UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

 

Commission File Number 001-32318

 

Devon Energy Corporation

(Exact name of Registrant as Specified in its Charter)

 

 

Registrant’s telephone number, including area code:

(405) 235-3611

 

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

 

 

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 29, 2007, was approximately $34.7 billion, based upon the closing price of $78.29 per share as reported by the New York Stock Exchange on such date. On February 15, 2008, 444,390,145 shares of common stock were outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2008 annual meeting of stockholders — Part III

 

 

DEVON ENERGY CORPORATION

 

INDEX TO FORM 10-K ANNUAL REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION

 

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.

 

“MMcfe” means million cubic feet of gas equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.

 

“NGL” or “NGLs” means natural gas liquids.

 

“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 that was used to prepare the December 31, 2007 reserve reports and other data in our

possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

 

 

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

 

 

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 that we intend to sell in 2008. 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 2007 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 low-risk part of our strategy, we also 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:

 

 

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. We have increased our total proved reserves from 8 MMBoe¹ at year-end 1987 to 2,496 MMBoe² at year-end 2007.

 

During the same time period, we have grown proved reserves from 0.66 Boe¹ per diluted share at the end of 1987 to 5.56 Boe² per diluted share at the end of 2007. This represents a compound annual growth rate of 11%. We have also increased production from 0.09 Boe¹ per diluted share in 1987 to 0.50 Boe² per diluted share in 2007, 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 West Africa that are held for sale and classified as discontinued operations as of December 31, 2007.

We achieved a number of significant accomplishments in our operations during 2007, including those discussed below.

 

 

In addition to production growth, our U.S. onshore properties also demonstrated measurable growth in proved reserves. U.S. onshore proved reserves grew 282 MMBoe due to extensions, discoveries and performance revisions. This was more than double our U.S. onshore production in 2007 of 125 MMBoe. Our drilling activities increased our 2007 U.S. onshore proved reserves by14% compared to the end of 2006.

 

 

Specific Gulf of Mexico developments in 2007 included the following:

 

 

 

 

In November 2006 and January 2007, we announced plans to divest our operations in Egypt and West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region. 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.

 

In October 2007, we completed the sale of our operations in Egypt and received proceeds of $341 million. As a result of this sale, we recognized a $90 million after-tax gain in the fourth quarter of 2007. In November 2007, we announced an agreement to sell our operations in Gabon for $205.5 million. We are finalizing purchase and sales agreements and obtaining the necessary partner and government approvals for the remaining properties in the West African divestiture package. We are optimistic we can complete these sales during the first half of 2008.

 

Pursuant to accounting rules for discontinued operations, the amounts in this document related to continuing operations for 2007 and all prior years presented do not include amounts related to our operations in Egypt and West Africa.

 

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, Natural Gas and NGL Marketing

 

The spot market for oil, gas and NGLs is subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) or short-term (less than one year) agreements. Regardless of the term of the contract, the vast majority of our production is sold at variable or market sensitive prices.

 

Additionally, we may periodically enter into financial hedging arrangements, 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. As of February 2008, 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 2008, approximately 81% 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 17% 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. The remaining 2% of our gas production was sold under long-term fixed price contracts.

 

NGL Marketing

 

Our NGL production is sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary, as of February 2008, approximately 69% of our NGL production was sold under short-term contracts at variable or market-sensitive prices. The remaining NGL production is sold under long-term market-indexed contracts which are subject to market pricing variations.

 

Marketing and Midstream Activities

 

The primary objective of our marketing and midstream operations is to add value to us and other producers to whom we provide such services by gathering, processing and marketing oil, gas and NGL production in a timely and efficient manner. Our most significant midstream asset is the Bridgeport processing plant and gathering system located in north Texas. These facilities serve not only our gas production from the Barnett Shale but also gas production of other producers in the area. Our midstream assets also include our 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our Jackfish heavy oil production with condensate and then transport the combined product to the Edmonton area.

 

Our marketing and midstream revenues are primarily generated by:

 

 

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

 

 

Customers

 

We sell our gas production to a variety of customers including pipelines, utilities, gas marketing firms, industrial users and local distribution companies. Gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries.

 

The principal customers for our crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked or shipped to storage, refining or pipeline facilities.

 

Our NGL production is primarily sold to customers engaged in petrochemical, refining and heavy oil blending activities. Pipelines, railcars and trucks are utilized to move our products to market.

 

No purchaser accounted for over 10% of our revenues in 2007, 2006 or 2005.

 

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 this 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. Because 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.

 

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 that 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.

 

On October 25, 2007, the provincial government of Alberta announced a new royalty regime. The new regime contemplates the introduction of new royalties for conventional oil, natural gas, NGL and bitumen production effective January 1, 2009. The royalties will be linked to price and production levels and will apply to both new and existing conventional oil and gas activities and oil sands projects.

 

The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to the existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. Finally, the proposed royalty structure may be modified prior to its implementation.

 

We believe this proposal would reduce future earnings and cash flows from our oil and gas properties located in Alberta. Additionally, assuming all other factors are equal, higher royalty rates would likely result in lower levels of capital investment in Alberta relative to our other areas of operations. However, the magnitude of the potential impact, which will depend on the final form of enacted legislation and other factors that impact the relative expected economic returns of capital projects, cannot be reasonably estimated at this time.

 

Pricing and Marketing in 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 permit from Canada’s National Energy Board (“NEB”). The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere.

 

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 agency 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 as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things, assessing the environmental impact of seismic acquisition, drilling or construction activities; the generation, storage, transportation and disposal of waste materials; the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and the development of emergency response and spill contingency plans.

The application of worldwide standards, such as ISO 14000 governing Environmental Management Systems, is required to be implemented for some international oil and gas operations.

 

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 16, 2005, and requires reductions of certain emissions that contribute to atmospheric levels of greenhouse gases (“GHG”). Certain countries in which we operate (but not the United States) have ratified the Protocol. Pursuant to its ratification of the Protocol in April 2007, the federal government of Canada released its Regulatory Framework for Air Emissions, a plan to implement mandatory reductions in GHG emissions by way of regulation under existing legislation. The mandatory reductions on GHG emissions will create additional costs for the Canadian oil and gas industry. Certain provinces in Canada have also implemented legislation and regulations to reduce GHG emissions, which will also have a cost associated with compliance. Presently, it is not possible to accurately estimate the costs we could incur to comply with any laws or regulations developed to achieve emissions reductions in Canada or elsewhere, but such expenditures could be substantial.

 

In 2006, we published our Corporate Climate Change Position and Strategy. Key components of the strategy include initiation of energy efficiency measures, tracking emerging climate change legislation and publication of a corporate GHG emission inventory, which occurred in January 2008. All provisions of the strategy are completed or 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 2007 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, 2007, we had approximately 5,000 employees. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.

 

Competition

 

See “Item 1A. Risk Factors.”

 

Availability of Reports

 

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

 

Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

 

Oil, 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:

 

 

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 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:

 

 

A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on our future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. We are currently performing exploratory drilling activities in certain international countries. We have been granted drilling concessions in these countries that require commitments on our behalf to incur capital expenditures. Even if future drilling activities are unsuccessful in establishing proved reserves, we will likely be required to fulfill our commitments to make such capital expenditures.

 

Industry Competition For Leases, Materials, People and Capital Can Be Significant

 

Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Higher recent commodity prices have increased drilling and operating costs. 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 and China. We also have operations in various countries in West Africa that we intend to sell in 2008. In these areas outside of North America, we face political and economic risks and other uncertainties that are more prevalent than what exist for our operations in North America. Such factors include, but are not limited to:

 

 

Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. 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, 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 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 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 insurance 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.

 

Our Short-Term Investments Are Subject To Risks Which May Affect Their Liquidity and Value

 

To maximize earnings on available cash balances, we periodically invest in securities that we consider to be short-term in nature and generally available for short-term liquidity needs. Such investments include asset-backed securities that have an auction rate reset feature (“auction rate securities”). Our auction rate securities are collateralized by student loans which are substantially guaranteed by the United States government, and generally have contractual maturities of more than 20 years. However, the underlying interest rates on such securities are scheduled to reset every 28 days. Therefore, these auction rate securities are generally priced and subsequently trade as short-term investments because of the interest rate reset feature.

 

At December 31, 2007, we held $372 million of auction rate securities. Subsequent to December 31, 2007, we have reduced our auction rate securities holdings to $153 million. However, beginning on February 8, 2008, we experienced difficulty selling additional securities due to the failure of the auction mechanism which provides liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every 28 days until the auction succeeds, the issuer calls the securities or the securities mature. Accordingly, there may be no effective mechanism for selling these securities.

 

All of our auction rate securities, including those subject to failed auctions, are currently rated AAA — the highest rating — by one or more rating agencies. However, these investments are subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by continued problems in the global credit markets, including but not limited to, U.S. subprime mortgage defaults, writedowns by major financial institutions due to deteriorating values of their asset portfolios (including leveraged loans, collateralized debt obligations, credit default swaps and other credit-linked products). These and other related factors have affected various sectors of the financial markets and caused credit and liquidity issues. If issuers are unable to successfully close future auctions and their credit ratings deteriorate, our ability to liquidate these securities and fully recover the carrying value of our investment in the near term may be limited. As a result, we may deem such investments to be long-term in nature and generally not available for short-term liquidity needs. Additionally, under such circumstances, we may record an impairment charge on these investments in the future.

 

Not applicable.

 

 

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 750 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator. To support our production in the Woodford Shale, located in southeast Oklahoma, we plan to bring online a 200 MMcf per day gas processing plant in 2008.

 

Our midstream assets also include the Access Pipeline transportation system in Canada. This 220-mile dual pipeline system extends from our Jackfish operations in northern Alberta to a 350 MBbls storage terminal in Edmonton. The dual pipeline system allows us to blend the Jackfish heavy oil production with condensate and transport the combined product to the Edmonton crude oil market. We have a 50% ownership interest in the Access Pipeline.

 

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 that 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 compliance in 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 the internal review and certification of reserves estimates and includes the Manager — Reserves and Economics and the Senior Advisor — Corporate Reserves. The Group reports independently of any of our operating divisions. The Vice President — Strategic Planning is directly responsible for overseeing the Group and reports to our President. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.

 

Throughout the year, the Group performs internal audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below.

 

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 2007 reserves estimates for all our offshore Gulf of Mexico properties and for 99% of our International proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2007 reserves estimates for 88% of our domestic onshore

properties. AJM Petroleum Consultants prepared estimates covering 34% of our 2007 Canadian reserves and audited an additional 51% of our Canadian reserves.

 

Set forth below is a summary of the reserves that were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2007, 2006 and 2005.

 

 

“Prepared” reserves are those quantities of reserves that were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.

 

In addition to conducting these internal and external reviews, we also have a Reserves Committee which consists of four independent members of our Board of Directors. Although we are not required to have a Reserves Committee, we established ours in 2004 to provide additional oversight of our reserves estimation and certification process. The Reserves Committee was designed to assist the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.

 

The Reserves Committee meets at least twice a year to discuss reserves issues and policies, and periodically meets separately with our senior reserves engineering personnel and our independent petroleum consultants. The responsibilities of the Reserves Committee include the following:

 

 

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, 2007. 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.

 

 

 

 

As presented in the previous table, we had 1,874 MMBoe of proved developed reserves at December 31, 2007. 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, 2007.

 

 

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 2007 except in filings with the SEC and the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of our reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.

 

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, 2007. 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, 2007, 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 or West African operations that were discontinued in 2006 and 2007, respectively.

 

Development Well Activity

 

 

Exploratory Well Activity

 

 

 

 

For the wells being drilled as of December 31, 2007 presented in the tables above, the following table summarizes the results of such wells as of February 1, 2008.

 

Well Statistics

 

The following table sets forth our producing wells as of December 31, 2007. The table does not include our West African operations that were discontinued in 2007.

 

 

 

 

Developed and Undeveloped Acreage

 

The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2007. The table does not include our West African operations that were classified as discontinued in 2007.

 

 

 

 

Operation of Properties

 

The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions.

 

We are the operator of 21,226 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, 2007, along with their production volumes for the year 2007. Included in the table are certain U.S. offshore properties that currently have no proved reserves or production. Such properties are considered significant because they may be the source of significant future growth in proved reserves and production. The table does not include our West African operations that were classified as discontinued in 2007. Additional summary profile information for our significant properties is provided following the table.

 

 

 

 

U.S. Onshore

 

Barnett Shale — The Barnett Shale, located in north Texas, is our largest property both in terms of production and proved reserves. Our leases include approximately 727,000 net acres located primarily in

Denton, Johnson, Parker, Tarrant and Wise counties. The Barnett Shale is a non-conventional reservoir and it produces natural gas and NGLs. We have an average working interest of greater than 90%. We drilled 539 gross wells in 2007 and expect to drill between 500 and 600 gross wells in 2008.

 

Carthage — The Carthage area in east Texas includes primarily Harrison, Marion, Panola and Shelby counties. Our average working interest is about 85% and we hold approximately 131,000 net acres. Our Carthage area wells produce primarily natural gas and NGLs from conventional reservoirs. We drilled 152 gross wells in 2007 and plan to drill approximately 122 gross wells in 2008.

 

Permian Basin, Texas — Our oil and gas properties in the Permian Basin of west Texas comprise approximately 464,000 net acres located primarily in Andrews, Crane, Martin, Terry, Ward and Yoakum counties. These properties produce both oil and natural gas from conventional reservoirs. Our average working interest in these properties is about 40%. We drilled 77 gross wells in 2007 and plan to drill approximately 38 gross wells in the area in 2008.

 

Washakie — Our Washakie area leases are concentrated in Carbon and Sweetwater counties in southern Wyoming. Our average working interest is about 76% and we hold about 157,000 net acres in the area. The Washakie wells produce primarily natural gas from conventional reservoirs. In 2007, we drilled 161 gross wells, and we plan to drill approximately 111 gross wells in 2008.

 

Groesbeck — The Groesbeck area of east Texas includes portions of Freestone, Leon, Limestone and Robertson counties. Our average working interest is approximately 72% and we hold about 172,000 net acres of land. The Groesbeck wells produce primarily natural gas from conventional reservoirs. In 2007, we drilled 21 gross wells, and we anticipate drilling approximately 16 additional gross wells in 2008.

 

Permian Basin, New Mexico — Our Permian Basin properties in southeastern New Mexico produce conventional oil and natural gas. We hold about 286,000 net acres concentrated in Eddy and Lea counties and have an average working interest of about 75% in these properties. In 2007, we drilled 78 gross wells in this area, and we expect to drill approximately 94 gross wells in 2008.

 

U.S. Offshore

 

Deepwater Producing — Our assets in the Gulf of Mexico include four significant producing properties — Magnolia, Merganser, Nansen and Red Hawk — located in deep water (greater than 600 feet). We have a 50% working interest in these properties. They are located on federal leases and total approximately 46,000 net acres. The properties produce both oil and natural gas.

 

Deepwater Development — In addition to our four significant deepwater producing properties, we are in the process of developing our deepwater Cascade project discovered in 2002. Cascade is located on federal leases encompassing approximately 12,000 net acres. We have a 50% working interest in Cascade. In 2007, we sanctioned development plans and awarded various service and facility contracts including contracts for an FPSO and shuttle tankers. The first of two development wells is planned for 2008. Production from Cascade, which will be primarily oil, is expected to begin in 2010.

 

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 one million net acres in our deepwater exploration inventory.

 

In 2006, a successful production test of the Jack No. 2 well provided evidence that our Lower Tertiary properties may be a source of meaningful future reserve and production growth. Through 2007, we have drilled four discovery wells in the Lower Tertiary. These include Cascade in 2002 (see “Deepwater Development” above), St. Malo in 2003, Jack in 2004 and Kaskida in 2006. We currently hold 194 blocks in the Lower Tertiary and we have identified 21 additional prospects to date.

 

At St. Malo, in which our working interest is 22.5%, we expect to complete two delineation wells in 2008. At Jack, where our working interest is 25%, we expect to complete a second appraisal well in early 2008. A second well (Cortez Bank) was drilled on the Kaskida unit in 2007 and other well operations are

planned for 2008. 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. Of our additional 21 Lower Tertiary exploration prospects we have identified, 15 are on our Keathley Canyon acreage.

 

Also in 2007, we participated in a delineation well on the Miocene-aged Mission Deep prospect in which we have a 50% working interest. We have identified 15 additional prospects in our deepwater Miocene inventory to date.

 

In total, we drilled one exploratory and one delineation well in the deepwater Gulf of Mexico in 2007 and plan to drill between 10 and 12 such wells in 2008. Our working interests in these exploratory opportunities range from 20% to 50%.

 

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 are employing steam-assisted gravity drainage at Jackfish, and we began steam injection in the third quarter of 2007. Production is expected to ramp up throughout 2008 toward a peak production target of 35,000 Bbls per day . We hold approximately 73,000 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. In 2007, we began front-end engineering and design work on this extension of the Jackfish project. We hope to receive regulatory approval and formally sanction this second phase in the middle of 2008. Like the first phase, this second phase of Jackfish is also expected to eventually produce 35,000 Bbls per day of heavy oil production.

 

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 2007, we drilled 429 gross wells in the area and plan to drill approximately 475 gross wells in 2008.

 

Deep Basin — Our properties in Canada’s Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 609,000 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 Deep Basin is 45%. In 2007, we drilled 41 gross wells and plan to drill approximately 49 gross wells in the area in 2008.

 

Peace River Arch — The Peace River Arch is located in west central Alberta. We hold approximately 494,000 net acres in the area, which produces primarily natural gas and NGLs from conventional reservoirs. Our average working interest in the area is approximately 70%. We drilled 60 gross wells in the Peace River Arch in 2007, and we expect to drill approximately 65 additional gross wells in 2008.

 

Northeast British Columbia — Our northeast British Columbia properties are located primarily in British Columbia and to a lesser extent in northwestern 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 2007, and we plan to drill approximately 37 gross wells in 2008.

 

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. 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 2007, we participated in drilling 11 gross wells, and we expect to drill approximately 16 gross wells in 2008.

China — Our production in China is from the Panyu development in the Pearl River Mouth Basin in the South China Sea. Panyu fields produce oil from conventional reservoirs. In addition to Panyu, which is located on Block 15/34, we hold leases in four exploratory blocks offshore China. In total, we have 7.9 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 three gross wells in China in 2007, all in the Panyu field. In 2008, we expect to drill approximately six gross wells in the Panyu field, one exploratory well on Block 42/05 and one exploratory well on Block 11/34.

 

Brazil — We commenced oil production in Brazil from our Polvo development area in 2007. Polvo, which we operate with a 60% interest, is located offshore in the Campos Basin in Block BM-C-8. In addition to our development project at Polvo, we hold acreage in eight exploratory blocks. In aggregate, we have 793,000 net acres in Brazil. Our working interests range from 18% to 100% in these blocks. We drilled three gross wells in Brazil in 2007 and plan to drill approximately eight gross wells in 2008.

 

Title to Properties

 

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.

 

As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, which generally include a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

 

 

Royalty Matters

 

Numerous gas producers and related parties, including us, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. The principal suit in which we are 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 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 April 12, 2007, the court entered a trial plan and scheduling order in which the case will proceed in phases. Two phases have been scheduled to date, with the first scheduled to begin in August 2008 and the second scheduled to begin in February 2009. We are not included in the groups of defendants selected for these first two phases. We believe that 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.

 

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.

 

 

There were no matters submitted to a vote of security holders during the fourth quarter of 2007.

 

 

Our common stock is traded on the New York Stock Exchange (the “NYSE”). On February 15, 2008, there were 15,923 holders of record of our common stock. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE during 2006 and 2007. Also, included are the quarterly dividends per share paid during 2006 and 2007.

 

 

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

 

The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2007.

 

 

 

 

 

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.”

 

 

 

 

 

Introduction

 

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be reviewed in conjunction with our “Selected Financial Data” and “Financial Statements and Supplementary Data.” Our discussion and analysis relates to the following subjects:

 

 

Overview of Business

 

Devon is the largest U.S. based independent oil and gas producer and processor 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. Over 90 percent of our production from continuing operations is from North America. We also operate in selected international areas, including Azerbaijan, Brazil and China. Our production mix in 2007 was 64 percent natural gas and 36 percent oil and NGLs such as propane, butane and ethane. We are currently producing 2.4 Bcf 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.

 

 

Overview of 2007 Results and Outlook

 

2007 was Devon’s best year in its 20-year history as a public company. 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, earnings per share and operating cash flow, and also grew proved reserves to a new all-time high. Key measures of our financial and operating performance for 2007, as well as certain operational developments, are summarized below:

 

 

Operating costs increased due to the 12% growth in production, inflationary pressure driven by increased competition for field services and the weakened U.S. dollar compared to the Canadian dollar. Per unit lease operating expenses increased 15% to $8.16 per Boe.

 

During 2007, we used $6.2 billion of cash flow from continuing operations along with other capital resources to fund $6.2 billion of capital expenditures, reduce debt obligations by $567 million, repurchase $326 million of our common stock and pay $259 million in dividends to our stockholders. We also ended the year with $1.7 billion of cash and short-term investments.

 

From an operational perspective, we completed another successful year with the drill-bit. We drilled 2,440 wells with an overall 98% rate of success. This success rate enabled us to increase our proved reserves by 9% to a record of 2.5 billion Boe at the end of 2007. We added 390 MMBoe of proved reserves during the year with extensions, discoveries and performance revisions, which was well in excess of the 224 MMBoe we produced during the year. Consistent with our two-pronged operating strategy, 92% of the wells we drilled were North American development wells.

 

Besides completing another successful year of drilling, we also had several other key operational achievements during 2007. In the Gulf of Mexico, we continued to build off prior years’ successful drilling results with our deepwater exploration and development program. We commenced production from the Merganser field, and we also began drilling our first operated exploratory well in the Lower Tertiary trend of the Gulf of Mexico. We also made progress toward commercial development of our four previous discoveries in the Lower Tertiary trend.

 

At our 100%-owned Jackfish thermal heavy oil project in the Alberta oil sands, we completed construction and commenced steam injection. Oil production from Jackfish is expected to ramp up throughout 2008 toward a peak production target of 35,000 Bbls per day. Additionally, we began front-end engineering and design work on an extension of our Jackfish project. Like the first phase, this second phase of Jackfish is also expected to eventually produce 35,000 Bbls per day.

 

Finally, we completed construction and fabrication of the Polvo oil development project offshore Brazil and began producing oil from the first of ten planned wells. Polvo, located in the Campos basin, was discovered in 2004 and is our first operated development project in Brazil.

In November 2006 and January 2007, we announced plans to divest our operations in Egypt and West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region. 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.

 

In October 2007, we completed the sale of our operations in Egypt and received proceeds of $341 million. As a result of this sale, we recognized a $90 million after-tax gain in the fourth quarter of 2007. In November 2007, we announced an agreement to sell our operations in Gabon for $205.5 million. We are finalizing purchase and sales agreements and obtaining the necessary partner and government approvals for the remaining properties in the West African divestiture package. We are optimistic we can complete these sales during the first half of 2008 and then primarily use the proceeds to repay our outstanding commercial paper and revolving credit facility borrowings and resume common stock repurchases.

 

Looking to 2008, we announced in February 2008 that we have hedged a meaningful portion of our expected 2008 production with financial price collar and swap arrangements. As of February 15, 2008, approximately 62% of our expected 2008 gas production is subject to either price collars with a floor price of $7.50 per MMBtu and an average ceiling price of $9.43 per MMBtu, or price swaps with an average price of $8.24 per MMBtu. Another 2% of our expected 2008 gas production is subject to fixed-price physical contracts. Also, as of February 15, 2008, approximately 12% of our expected 2008 oil production is subject to price collars with a floor price of $70.00 per barrel and an average ceiling price of $140.23 per barrel.

 

Additionally, our operational accomplishments in recent years have laid the foundation for continued growth in future years, at competitive unit costs, which we expect will continue to create additional value for our investors. In 2008, we expect to deliver proved reserve additions of 390 to 410 million Boe with related capital expenditures in the range of $6.1 to $6.4 billion. We expect production to increase approximately 9% from 2007 to 2008, which reflects our significant reserve additions in recent years as well as those expected in 2008. Additionally, our exploration program exposes us to high-impact projects in North America and international locations that can fuel more growth in the years to come.

 

Results of Operations

 

Revenues

 

Changes in oil, gas and NGL production, prices and revenues from 2005 to 2007 are shown in the following tables. The amounts for all periods presented exclude results from our Egyptian and West African

operations which are presented as discontinued operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.