of indebtedness, except for an assumption that our commercial paper will be repaid at the end of the second quarter of 2007.
 
The interest expense in 2007 related to our fixed-rate debt, including net accretion of related discounts, will be approximately $410 million. This fixed-rate debt removes the uncertainty of future interest rates from some, but not all, of our long-term debt.
 
Our floating rate debt is comprised of variable-rate commercial paper and one debt instrument which has been converted to floating rate debt through the use of an interest rate swap. Our floating rate debt is summarized in the following table:
 
             
Debt Instrument
  Notional Amount  
Floating Rate
(In millions)
 
Commercial paper
  $ 1,808 (1)   Various(2)
4.375% senior notes due in Oct 2007
  $ 400     LIBOR plus 40 basis points
 
 
(1) Represents outstanding balance as of December 31, 2006.
 
(2) 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 December 31, 2006, the average rate on the outstanding balance was 5.37%.


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Based on estimates of future LIBOR rates as of December 31, 2006, interest expense on floating rate debt, including net amortization of premiums, is expected to total between $80 million and $90 million in 2007.
 
Our interest expense totals include payments of facility and agency fees, amortization of debt issuance costs and other miscellaneous items not related to the debt balances outstanding. We expect between $5 million and $15 million of such items to be included in our 2007 interest expense. Also, we expect to capitalize between $95 million and $105 million of interest during 2007.
 
Effects of Changes in Foreign Currency Rates
 
Foreign currency gains or losses are not expected to be material in 2007.
 
Other Income
 
We estimate that our other income in 2007 will be between $65 million and $85 million.
 
Historically, we maintained a comprehensive insurance program that included coverage for physical damage to our offshore facilities caused by hurricanes. Our historical insurance program also included substantial business interruption coverage which we are utilizing to recover costs associated with the suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of 2005.
 
Based on current estimates of physical damage and the anticipated length of time we will have production suspended, we expect our policy recoveries will exceed repair costs and deductible amounts. This expectation is based upon several variables, including the $467 million received in the third quarter of 2006 as a full settlement of the amount due from our primary insurers. As of December 31, 2006, $154 million of these proceeds had been utilized as reimbursement of past repair costs and deductible amounts. The remaining proceeds of $313 million will be utilized as reimbursement of our anticipated future repair costs. We have not yet received any settlements related to claims filed with our secondary insurers.
 
Should our total policy recoveries, including the partial settlements already received from our primary insurers, exceed all repair costs and deductible amounts, such excess will be recognized as other income in the statement of operations in the period in which such determination can be made. Based on the most recent estimates of our costs for repairs, we believe that some amount will ultimately be recorded as other income. However, the timing and amount that would be recorded as other income are uncertain. Therefore, the 2007 estimate for other income above does not include any amount related to hurricane proceeds.
 
Income Taxes
 
Our financial income tax rate in 2007 will vary materially depending on the actual amount of financial pre-tax earnings. The tax rate for 2007 will be significantly affected by the proportional share of consolidated pre-tax earnings generated by U.S., Canadian and International operations due to the different tax rates of each country. There are certain tax deductions and credits that will have a fixed impact on 2007 income tax expense regardless of the level of pre-tax earnings that are produced.
 
Given the uncertainty of pre-tax earnings, we expect that our consolidated financial income tax rate in 2007 will be between 20% and 40%. The current income tax rate is expected to be between 15% and 25%. The deferred income tax rate is expected to be between 5% and 15%. Significant changes in estimated capital expenditures, production levels of oil, natural gas and NGLs, the prices of such products, marketing and midstream revenues, or any of the various expense items could materially alter the effect of the aforementioned tax deductions and credits on 2007 financial income tax rates.
 
Discontinued Operations
 
As previously discussed, we intend to divest our Egyptian and West African operations in 2007. We expect to complete the sale of Egypt during the first half of 2007 and the sale of West Africa during the third quarter of 2007. The following table shows the estimates for 2007 oil, gas and NGL production as well as the


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anticipated production and operating expenses associated with these discontinued operations for 2007. These estimates assume the sales of Egypt and West Africa will occur at the end of the second quarter of 2007. Pursuant to accounting rules for discontinued operations, the Egyptian assets will not be subject to DD&A during 2007 and the West African assets will only be subject to DD&A for the first month of 2007.
 
                 
    Egypt     West Africa  
 
Oil production (MMBbls)
    1       5  
Gas production (Bcf)
          3  
Total production (MMBoe)
    1       6  
Production and operating expenses (In millions)
  $ 11     $ 34  
Capital expenditures (In millions)
  $ 17     $ 120  
 
Year 2007 Potential Capital Resources, Uses and Liquidity
 
Capital Expenditures
 
Though we have completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, we do not “budget,” nor can we reasonably predict, the timing or size of such possible acquisitions.
 
Our capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from our price expectations for our future production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2007 capital expenditures. In addition, if the actual material or labor costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from our estimates.
 
Given the limitations discussed above, the following table shows expected drilling, development and facilities expenditures by geographic area. Production capital related to proved reserves relates to reserves classified as proved as of year-end 2006. Other production capital includes drilling that does not offset currently productive units and for which there is not a certainty of continued production from a known productive formation. Exploration capital includes exploratory drilling to find and produce oil or gas in previously untested fault blocks or new reservoirs.
 
                                         
    U.S.
    U.S.
                   
    Onshore     Offshore     Canada     International     Total  
    (In millions)  
 
Production capital related to proved reserves
  $ 1,170 - $1,270     $  80 - $ 90     $  410  - $ 450     $ 260 - $280     $ 1,920 - $2,090  
Other production capital
  $ 1,250 - $1,340     $ 220 - $230     $  590  - $ 640     $ 15 - $ 20     $ 2,075 - $2,230  
Exploration capital
  $ 350 - $  380     $ 290 - $310     $  160  - $ 170     $ 75 - $ 85     $ 875 - $  945  
                                         
Total
  $ 2,770 - $2,990     $ 590 - $630     $ 1,160 - $1,260     $ 350 - $385     $ 4,870 -$5,265  
                                         
 
In addition to the above expenditures for drilling, development and facilities, we expect to spend between $330 million to $370 million on our marketing and midstream assets, which include our oil pipelines, gas processing plants, CO2 removal facilities and gas transport pipelines. We also expect to capitalize between $245 million and $255 million of G&A expenses in accordance with the full cost method of accounting and to capitalize between $95 million and $105 million of interest. We also expect to pay between $40 million and $50 million for plugging and abandonment charges, and to spend between $135 million and $145 million for other non-oil and gas property fixed assets.


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Other Cash Uses
 
Our management expects the policy of paying a quarterly common stock dividend to continue. With the current $0.1125 per share quarterly dividend rate and 444 million shares of common stock outstanding as of December 31, 2006, dividends are expected to approximate $200 million. Also, we have $150 million of 6.49% cumulative preferred stock upon which we will pay $10 million of dividends in 2007.
 
Capital Resources and Liquidity
 
Our estimated 2007 cash uses, including our drilling and development activities, retirement of debt and repurchase of common stock, are expected to be funded primarily through a combination of operating cash flow and proceeds from the sale of our assets in Egypt and West Africa. Any remaining cash uses could be funded by increasing our borrowings under our commercial paper program or with borrowings from the available capacity under our credit facility, which was $408 million at December 31, 2006. The amount of operating cash flow to be generated during 2007 is uncertain due to the factors affecting revenues and expenses as previously cited. However, we expect our combined capital resources to be more than adequate to fund our anticipated capital expenditures and other cash uses for 2007.
 
If significant other acquisitions or other unplanned capital requirements arise during the year, we could utilize our existing credit facility and/or seek to establish and utilize other sources of financing.
 
Item 7A.   Quantitative and Qualitative Disclosures about Market Risk
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
 
Commodity Price Risk
 
Our major market risk exposure is in the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian natural gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for several years. See “Item 1A. Risk Factors.”
 
Currently, we are largely accepting the volatility risk that oil, natural gas and NGL prices present. None of our future oil production is subject to price swaps or collars. With regard to our future natural gas production, based on contracts currently in place, we will have approximately 116 MMcf per day of gas production in 2007 that is subject to either fixed-price contracts, swaps, floors or collars. This amount represents approximately 5% of our estimated 2007 gas production (3% of our total Boe production). For the years 2008 through 2011, we have fixed-price physical delivery contracts covering Canadian natural gas production ranging from seven Bcf to 14 Bcf per year. These contracts are not expected to have a material effect on our realized gas prices from 2007 through 2011.
 
Interest Rate Risk
 
At December 31, 2006, we had debt outstanding of $7.8 billion. Of this amount, $5.6 billion, or 72%, bears interest at fixed rates averaging 7.3%. Additionally, we had $1.8 billion of outstanding commercial paper


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bearing interest at floating rates which averaged 5.37% at December 31, 2006. The remaining debt consists of $400 million 4.375% senior notes due in October of 2007. Through the use of an interest rate swap, this fixed-rate debt has been converted to floating-rate debt bearing interest equal to LIBOR plus 40 basis points.
 
We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in interest rates may have on the fair value of any outstanding interest rate swap instruments. At December 31, 2006, a 10% increase in the underlying interest rates would have decreased the fair value of our interest rate swap by $2 million.
 
The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.
 
Foreign Currency Risk
 
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our December 31, 2006 balance sheet.


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Item 8.   Financial Statements and Supplementary Data
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
 
         
    Page
 
  63
Consolidated Financial Statements:
   
  64
  65
  66
  67
  68
  69
 
All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Devon Energy Corporation:
 
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
 
As described in Note 1 to the consolidated financial statements, as of January 1, 2006, the Company adopted Statements of Financial Accounting Standards No. 123(R), Share-Based Payment, and as of December 31, 2006 the Company adopted the balance sheet recognition provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R).
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Devon Energy Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
 
KPMG LLP
 
Oklahoma City, Oklahoma
February 26, 2007


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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
 
                 
    December 31,  
    2006     2005  
    (In millions, except
 
    share data)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 739       1,593  
Short-term investments
    574       680  
Accounts receivable
    1,393       1,565  
Deferred income taxes
    102       158  
Current assets held for sale
    81       66  
Other current assets
    323       144  
                 
Total current assets
    3,212       4,206  
                 
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,674 and $2,704 excluded from amortization in 2006 and 2005, respectively)
    41,889       33,824  
Less accumulated depreciation, depletion and amortization
    17,294       14,913  
                 
      24,595       18,911  
Investment in Chevron Corporation common stock, at fair value
    1,043       805  
Goodwill
    5,706       5,705  
Assets held for sale
    185       217  
Other assets
    322       429  
                 
Total assets
  $ 35,063       30,273  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable — trade
  $ 1,190       928  
Revenues and royalties due to others
    529       666  
Income taxes payable
    197       293  
Short-term debt
    2,205       662  
Accrued interest payable
    114       127  
Fair value of derivative financial instruments
    6       18  
Current portion of asset retirement obligation
    61       50  
Current liabilities associated with assets held for sale
    5       19  
Accrued expenses and other current liabilities
    338       171  
                 
Total current liabilities
    4,645       2,934  
                 
Debentures exchangeable into shares of Chevron Corporation common stock
    727       709  
Other long-term debt
    4,841       5,248  
Fair value of derivative financial instruments
    302       125  
Asset retirement obligation
    833       610  
Liabilities associated with assets held for sale
    25       40  
Other liabilities
    598       371  
Deferred income taxes
    5,650       5,374  
Stockholders’ equity:
               
Preferred stock of $1.00 par value. Authorized 4,500,000 shares; issued 1,500,000 ($150 million aggregate liquidation value)
    1       1  
Common stock of $0.10 par value. Authorized 800,000,000 shares; issued 444,040,000 in 2006 and 443,488,000 in 2005
    44       44  
Additional paid-in capital
    6,840       6,928  
Retained earnings
    9,114       6,477  
Accumulated other comprehensive income
    1,444       1,414  
Treasury stock, at cost: 11,000 shares in 2006 and 37,000 shares in 2005
    (1 )     (2 )
                 
Total stockholders’ equity
    17,442       14,862  
                 
Commitments and contingencies (Note 8)
               
Total liabilities and stockholders’ equity
  $ 35,063       30,273  
                 
 
See accompanying notes to consolidated financial statements.


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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
 
                         
    Year Ended December 31,  
    2006     2005     2004  
    (In millions, except per share amounts)  
 
Revenues:
                       
Oil sales
  $ 3,205       2,359       2,099  
Gas sales
    4,932       5,784       4,732  
NGL sales
    749       687       554  
Marketing and midstream revenues
    1,692       1,792       1,701  
                         
Total revenues
    10,578       10,622       9,086  
                         
Expenses and other income, net:
                       
Lease operating expenses
    1,488       1,324       1,259  
Production taxes
    341       335       255  
Marketing and midstream operating costs and expenses
    1,244       1,342       1,339  
Depreciation, depletion and amortization of oil and gas properties
    2,266       1,981       2,077  
Depreciation and amortization of non-oil and gas properties
    176       160       148  
Accretion of asset retirement obligation
    49       43       44  
General and administrative expenses
    397       291       277  
Interest expense
    421       533       475  
Change in fair value of derivative financial instruments
    178       94       62  
Reduction of carrying value of oil and gas properties
    121       212        
Other income, net
    (115 )     (198 )     (126 )
                         
Total expenses and other income, net
    6,566       6,117       5,810  
Earnings from continuing operations before income tax expense
    4,012       4,505       3,276  
Income tax expense:
                       
Current
    819       1,218       725  
Deferred
    370       388       370  
                         
Total income tax expense
    1,189       1,606       1,095  
                         
Earnings from continuing operations
    2,823       2,899       2,181  
Discontinued operations:
                       
Earnings from discontinued operations before income taxes
    22       46       17  
Income tax (benefit) expense
    (1 )     15       12  
                         
Earnings from discontinued operations
    23       31       5  
                         
Net earnings
    2,846       2,930       2,186  
Preferred stock dividends
    10       10       10  
                         
Net earnings applicable to common stockholders
  $ 2,836       2,920       2,176  
                         
Basic net earnings per share:
                       
Earnings from continuing operations
  $ 6.37       6.31       4.50  
Earnings from discontinued operations
    0.05       0.07       0.01  
                         
Net earnings
  $ 6.42       6.38       4.51  
                         
Diluted net earnings per share:
                       
Earnings from continuing operations
  $ 6.29       6.19       4.37  
Earnings from discontinued operations
    0.05       0.07       0.01  
                         
Net earnings
  $ 6.34       6.26       4.38  
                         
Weighted average common shares outstanding:
                       
Basic
    442       458       482  
                         
Diluted
    448       470       499  
                         
 
See accompanying notes to consolidated financial statements.


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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
 
                         
    Year Ended December 31,  
    2006     2005     2004  
    (In millions)  
 
Net earnings
  $ 2,846       2,930       2,186  
Foreign currency translation:
                       
Change in cumulative translation adjustment
    (25 )     181       426  
Income taxes
    28       (19 )     (38 )
                         
Total
    3       162       388  
                         
Derivative financial instruments:
                       
Unrealized change in fair value
          (255 )     (848 )
Reclassification adjustment for realized (gains) losses included in net earnings
    (2 )     685       635  
Income taxes
          (141 )     62  
                         
Total
    (2 )     289       (151 )
                         
Pension and postretirement benefit plans:
                       
Change in additional minimum pension liability
    30       (8 )     61  
Income taxes
    (13 )     3       (22 )
                         
Total
    17       (5 )     39  
                         
Investment in Chevron Corporation common stock:
                       
Unrealized holding gain
    238       60       132  
Income taxes
    (86 )     (22 )     (47 )
                         
Total
    152       38       85  
                         
Other comprehensive income, net of tax
    170       484       361  
                         
Comprehensive income
  $ 3,016       3,414       2,547  
                         
 
See accompanying notes to consolidated financial statements.


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DEVON ENERGY CORPORATION AND SUBSIDIARIES