Devon Energy 10-K 2009
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission File Number 001-32318
Registrants telephone number, including area code:
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
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 (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrants 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, 2008, was approximately $53.0 billion, based upon the closing price of $120.16 per share as reported by the New York Stock Exchange on such date. On February 16, 2009, 443.8 million shares of common stock were outstanding.
Proxy statement for the 2009 annual meeting of stockholders Part III
DEVON ENERGY CORPORATION
As used in this document:
Bbl or Bbls means barrel or barrels.
Bcf means billion cubic feet.
Bcfe means billion cubic feet of gas equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
Boe means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
Btu means British thermal units, a measure of heating value.
Canada means the division of Devon encompassing oil and gas properties located in Canada.
Domestic means the properties of Devon in the onshore continental United States and the offshore Gulf of Mexico.
Federal Funds Rate means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.
FPSO means floating, production, storage and offloading facilities.
Inside FERC refers to the publication Inside F.E.R.C.s Gas Market Report.
International means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.
LIBOR means London Interbank Offered Rate.
MBbls means thousand barrels.
MBoe means thousand Boe.
Mcf means thousand cubic feet.
MMBbls means million barrels.
MMBoe means million Boe.
MMBtu means million Btu.
MMcf means million cubic feet.
MMcfe means million cubic feet of gas equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
NGL or NGLs means natural gas liquids.
NYMEX means New York Mercantile Exchange.
Oil includes crude oil and condensate.
SEC means United States Securities and Exchange Commission.
U.S. Offshore means the properties of Devon in the Gulf of Mexico.
U.S. Onshore means the properties of Devon in the continental United States.
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All
statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare the December 31, 2008 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.
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. In addition to our oil and gas operations, we have marketing and midstream operations primarily in North America. These include marketing gas, crude oil and NGLs, and constructing and operating pipelines, storage and treating facilities and natural gas processing plants. A detailed description of our significant properties and associated 2008 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).
We have a two-pronged operating strategy. First, we invest a significant portion of our capital budget in low-risk 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 capital in 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:
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 2,428 MMBoe at year-end 2008.
During the same time period, we have grown proved reserves from 0.66 Boe1 per diluted share at the end of 1987 to 5.44 Boe per diluted share at the end of 2008. This represents a compound annual growth rate of 11%. We have also increased production from 0.09 Boe1 per diluted share in 1987 to 0.53 Boe per diluted share in 2008, 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.
We achieved a number of significant accomplishments in our operations during 2008, including those discussed below.
1 Excludes the effects of mergers in 1998 and 2000 that were accounted for as poolings of interests.
We also completed construction and commenced operation of our Northridge natural gas processing plant in southeastern Oklahoma. This plant can process up to 200 MMcf of natural gas per day and will support our growing production in the Woodford Shale.
We have also leveraged our knowledge of and expertise in the Barnett Shale into other unconventional natural gas plays, such as the Haynesville shale in eastern Texas and western Louisiana, the Cana shale play in western Oklahoma and the Cody play in Montana. We added approximately 800,000 net undeveloped acres to our lease inventory, positioning us with more than 1.4 million net acres in emerging unconventional natural gas plays.
In addition to production growth, our U.S. onshore properties also demonstrated measurable growth in proved reserves. U.S. onshore proved reserves grew 416 MMBoe due to extensions, discoveries and performance revisions. This was almost three times our U.S. onshore production in 2008 of 146 MMBoe. Our drilling activities increased our 2008 U.S. onshore proved reserves by 27% compared to the end of 2007.
Pursuant to accounting rules for discontinued operations, the amounts in this document related to continuing operations for 2008 and all prior years presented do not include amounts related to our operations in Egypt and West Africa.
Specific Gulf of Mexico developments in 2008 included the following:
Notes 18 and 20 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.
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) or short-term (less than one year) agreements. Regardless of the term of the contract, the vast majority of our production is sold at variable or market sensitive prices.
Additionally, we may periodically enter into financial hedging arrangements, 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.
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 2009, all of our oil production was sold at variable or market-sensitive prices.
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 2009, approximately 75% of our gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as spot market sales. Another 24% of our production was committed under various long-term contracts, which dedicate the gas to a purchaser for an extended period of time, but still at market sensitive prices. The remaining 1% of our gas production was sold under long-term, fixed-price contracts.
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 2009, approximately 97% 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.
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 for sale.
Our marketing and midstream revenues are primarily generated by:
Our marketing and midstream costs and expenses are primarily incurred from:
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 2008, 2007 or 2006.
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.
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 and financial strength.
The following are significant areas of government control and regulation in the United States, Canada and other international locations in which we operate.
Our oil and gas operations are subject to various federal, state, provincial, tribal, local and international laws and regulations, including, but not limited to, laws and regulations related to the acquisition of seismic data; the location of wells; drilling and casing of wells; well production; spill prevention plans; emissions permitting; 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 gas wells; and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.
Certain of our U.S. oil and 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.
The royalty system in Canada is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada 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.
In December 2008, the provincial government of Alberta enacted a new royalty regime. The new regime provides for new royalties for conventional oil, gas, NGL and bitumen production effective January 1, 2009. The royalties are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects.
This royalty regime reduced our proved reserves as of December 31, 2008 by 28 MMBoe. Additionally, this regime is expected to reduce future earnings and cash flows from our oil and gas properties located in Alberta. The actual effect on our future earnings and cash flows of this royalty regime will be determined based on, among other things, our production rates from wells in Alberta, the proportion of our Alberta production to our overall production, our product mix in Alberta, commodity prices and foreign exchange rates.
Any oil or 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 Canadas 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.
The Investment Canada Act requires federal 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.
Some of our international licenses are governed by production sharing contracts (PSCs) between the concessionaires and the granting government agency. PSCs are contracts that define and regulate the framework for investments, revenue sharing, and taxation of mineral interests in foreign countries. Unlike most domestic leases, PSCs have defined production terms and time limits of generally 30 years. PSCs also generally contain sliding scale revenue sharing provisions. As a result, at either higher production rates or higher cumulative rates of return, PSCs generally allow the government agency to retain higher fractions of revenue.
We are subject to various federal, state, provincial, tribal, local and international laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things, assessing the environmental impact of seismic acquisition, drilling or construction activities; the generation, storage, transportation and disposal of waste materials; the emission of certain gases into the atmosphere; the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and the development of emergency response and spill contingency plans. The application of worldwide standards, such as ISO 14000 governing Environmental Management Systems, is required to be implemented for some international oil and gas operations.
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. Devon continues to explore energy efficiency measures and greenhouse gas emission reduction opportunities. We also continue to monitor legislative and regulatory climate change developments. 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, 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 and safety and health compliance. While our unreimbursed expenditures in 2008 attributable to 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.
As of December 31, 2008, we had approximately 5,500 employees. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.
See Item 1A. Risk Factors.
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.
Our financial results are highly dependent on the prices of and demand for oil, gas and NGLs. A significant downward movement of the prices for these commodities could have a material adverse effect on our revenues, operating cash flows and profitability. Such a downward price movement could also have a material adverse effect on our estimated proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Historically, prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:
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 rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase, due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies, identify additional producing zones in existing wells, secondary recovery reserves or tertiary recovery reserves, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL
production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
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.
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the costs of properties available for acquisition. Certain of our competitors have financial and other resources substantially larger than ours, 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 gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels, and the application of government regulations.
Our operations outside North America are based primarily in Azerbaijan, Brazil and China. We face political and economic risks and other uncertainties in these areas that are more prevalent than what exist for our operations in North America. Such factors include, but are not limited to:
Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting managements attention from our more significant assets. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. This could adversely affect our interests and our future profitability.
The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.
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, tribal 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.
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal, local and international laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have a significant impact on our operations and profitability.
Exploration, development, production and processing of oil, gas and NGLs can be hazardous and involve unforeseen occurrences such as hurricanes, blowouts, cratering, fires and loss of well control. These occurrences can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. We maintain insurance against certain losses or liabilities in accordance with customary industry practices and in amounts that management believes to be prudent. However, insurance against all operational risks is not available to us. Due to changes in the insurance marketplace following hurricanes in the Gulf of Mexico in recent years, we currently do not have coverage for any damage that may be caused by future named windstorms in the Gulf of Mexico.
To maximize earnings on available cash balances, we periodically invest in securities that we consider to be short-term in nature and generally available for short-term liquidity needs. During 2007, we purchased asset-backed securities that have an auction rate reset feature (auction rate securities). Our auction rate securities generally have contractual maturities of more than 20 years. However, the underlying interest rates on our securities are scheduled to reset every seven to 28 days. Therefore, when we bought these securities, they were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. At December 31, 2008, our auction rate securities totaled $122 million.
Since February 8, 2008, we have experienced difficulty selling our securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature. Due to continued auction failures throughout 2008, we consider these investments to be long-term in nature and generally not available for short-term liquidity needs.
Our auction rate securities are rated AAA the highest rating by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. These investments are subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by 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. Under such circumstances, we may record an impairment charge on these investments in the future.
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, gas and NGLs from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral and net profits interests, foreign government concessions and other forms of direct and indirect ownership in oil and gas properties.
We also have certain midstream assets, including natural gas and NGL processing plants and pipeline systems. Our most significant midstream assets are our assets serving the Barnett Shale region in north Texas. These assets include approximately 3,100 miles of pipeline, two natural gas processing plants with 750 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator. To support our continued development and growing production in the Woodford Shale, located in southeastern Oklahoma, we constructed the Northridge natural gas processing plant in 2008. The Northridge plant has a capacity of 200 MMcf per day.
Our midstream assets also include the Access Pipeline transportation system in Canada. This 220-mile dual pipeline system extends from our Jackfish operations in northern Alberta to a 350 MBbls storage terminal 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 for sale. 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, 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. Existing economic and operating conditions is defined as those 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. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the Group) and 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 reserve estimates and includes the Director Reserves and Economics and the Senior Advisor Corporate Reserves. The Group reports independently of any of our operating divisions. The Senior Vice President Strategic Development is directly responsible for overseeing the Group and reports to our President. No portion of the Groups compensation is directly dependent on the quantity of reserves booked.
Throughout the year, the Group performs internal audits of each operating divisions 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 2008 reserve estimates for all of our offshore Gulf of Mexico properties and for 99% of our International proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2008 reserve estimates for 90% of our domestic onshore properties. AJM Petroleum Consultants audited 78% 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 2008, 2007 and 2006.
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 companys 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 three independent members of our Board of Directors. Although we are not required to have a Reserves Committee, we established ours in 2004 to provide additional oversight of our reserves estimation and certification process. The Reserves Committee was designed to assist the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.
The Reserves Committee meets at least twice a year to discuss reserves issues and policies, and periodically meets separately with our senior reserves engineering personnel and our independent petroleum consultants. The responsibilities of the Reserves Committee include the following:
The following table sets forth our estimated proved reserves and related estimated cash flow information as of December 31, 2008. These estimates correspond with the method used in presenting the Supplemental Information on Oil and Gas Operations in Note 20 to our consolidated financial statements included herein.
As presented in the previous table, we had 1,934 MMBoe of proved developed reserves at December 31, 2008. 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, 2008.
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 2008 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, 2008. 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.
Certain information concerning oil, 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, 2008, is set forth in Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
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.
Exploratory Well Activity
For the wells being drilled as of December 31, 2008 presented in the tables above, the following table summarizes the results of such wells as of February 1, 2009.
The following table sets forth our producing wells as of December 31, 2008.
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2008.
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 22,527 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, 2008, along with their production volumes for the year 2008. Additional summary profile information for our significant properties is provided following the table.
We have certain North American onshore and offshore properties we consider to be significant because they may be the source of significant future growth in proved reserves and production. However, these
properties are not included in the following table because as of December 31, 2008, such properties had only minimal, if any, proved reserves or production. Onshore, these properties include the Haynesville, Cana and Cody properties in the U.S. and the Horn River Basin properties in Canada. Offshore, these properties include our deepwater development and exploration properties in the Gulf of Mexico. These properties and our related development plans are discussed along with our other significant properties following the table.
Also, as presented in the table, we had no proved reserves associated with our Jackfish operations as of December 31, 2008. During 2008 and thus far in 2009, we have been producing heavy oil from our Jackfish property. However, due to low crude oil prices and unfavorable operating conditions as of December 31, 2008, our Jackfish reserves did not meet the existing economic and operating condition requirement to be classified as proved at the end of 2008.
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 715,000 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 659 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 173,000 net acres. Our Carthage area wells produce primarily natural gas and NGLs from conventional reservoirs. We drilled 132 gross wells in 2008.
Permian Basin, Texas Our oil and gas properties in the Permian Basin of west Texas comprise approximately 470,000 net acres located primarily in Andrews, Crane, Ector, Martin, Terry, Ward and Yoakum counties. These properties produce both oil and gas from conventional reservoirs. Our average working interest in these properties is about 40%. We drilled 71 gross wells 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 2008, we drilled 115 gross wells.
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 168,000 net acres of land. The Groesbeck wells produce primarily natural gas from conventional reservoirs. In 2008, we drilled 16 gross wells.
Woodford Shale Our Woodford Shale properties in southeastern Oklahoma produce natural gas and NGLs from a non-conventional reservoir. Our 54,000 net acres are concentrated in Coal and Hughes counties and have an average working interest of about 57%. In 2008, we drilled 131 gross wells in this area. To support our production in the Woodford Shale, we also brought online a 200 MMcf per day natural gas processing plant in 2008.
2009 Development Plans We expect 2009 oil, gas and NGL prices will be noticeably lower than those for 2008. As a result, we expect our operating cash flow will also be lower than that for 2008 and will require us to scale back our anticipated capital expenditures in 2009 compared to 2008. Accordingly, we expect to drill fewer wells in 2009 than in 2008 for the key U.S. Onshore areas discussed above.
Our reduction in 2009 drilling activities in these areas is also related to our plan to devote a portion of our planned 2009 capital expenditures to develop three new unconventional natural gas plays. In 2008, we built a position of nearly 1.3 million net acres in these unconventional natural gas plays. In east Texas and north Louisiana we have accumulated approximately 570,000 net acres prospective for the Haynesville shale formation. In western Oklahoma, our Cana leasehold position targets the deep Woodford shale formation in the Anadarko Basin. We hold about 112,000 net acres in the Cana area. In south central Montana, we have accumulated a significant leasehold position for our Cody project area. We hold approximately 575,000 net acres in this region. In 2009, we will continue to evaluate our acreage and drill wells in these emerging plays to assess the reserve and production potential of our acreage position.
Deepwater Producing Our assets in the Gulf of Mexico include three significant producing properties Magnolia, Merganser and Nansen located in deep water (greater than 600 feet). We have a 50% working interest in Merganser and Nansen and a 25% working interest in Magnolia. The three fields are located on federal leases and total approximately 23,000 net acres. The properties produce both oil and gas.
Deepwater Development In addition to our three significant deepwater producing properties, we will continue development activities on our deepwater Cascade project throughout 2009. Cascade was discovered in 2002 and is located on federal leases encompassing approximately 12,000 net acres. We have a 50% working interest in Cascade. Production from Cascade, which will be primarily oil, is expected to begin in 2010. Cascade will be the first project in the Gulf to utilize an FPSO.
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 2008, 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 161 blocks in the Lower Tertiary and we have identified 21 additional prospects to date.
At St. Malo, in which our working interest is 25%, we drilled two delineation wells in 2008. At Jack, where our working interest is 25%, we drilled a second appraisal well in 2008. A sidetrack appraisal well was drilled on the Kaskida unit in 2008 and we commenced an additional delineation well in late 2008. Our working interest in Kaskida is 30%, and we believe Kaskida is the largest of our four Lower Tertiary discoveries to date.
Also in 2008, we participated in a sidetrack delineation well on the Miocene-aged Mission Deep discovery in which we have a 50% working interest. We have identified 14 additional prospects in our deepwater Miocene inventory to date.
In total, we drilled seven exploratory and appraisal wells in the deepwater Gulf of Mexico in 2008. Our working interests in these exploratory opportunities range from 25% to 50%. In 2009, we will continue to perform additional delineation drilling and continue to plan the development of Jack and St. Malo.
Lloydminster Our Lloydminster properties are located to the south and east of Jackfish in eastern Alberta and western Saskatchewan. Lloydminster produces heavy oil by conventional means without steam injection. We hold 2.5 million net acres and have an 89% average working interest in our Lloydminster properties. In 2008, we drilled 425 gross wells in the area.
Peace River Arch The Peace River Arch is located in west central Alberta. We hold approximately 569,000 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 66 gross wells in the Peace River Arch in 2008.
Deep Basin Our properties in Canadas Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 602,000 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 2008, we drilled 61 gross wells.
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 1.7 million net acres in the
area. These properties produce principally natural gas from conventional reservoirs. We hold a 76% average working interest in these properties. We drilled 37 gross wells in the area in 2008.
Jackfish By the end of 2008, we ramped up production from our 100%-owned Jackfish thermal heavy oil project in the non-conventional oil sands of east central Alberta to 22,000 Bbls per day. We are employing steam-assisted gravity drainage at Jackfish. Production is expected to increase in 2009 to its peak production target of 35,000 Bbls per day. We hold approximately 75,000 net acres in the entire Jackfish area, which can support expansion of the original project. In 2008, we received regulatory approval to develop a second phase of Jackfish. Like the first phase, this second phase of Jackfish is also expected to eventually produce 35,000 Bbls per day of heavy oil production.
2009 Development Plans Similar to our 2009 plans for our U.S. Onshore areas discussed above, we expect to drill fewer wells in 2009 than in 2008 for the key areas in Canada discussed above. Our plans to drill fewer wells in these areas is also affected by our intentions to devote a portion of our planned 2009 capital expenditures to develop our positions in the Horn River Basin in northeast British Columbia. In 2008, we accumulated approximately 153,000 net acres targeting the Devonian shale in this area. In 2009, we will continue to evaluate our acreage and drill wells in this area to assess the reserve and production potential of our acreage position.
Azerbaijan Outside North America, Devons 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 2008, we participated in drilling 15 gross wells.
China Our production in China is from the Panyu development in the Pearl River Mouth Basin in the South China Sea. The 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 seven gross wells in China in 2008.
Brazil In 2008, we continued to ramp up production from our Polvo development, which we operate with a 60% working interest. Polvo is located offshore in the Campos Basin in Block BM-C-8. We experienced mechanical issues during 2008 at Polvo that delayed bringing a portion of our expected production online. As of December 31, 2008, the mechanical issues appear to have been corrected, and we exited the year with gross production at approximately 17,000 Bbls per day. In addition to our development project at Polvo, we hold acreage in eight exploratory blocks. In aggregate, we have 1.4 million net acres in Brazil. Our working interests range from 18% to 100% in these blocks. We drilled 12 gross wells in Brazil in 2008 and over the next two years we plan to drill up to eight exploratory wells.
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.
Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. 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 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. The first phase was scheduled to begin in August 2008, but the defendant settled prior to trial. The second phase was scheduled to begin in February 2009, but the defendants settled prior to trial. Devon was not included in the groups of defendants selected for these first two phases. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure with respect to this lawsuit and, therefore, no liability related to this lawsuit has been recorded.
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 2008.
Our common stock is traded on the New York Stock Exchange (the NYSE). On February 16, 2009, there were 14,074 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 2008 and 2007. Also, included are the quarterly dividends per share paid during 2008 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.
Our Board of Directors has approved a program to repurchase up to 50 million shares, which expires on December 31, 2009. As of December 31, 2008, up to 45.5 million shares can be repurchased under the 50 million share repurchase program.
Our Board of Directors has also approved an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to, and options exercised by, employees. In 2008, the repurchase program authorized the repurchase of up to 4.8 million shares or a cost of $422 million, whichever amount was reached first. When the 2008 portion of this annual program expired on December 31, 2008, 2.0 million shares had been repurchased under this program for $178 million, or $87.83 per share.
No shares were repurchased under these programs during the fourth quarter of 2008.
Prior to the end of 2008, our Board of Directors authorized the 2009 portion of the annual program. Under this program in 2009, we are authorized to repurchase up to 4.8 million shares or a cost of $360 million, whichever amount is reached first.
As of December 31, 2008, we are authorized to repurchase up to 50.3 million shares under publicly announced programs. This amount is comprised of the 45.5 million remaining shares authorized to be repurchased under the 50 million share repurchase program and the 4.8 million shares authorized to be repurchased under the annual repurchase program in 2009. However, in response to the current economic environment and recent downturn in commodity prices, we have indefinitely suspended activity under both these programs. As a result, we do not anticipate repurchasing shares under these programs in the foreseeable future. Should economic conditions or commodity prices strengthen, we will consider resumption of share repurchases under our authorized programs.
This Form 10-K includes as exhibits the certifications of our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, required to be filed with the SEC pursuant to Section 302 of the Sarbanes Oxley Act of 2002. We have also filed with the New York Stock Exchange the 2008 annual certification of our Chief Executive Officer confirming that we have complied with the New York Stock Exchange corporate governance listing standards.
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on Devons common stock with the cumulative total returns of the Standard & Poors 500 index (the S&P 500 Index) and the group of companies included in the Crude Petroleum and Natural Gas Standard Industrial Classification code (the SIC Code). The graph was prepared based on the following assumptions:
Comparison of 5-Year Cumulative Total Return
Devon, S&P 500 Index and SIC Code
The graph and related information shall not be deemed soliciting material or to be filed with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
The following selected financial information (not covered by the report of independent registered public accounting firm) should be read in conjunction with Item 7. Managements 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.
The following discussion and analysis presents managements 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:
Devon is one of the worlds leading independent oil and gas exploration and production companies. Our operations are focused primarily in the United States and Canada. However, we also explore for and produce oil and gas in select international areas, including Azerbaijan, Brazil and China. We also own natural gas pipelines and treatment facilities in many of our producing areas, making us one of North Americas larger processors of natural gas liquids.
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. Our production mix in 2008 was approximately 65% gas and 35% oil and NGLs such as propane, butane and ethane. We are currently producing 2.6 Bcf of gas each day, or about 3% 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 building oil and gas reserves and production, exercising capital discipline and controlling operating costs. We also use our marketing and midstream operations to improve our overall performance. Finally, we must continually preserve our financial flexibility to achieve sustainable, long-term success.
Approximately two-thirds of our planned 2009 investment in capital projects is dedicated to a foundation of low-risk projects primarily in North America. The remainder of our capital has been identified for longer-term projects primarily in new unconventional natural gas plays in several United States onshore regions, as well as continued offshore activities 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.
2008 was a year of contrasts. By many measures, 2008 was the best year in our history. Throughout the year, we achieved key operational successes as we continued to execute on our operating strategy. We drilled a record amount of wells with a 98% success rate and delivered a record amount of operating cash flow. As a result of our operational success and rising commodity prices, in the third quarter of 2008, we reported the largest quarterly earnings in our history.
However, sharp declines in oil, gas and NGL prices during the fourth quarter caused us to record noncash impairments of our oil and gas properties totaling $7.1 billion, net of income taxes. Due to this impairment charge, our record earnings in the third quarter were immediately followed by a record quarterly loss in the fourth quarter.
We account for our oil and gas properties using the full cost accounting method. Full cost impairment calculations require the use of quarter-end prices. As a result, such calculations do not indicate the true fair value of the underlying reserves because of the volatile nature of commodity prices. In fact, the SEC recently recognized that impairment calculations based upon prices as of a single day of the year are not ideal and issued new rules that require the use of 12-month average prices for impairment calculations. These new rules will be effective for our 2009 year-end reporting. Had these new rules been in place as of December 31, 2008, we would not have recognized the noncash impairments.
Key measures of our performance for 2008, as well as certain operational developments, are summarized below:
Despite these positive results, we reported a net loss of $2.1 billion, or $4.85 per diluted share, for 2008. This represents a $5.8 billion decrease in earnings compared to 2007, which was primarily attributable to the $7.1 billion, net of income tax, property impairments recognized in the fourth quarter of 2008.
From an operational perspective, we completed another successful year with the drill-bit. We drilled a record 2,441 gross wells with an overall 98% rate of success. This success rate enabled us to increase proved reserves by 584 million Boe, which represented nearly 2 and one half times our 2008 production. Consistent with our two-pronged operating strategy, 93% 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 2008. In the Gulf of Mexico, we continued to build off prior years successful drilling results with our deepwater exploration and development program. At Cascade, we commenced drilling the first of two initial producing wells and continued work on production facilities and subsea equipment. We also continued progressing toward commercial development of our other previous discoveries in the Lower Tertiary trend of the Gulf of Mexico. We also added some 800,000 net undeveloped acres to our lease inventory, positioning us with more than 1.4 million net acres in four emerging unconventional natural gas plays in the United States.
In 2008, we substantially completed our African divestiture program. We have now sold all our oil and gas producing properties in Africa, generating aggregate proceeds of $2.2 billion after income taxes.
Additionally, on October 31, 2008, we transferred our 14.2 million shares of Chevron common stock to Chevron. In exchange, we received Chevrons interest in the Drunkards Wash coalbed natural gas field in east-central Utah and $280 million in cash. The field has approximately 51,000 net acres and had net production of about 40 million cubic feet of natural gas equivalent per day at the time of the exchange.
Even with the fourth quarter net loss, we strengthened our financial position during 2008. We used cash on hand, operating cash flow, divestiture proceeds and Chevron exchange proceeds to fund $9.4 billion of capital expenditures, reduce debt by $2.1 billion, repurchase $815 million of common and preferred stock and pay $289 million of dividends. At the end of 2008, we had $379 million of cash, and as of January 31, 2009, we had $3.1 billion of availability under our credit lines.
As previously mentioned, our current and future earnings depend largely on our ability to replace and grow oil and gas reserves, increase production and exert cost discipline. We must also manage commodity pricing risks to achieve long-term success.
Oil and gas prices reached historical high levels in recent years and during the first half of 2008. We have utilized the record operating cash flows generated by high commodity prices, along with proceeds from our African divestitures, to, among other uses, repay outstanding debt. During 2008 and 2007, we repaid outstanding debt totaling $3.9 billion. During this same period, we also repurchased $1.0 billion of our common stock and redeemed $150 million of preferred stock. High commodity prices have also been a key factor driving cost increases in the oil and gas industry that have exceeded general inflation trends. We are no different from others in the industry in that we have been impacted by these cost increases.
As we exited the third quarter of 2008, oil and gas prices had declined sharply from their recent record levels and declined even further through the end of 2008. In addition, recent problems in the credit markets, steep stock market declines, financial institution failures and government bail-outs provide evidence of a weakening United States and global economy. As a result of the market turmoil and price decreases, oil and gas companies with high debt levels and lack of liquidity have been, and will continue to be, negatively impacted. However, we do not consider ourselves to be in this category based on our current debt level and credit availability.
The only constant in the oil and gas business is volatility, and 2008 presented us with some remarkable reminders. Our response to the current environment is to dramatically cut capital expenditures. We are
budgeting exploration and development capital at $3.5 billion to $4.1 billion for 2009. This is less than half of our 2008 investment in exploration and development. With the addition of non-oil and gas capital and other capitalized costs, we are forecasting total 2009 capital expenditures of $4.7 billion to $5.4 billion.
Assuming average benchmark prices of $45.00 per barrel of crude oil and $5.50 per Mcf of gas, our 2009 capital budget will require deficit spending of about $1 billion. Our philosophy has always been to live roughly within our cash flow, and we clearly will not continue to spend at this rate in future years without some improvement in oil and gas prices. However, in order to preserve our business and maintain a level of momentum that will allow us to take advantage of stronger prices when markets recover, we believe it is prudent to use our balance sheet strength to fund this additional $1 billion of spending in 2009. If we see further price weakness in 2009 or beyond, we are prepared to make further cuts.
We are dramatically decreasing our activity across most of our near-term development projects in North America. We will continue activity at a rate that will keep us competitive, but at a far lower level than in 2008. However, we are going to continue the momentum of some of our longer-term growth projects that will position us to bring on new production when oil and gas demand recovers. We are continuing to fund the second phase of our operations at Jackfish and the evaluation and development of our Lower Tertiary assets in the Gulf of Mexico. We will also move forward with the evaluation of our sizable acreage positions in several emerging natural gas plays in North America.
This decrease in development drilling will impact our oil and gas production. We are currently forecasting our 2009 production will be essentially flat with that of 2008.
We are fortunate that we are positioned to withstand the downturn in the global economy and the resulting weakness in oil and gas prices. The strength of our balance sheet and the quality of our oil and gas properties position us to emerge from the current environment and prosper in the future.
Results of Operations
Changes in oil, gas and NGL production, prices and revenues from 2006 to 2008 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.
N/M Not meaningful.
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between 2006 and 2008.
2008 vs. 2007 Oil sales increased $1.2 billion as a result of a 35% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 38% during the same time period, accounting for the majority of the increase.
Oil sales decreased $104 million due to a two million barrel decrease in production. Our International production decreased approximately six million barrels due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. We also deferred 0.5 million barrels of oil production due to hurricanes. These
decreases were partially offset by additional production resulting from increased development activity at our Jackfish and Lloydminster areas in Canada and at our Polvo development in Brazil.
2007 vs. 2006 Oil sales increased $700 million due to a 13 million barrel increase in production. The increase in our 2007 oil production was primarily due to our properties in Azerbaijan where we achieved payout of certain carried interests in the last half of 2006. This led to a nine million barrel increase in 2007 as compared to 2006. Production also increased 3.5 million barrels due to increased development activity in our Lloydminster area in Canada. Also, oil sales from our Polvo field in Brazil began during the fourth quarter of 2007, which resulted in 0.5 million barrels of increased production.
Oil sales increased $359 million as a result of an 11% increase in our realized price without hedges. The average NYMEX West Texas Intermediate index price increased 9% during the same time period, accounting for the majority of the increase.
2008 vs. 2007 Gas sales increased $1.7 billion as a result of a 29% increase in our realized price without hedges. This increase was largely due to increases in the regional index prices upon which our gas sales are based.
A 77 Bcf increase in production during 2008 caused gas sales to increase by $462 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 83 Bcf to the gas production increase. This increase and the effect of new drilling and development in our other North American properties were partially offset by natural production declines and the deferral of seven Bcf of production in 2008 due to hurricanes.
2007 vs. 2006 A 55 Bcf increase in production caused gas sales to increase by $327 million. Our drilling and development program in the Barnett Shale field in north Texas contributed 53 Bcf to the gas production increase. The June 2006 Chief Holdings LLC (Chief) acquisition also contributed 12 Bcf of increased production. During 2007, we also began first production from the Merganser field in the deepwater Gulf of Mexico, which resulted in seven Bcf of increased production. These increases and the effects of new drilling and development in our other North American properties were partially offset by natural production declines primarily in Canada.
A 1% decline in our average realized price without hedges caused gas sales to decrease $52 million in 2007.
Net (Loss) Gain on Oil and Gas Derivative Financial Instruments
The following tables provide financial information associated with our oil and gas hedges from 2006 to 2008. The first table presents the cash settlements and unrealized gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements from 2006 to 2008. The prices do not include the effects of unrealized gains and losses.
Our oil and gas derivative financial instruments include price swaps and costless price collars. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The costless price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty. Cash settlements as presented in the tables above represent realized losses or gains related to our price swaps and collars.
During 2008, we received $27 million, or $0.51 per Bbl, from counterparties to settle our oil price collars. We paid $424 million, or $0.45 per Mcf, to counterparties during 2008 to settle our gas price swaps and collars. During 2007, we received $40 million, or $0.04 per Mcf, from counterparties to settle our gas price swaps and collars. In 2006, cash payments related to our gas price swaps and collars were completely offset by cash receipts.
In addition to recognizing these cash settlement effects, we also recognize unrealized changes in the fair values of our oil and gas derivative instruments in each reporting period. We estimate the fair values of our oil and gas derivative financial instruments primarily by using internal discounted cash flow calculations. From time to time, we validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.
The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Based on the amount of volumes subject to price swaps and collars at December 31, 2008, a 10% increase in these forward curves would have decreased our 2008 unrealized gain for our oil and gas collar derivative financial instruments by approximately $54 million. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility.
Counterparty credit risk is also a component of commodity derivative valuations. We have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with eight separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterpartys credit rating falls below investment grade. The threshold for collateral posting decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. As of December 31, 2008, the credit ratings of all our counterparties were investment grade.
The $243 million net unrealized gain recognized in 2008 was primarily the result of a decrease in the Inside FERC Henry Hub forward curve subsequent to our contract trade dates.
The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit between 2006 and 2008 are shown in the table below.
2008 vs. 2007 Marketing and midstream revenues increased $556 million and operating costs and expenses increased $397 million, causing operating profit to increase $159 million. Both revenues and expenses increased primarily due to higher natural gas and NGL prices and increased gas pipeline throughput.
2007 vs. 2006 Marketing and midstream revenues increased $64 million, while operating costs and expenses decreased $9 million, causing operating profit to increase $73 million. Revenues increased primarily due to higher prices realized on NGL sales.
The details of the changes in oil, gas and NGL production and operating expenses between 2006 and 2008 are shown in the table below.
2008 vs. 2007 LOE increased $389 million in 2008. The largest contributor to this increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with new thermal heavy oil production from our Jackfish operations in Canada as well as new oil production from Brazil. As these large-scale projects are in the early phases of production, per-unit operating costs are higher than the per-unit costs for our overall portfolio of producing properties. LOE also increased $112 million due to our 6% growth in production. Additionally, LOE increased $31 million due to damages to certain of our facilities and transportation systems caused by Hurricane Ike in the third quarter of 2008. These hurricane damages also contributed to the increase in LOE per Boe.
2007 vs. 2006 LOE increased $403 million in 2007. The largest contributor to this increase was our 12% growth in production, which caused an increase of $168 million. Another key contributor to the LOE increase was the effects of inflationary pressure driven by increased competition for field services. Increased demand for these services continued to drive costs higher for materials, equipment and personnel used in both recurring activities as well as well-workover projects during 2007. Furthermore, changes in the exchange rate between the U.S. and Canadian dollar also caused LOE to increase $40 million.
The following table details the changes in production taxes between 2006 and 2008. 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.
2008 vs. 2007 Production taxes increased $59 million due to an increase in the effective production tax rate in 2008. Our higher production tax rates in 2008 were largely due to higher rates in China, which are
based on the level of crude oil prices. As our realized price for crude oil sales in China increases or decreases, production tax rates will increase or decrease in a like manner.
2007 vs. 2006 Production taxes decreased $66 million due to a decrease in the effective production tax rate in 2007. Our lower production tax rates in 2007 were primarily due to an increase in tax credits received on certain horizontal wells in the state of Texas and the increase in Azerbaijan revenues subsequent to the payouts of our carried interests in the last half of 2006. Our Azerbaijan revenues are not subject to production taxes. Therefore, the increased revenues generated in Azerbaijan in 2007 caused our overall rate of production taxes to decrease.
DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the depletable base. The depletable base represents our net capitalized investment plus future development costs related to proved undeveloped 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 production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.
The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between 2006 and 2008 are shown in the table below.
The following table details the increases in DD&A of oil and gas properties between 2006 and 2008 due to the changes in production volumes and DD&A rate presented in the table above.
2008 vs. 2007 Oil and gas property related DD&A increased $434 million due to a 15% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on both the costs incurred during 2008 as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase include reductions in reserve estimates due to lower 2008 year-end commodity prices and the transfer of previously unproved costs to the depletable base as a result of 2008 drilling activities. In addition to the impact from the higher 2008 rate, our 6% production increase caused oil and gas property related DD&A expense to increase $164 million.
2007 vs. 2006 Oil and gas property related DD&A increased $355 million due to a 15% increase in the DD&A rate. The largest contributor to the rate increase was inflationary pressure on both the costs incurred during 2007 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 transfer of previously unproved costs to the depletable base as a result of 2007 drilling activities and a higher Canadian-to-U.S. dollar exchange rate in 2007. The net effect of these increases was partially offset by higher reserve estimates due to higher 2007 year-end commodity prices. In addition to the impact from the higher 2007 rate, our 12% production increase caused oil and gas property related DD&A expense to increase $242 million.
Our net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially offset by two components. One is the amount of G&A capitalized pursuant to the full cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a propertys 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.
2008 vs. 2007 Gross G&A increased $241 million. The largest contributors to the increase were higher employee compensation and benefits costs. These cost increases, which were largely related to our growth and industry inflation during most of 2008, caused gross G&A to increase $184 million. Of this increase, $79 million related to higher stock compensation.
Stock compensation increased $27 million in the second quarter of 2008 due to a modification of the share-based compensation arrangements for certain of our executives. The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. As a condition to receiving the benefits of these modifications, the executives must agree not to use or disclose Devons confidential information and not to solicit Devons employees and customers. The executives are required to agree to these conditions at retirement and again in each subsequent year until all grants have vested.
Although this modification does not accelerate the vesting of the executives grants, it does accelerate the expense recognition as executives approach the years-of-service and age criteria. When the modification was made in the second quarter of 2008, certain executives had already met the years-of-service and age criteria. As a result, we recognized $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. In the fourth quarter of 2008, we recognized an additional $16 million of stock compensation for grants made to these executives. The additional expenses would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.
The higher employee compensation and benefits costs, exclusive of the accelerated stock compensation expense, were also the primary factors that caused the $94 million increase in capitalized G&A in 2008.
2007 vs. 2006 Gross G&A increased $198 million. The largest contributors to this increase were higher employee compensation and benefits costs. These cost increases, which were related to our growth and industry inflation during 2007, caused gross G&A to increase $134 million. Of this increase, $55 million related to higher stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $13 million increase in costs.
The factors discussed above were also the primary factors that caused the $69 million increase in capitalized G&A in 2007.
The following schedule includes the components of interest expense between 2006 and 2008.
Interest based on debt outstanding decreased $82 million from 2007 to 2008. This decrease was largely due to lower average outstanding amounts for commercial paper and credit facility borrowings in 2008 than in 2007. The decrease in borrowings resulted largely from the use of proceeds from our West African divestiture program and cash flow from operations to repay all commercial paper and credit facility borrowings in the second quarter of 2008. Additionally, we retired debentures with a face value of $652 million during 2008, primarily during the third quarter.
Interest based on debt outstanding increased $22 million from 2006 to 2007. This increase was largely due to higher average outstanding amounts for commercial paper and credit facility borrowings in 2007 than in 2006, partially offset by the effects of repaying various maturing notes in 2007 and 2006.
Capitalized interest increased from 2007 to 2008 primarily due to higher cumulative costs related to large-scale development projects in the Gulf of Mexico and Brazil, partially offset by lower capitalized interest resulting from the completion of the Access Pipeline in Canada.
Capitalized interest increased from 2006 to 2007 primarily due to higher cumulative costs related to large-scale development projects in the Gulf of Mexico and Brazil. Higher cumulative costs related to the development of the second phase of our Jackfish heavy oil development project in Canada and the construction of the related Access Pipeline also contributed to the increase.
The details of the changes in fair value of other financial instruments between 2006 and 2008 are shown in the table below.
Prior to 2007, we recognized unrealized changes in the fair values of our investment in 14.2 million shares of Chevron common stock as part of other comprehensive income. Effective January 1, 2007 as a result of our adoption of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115, we began recognizing unrealized gains and losses on our investment in Chevron common stock in net earnings rather than as part of other comprehensive income. On October 31, 2008, we exchanged these shares of Chevron common stock for Chevrons interest in the Drunkards Wash properties located in east-central Utah and $280 million in cash. In accordance with the terms of the exchange, the fair value of our investment in the Chevron shares was estimated to be $67.71 per share on the exchange date. Prior to the exchange of these shares, we calculated the fair value of our investment in Chevron common stock using Chevrons published market price.
We also recognized unrealized changes in the fair value of the conversion option embedded in the debentures exchangeable into shares of Chevron common stock. The embedded option was not actively traded in an established market. Therefore, we estimated its fair value using quotes obtained from a broker for trades occurring near the valuation date. Since the exchangeable debentures were retired in August 2008, we will not recognize any future gains or losses from the embedded option.
The loss during 2008 on our investment in Chevron common stock was directly attributable to a $25.62 per share decrease in the estimated fair value while we owned Chevrons common stock during the year. The gain on the embedded option during 2008 was directly attributable to the change in fair value of the Chevron common stock from January 1, 2008 to the maturity date of August 15, 2008. The gain on our investment in Chevron common stock and loss on the embedded option during 2007 were directly attributable to a $19.80 increase in the price per share of Chevrons common stock during 2007.
We also recognize unrealized changes in the fair values of our interest rate swaps each reporting period. We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest-rate yields. From time to time, we validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.
The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the notional amount subject to the interest rate swaps at December 31, 2008, a 10% increase in these forward curves would have decreased our 2008 unrealized gain for our interest rate swaps by approximately $3 million.
During 2008, we recorded a $104 million unrealized gain as a result of changes in interest rates subsequent to the trade dates of our contracts.
As previously discussed for our commodity derivative contracts, counterparty credit risk is also a component of interest rate derivative valuations. We have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our interest rate derivative contracts are held with five separate counterparties and have cash collateral posting requirements. Additionally, the credit ratings of all our counterparties were investment grade as of December 31, 2008.
During 2008 and 2006, we reduced the carrying values of certain of our oil and gas properties due to full cost ceiling limitations and unsuccessful exploratory activities. A summary of these reductions and additional discussion is provided below.
The 2008 reductions were all recognized in the fourth quarter of 2008 and resulted primarily from a significant decrease in each countrys full cost ceiling. The lower ceiling values largely resulted from the effects of sharp declines in oil, gas and NGL prices compared to previous quarter-end prices. To demonstrate this decline, the December 31, 2008 and September 30, 2008 weighted average wellhead prices for the United States, Canada and Brazil are presented in the following table.
N/A Not applicable.
The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas. The September 30, 2008, wellhead prices in the table compare to the NYMEX cash price of $100.64 per Bbl for crude oil and the Henry Hub spot price of $7.12 per MMBtu for gas.
As a result of a decline in the estimated future net revenues, the carrying value of our Russian oil and gas 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.
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 our Polvo development project in Brazil.
The following schedule includes the components of other income between 2006 and 2008.
Interest and dividend income decreased from 2007 to 2008 primarily due to a decrease in interest rates, as well as a decrease in dividends received on our investment in Chevron common stock. Interest and dividend income decreased from 2006 to 2007 primarily due to a decrease in income-earning cash and investment balances, partially offset by an increase in the dividend rate on our investment in Chevron common stock.
We suffered insured damages in the third quarter of 2005 related to hurricanes that struck the Gulf of Mexico. During 2006 and 2007, we received $480 million as a full settlement of the amount due from our primary insurers and certain of our secondary insurers. During the fourth quarter of 2008, we received $106 million as full settlement of the amount due from our remaining secondary insurers. Our claims under our then existing insurance arrangements included both physical damages and business interruption claims. As of December 31, 2008, we had utilized $424 million of these proceeds as reimbursement of repair costs and deductible amounts, resulting in excess recoveries. The $162 million of excess recoveries was recorded as other income during 2008.
The following table presents our total income tax (benefit) expense related to continuing operations and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate for each of the past three years. The primary factors causing our effective rates to vary from 2006 to 2008, and differ from the U.S. statutory rate, are discussed below.
For 2008, our effective income tax rate differed from the U.S. statutory income tax rate largely due to two related factors. First, during 2008, we repatriated $2.6 billion from certain foreign subsidiaries to the
United States. Second, we made certain tax policy election changes in the second quarter of 2008 to minimize the taxes we otherwise would pay for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, we recognized additional tax expense of $307 million during 2008. Of the $307 million, $290 million was recognized as current income tax expense, and $17 million was recognized as deferred tax expense. Excluding the $307 million of additional tax expense, our effective income tax benefit rate would have been 32% for 2008.
In 2008, 2007 and 2006, deferred income taxes were reduced $7 million, $261 million and $243 million, respectively, due to successive 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 replaced a previous franchise tax. The new tax was effective January 1, 2007.
Earnings From Discontinued Operations
Our discontinued operations consist of our operations in Egypt and West Africa, including Equatorial Guinea, Cote dIvoire, Gabon and other countries in the region.
In October 2007, we completed the sale of our Egyptian operations 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 the second quarter of 2008, we sold our assets and terminated our operations in certain West African countries, consisting primarily of Equatorial Guinea and Gabon. As a result of the sales, we recognized gains totaling $736 million ($674 million after income taxes) in 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments).
In the third quarter of 2008, we sold our assets and terminated our operations in Cote dIvoire. As a result of this sale, we recognized a gain of $83 million ($95 million after income taxes) in 2008 from proceeds of $205 million ($163 million net of income taxes and purchase price adjustments).
With the Cote dIvoire transaction, we completed the divestiture of all our oil and gas producing properties in Africa. The Africa divestitures generated just over $3.0 billion of sales proceeds. After income taxes and purchase price adjustments, such proceeds totaled $2.2 billion and generated after-tax gains of $0.8 billion.
Following are the components of earnings from discontinued operations between 2006 and 2008.
2008 vs. 2007 Earnings from discontinued operations increased $471 million in 2008. Earnings in 2008 included $769 million of after-tax divestiture gains as discussed above. This was $679 million more than the $90 million after-tax gain from the sale of our Egyptian operations in 2007. The increase in 2008 was partially offset by a decrease of $212 million from reduced earnings due to the timing of the 2008 and 2007 divestitures.
2007 vs. 2006 Earnings from discontinued operations increased $248 million in 2007. In addition to variances caused by changes in production volumes and realized prices, our earnings from discontinued operations in 2007 were impacted by other significant factors. Pursuant to accounting rules for discontinued operations, we ceased recording DD&A in November 2006 related to our Egyptian operations and in January 2007 related to our West African operations. This reduction in DD&A caused earnings from discontinued operations to increase $119 million in 2007. Earnings in 2007 also benefited from the $90 million gain from the sale of our Egyptian operations.
In addition, earnings from discontinued operations increased $90 million in 2007 due to the net effect of reductions in carrying value in 2006 and 2007. Our earnings in 2007 were reduced by $13 million from these reductions, compared to $103 million of reductions recorded in 2006. Due to unsuccessful drilling activities in Nigeria, in the first quarter of 2006, we recognized an $85 million impairment of our investment in Nigeria equal to the costs to drill two dry holes and a proportionate share of block-related costs. There was no income tax benefit related to this impairment. As a result of unsuccessful exploratory activities in Egypt during 2006, the net book value of our Egyptian oil and gas properties, less related deferred income taxes, exceeded the ceiling by $18 million as of the end of September 30, 2006. Therefore, in 2006 we recognized an $18 million after-tax loss ($31 million pre-tax). In the second quarter of 2007, based on drilling activities in Nigeria, we recognized a $13 million after-tax loss ($64 million pre-tax).
Capital Resources, Uses and Liquidity
The following discussion of capital resources, uses and liquidity should be read in conjunction with the consolidated financial statements included in Financial Statements and Supplementary Data.
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents from 2006 to 2008. 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.
Net cash provided by operating activities (operating cash flow) continued to be our primary source of capital and liquidity in 2008. 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, financial instrument fair value changes, property impairments and deferred income taxes. As a result, our operating cash flow increased 50% during 2008 primarily due to the $3.0 billion increase in oil, gas and NGL revenues, net of commodity hedge settlements, as discussed in the Results of Operations section of this report.
During 2008, 2007 and 2006, our capital expenditures were primarily funded by our operating cash flow. In 2006, we used a combination of commercial paper borrowings and proceeds from the sale of short-term investments to fund the $2.0 billion Chief acquisition in June 2006.
As needed, we utilize cash on hand and access our credit facilities and commercial paper program as sources of cash to supplement the liquidity provided by our operating cash flow. Additionally, we sometimes acquire short-term investments to maximize our income on available cash balances. As needed, we may reduce such short-term investment balances to further supplement our operating cash flow.
During 2008, we reduced our short-term investment balances by $250 million. We also received $280 million from the exchange of our investment in Chevron common stock, $117 million from the sale of non-oil and gas property and equipment and $116 million from stock option exercises. Another significant source of cash was our African divestiture program. In the second and third quarters of 2008, we received $2.6 billion in proceeds ($1.9 billion net of income taxes and purchase price adjustments) from sales of assets located in Equatorial Guinea and other West African countries. Also, in conjunction with these asset sales, we repatriated an additional $2.6 billion of earnings from certain foreign subsidiaries to the United States.
We used these combined sources of cash in 2008 to fund debt repayments, common stock repurchases, redemptions of preferred stock and dividends on common and preferred stock.
During 2007, we borrowed $1.5 billion under our unsecured revolving line of credit and reduced our short-term investment balances by $202 million. We also received $341 million of proceeds from the sale of our Egyptian operations. These sources of cash were used primarily to fund net commercial paper repayments, long-term debt repayments, common stock repurchases and dividends on common and preferred stock.
During 2006, we borrowed $1.8 billion under our commercial paper program and reduced our short-term investment balances by $106 million. These sources of cash were largely used to fund the $2.0 billion acquisition of Chief in June 2006. Also during 2006, we supplemented operating cash flow with cash on hand, which was used to fund scheduled long-term debt maturities, common stock repurchases and dividends on common and preferred stock.
Following are the components of our capital expenditures for the years ended 2008, 2007 and 2006.
Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling or development of oil and gas properties, which totaled $8.7 billion, $5.6 billion and $6.8 billion in 2008, 2007 and 2006, respectively. The 2008 capital expenditures include $2.6 billion related to acquisitions of properties in Texas, Louisiana, Oklahoma and Canada. The 2006 capital expenditures include $2.0 billion related to the acquisition of the Chief properties. Excluding the effect of these acquisitions, the increase in capital expenditures from 2006 to 2008 was due to increased drilling activities in the Barnett Shale, Gulf of Mexico, Carthage, Cana, Woodford Shale, Groesbeck and Washakie areas of the United States, the Lloydminster and Jackfish projects in Canada, and in the Polvo development in Brazil. Expenditures also increased due to inflationary pressure driven by increased competition for field services.
Our capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. These midstream facilities exist primarily to support our oil and gas development operations. The majority of our midstream expenditures from 2006 to 2008 were related to development activities in the Barnett Shale, the Woodford Shale in southeastern Oklahoma and Jackfish in Canada.
During 2008, we repaid $1.5 billion in outstanding credit facility borrowings primarily with proceeds received from the sales of assets under our African divestiture program. Also during 2008, virtually all holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock owned by us. The debentures matured on August 15, 2008. In lieu of delivering our shares of Chevron common stock, we exercised our option to pay the exchanging debenture holders cash totaling $1.0 billion. This amount included the retirement of debentures with a book value of $652 million and a $379 million payment of the related embedded derivative option.
During 2007, we repaid the $400 million 4.375% notes, which matured on October 1, 2007. Also during 2007, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock prior to the debentures August 15, 2008 maturity date. In lieu of delivering shares of Chevron common stock, we exercised our option to pay the exchanging debenture holders an amount of cash equal to the market value of Chevron common stock. We paid $167 million in cash to exchangeable debenture holders who exercised their exchange rights. This amount included the retirement of debentures with a book value of $105 million and a $62 million payment of the related embedded derivative option.
During 2006, we retired the $500 million 2.75% notes and the $178 million ($200 million Canadian) 6.55% senior notes. We also repaid $180 million of debt acquired in the Chief acquisition.
During the three-year period ended December 31, 2008, we repurchased 14.8 million shares at a total cost of $1.2 billion, or $83.98 per share, under various repurchase programs. During 2008, we repurchased 6.5 million shares at a cost of $665 million, or $102.56 per share. During 2007, we repurchased 4.1 million shares at a cost of $326 million, or $79.80 per share. During 2006, we repurchased 4.2 million shares at a cost of $253 million, or $59.61 per share.
On June 20, 2008, we redeemed all 1.5 million outstanding shares of our 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
Our common stock dividends were $284 million (or a quarterly rate of $0.16 per share), $249 million (or a quarterly rate of $0.14 per share) and $199 million (or a quarterly rate of $0.1125) in 2008, 2007 and 2006, respectively. Common dividends increased primarily due to the higher quarterly dividend rates.
We also paid $5 million of preferred stock dividends in 2008 and $10 million of preferred stock dividends in both 2007 and 2006. The decrease in the preferred dividends in 2008 was due to the redemption of our preferred stock in the second quarter of 2008.
Historically, our primary source of capital and liquidity has been operating cash flow. During 2008, we repatriated earnings from certain foreign subsidiaries to the United States in conjunction with the divestitures of our assets in West Africa. Subsequent to these repatriations, we do not expect to repatriate similar earnings from our historical operations in the foreseeable future. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. We expect the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed later in this section.
Our operating cash flow has increased approximately 73% since 2006, reaching a total of $9.3 billion in 2008. 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, gas and NGLs we produce.
Commodity Prices Prices for oil, gas and NGLs are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in oil, gas and NGL prices and are beyond our control. Although we expect this volatility to continue throughout 2009, we expect 2009 oil, gas and NGL prices will be noticeably lower than those for 2008. The corresponding reduction in our operating cash flow will require us to scale back certain uses of cash during 2009 compared to 2008, including most notably our capital expenditures.
To mitigate some of the risk inherent in prices, we have utilized various 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 of a portion of our future oil and gas production. Based on contracts in place as of February 16, 2009, in 2009 approximately 10% of our estimated gas production is subject to either price collars or fixed-price contracts. The key terms of these contracts are summarized in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases, as experienced in recent years, can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also true during periods of depressed commodity prices such as what we are currently experiencing.
Interest Rates Our operating cash flow can also be sensitive to interest rate fluctuations. As of January 31, 2009, we had long-term debt of $6.2 billion. This included $6.0 billion of fixed-rate debt and $0.2 billion of variable-rate commercial paper borrowings. The fixed-rate debt bears interest at an overall weighted average rate of 7.23%. We also have interest rate swaps to mitigate a portion of the fair value effects of interest rate fluctuations on our fixed-rate debt. Under the terms of these swaps, we receive a fixed rate and pay a variable rate on a total notional amount of $1.05 billion. Including the effects of these swaps, the weighted-average interest rate related to our fixed-rate debt was 6.64% as of January 31, 2009. The key terms of these interest rate swaps are included in Item 7A. Quantitative and Qualitative Disclosures of Market Risk.
Credit Losses Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. We are also exposed to the credit risk of counterparties to our derivative financial contracts as discussed previously in this report.
The recent deterioration of the global financial and capital markets, combined with the drop in commodity prices, has increased our credit risk exposure. However, we utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, prepayment requirements for commodity sales and collateral posting requirements in our existing derivative contracts.
We have two revolving lines of credit and a commercial paper program that we intend to access during 2009 to provide liquidity. Although we are reducing our planned 2009 capital expenditures, we anticipate our operating cash flow in 2009 will be approximately $1.0 billion less than our capital expenditures due to significantly lower commodity prices.
We have a $2.65 billion syndicated, unsecured revolving line of credit (the Senior Credit Facility). The maturity date for $2.15 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.5 billion is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $500 million.
Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of January 31, 2009, there were no borrowings under the Senior Credit Facility.
On November 5, 2008, we established a new $700 million 364-day, syndicated, unsecured revolving senior credit facility (the Short-Term Facility). The Short-Term Facility provides us with incremental liquidity for near-term capital expenditures.