Devon Energy 10-K 2007
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 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, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2006, was $26,464,653,232.
On February 15, 2007, 444,461,491 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2007 annual meeting of stockholders Part III
As used in this document:
Bbl or Bbls means barrel or barrels.
Bcf means billion cubic feet.
Boe means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
FPSO means floating, production, storage and offloading facilities.
Btu means British Thermal units, a measure of heating value.
Inside FERC refers to the publication Inside F.E.R.C.s Gas Market Report.
LIBOR means London Interbank Offered Rate.
MBbls means thousand barrels.
MMBbls means million barrels.
MBoe means thousand Boe.
MMBoe means million Boe.
MMBtu means million Btu.
Mcf means thousand cubic feet.
MMcf means million cubic feet.
NGL or NGLs means natural gas liquids.
NYMEX means New York Mercantile Exchange.
Oil includes crude oil and condensate.
SEC means United States Securities and Exchange Commission.
Domestic means the properties of Devon in the onshore continental United States and the offshore Gulf of Mexico.
U.S. Onshore means the properties of Devon in the continental United States.
U.S. Offshore means the properties of Devon in the Gulf of Mexico.
Canada means the division of Devon encompassing oil and gas properties located in Canada.
International means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information which was used to prepare the December 31, 2006 reserve reports and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as may, will, expect, intend, project, estimate, anticipate, believe, or continue or the negative thereof or variations thereon or similar
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. We also own properties in West Africa and Egypt that we intend to sell in 2007. In addition to our oil and gas operations, we have marketing and midstream operations primarily in North America. These include marketing natural gas, crude oil and NGLs, and constructing and operating pipelines, storage and treating facilities and gas processing plants. A detailed description of our significant properties and associated 2006 developments can be found under Item 2. Properties.
We began operations in 1971 as a privately held company. In 1988, our common stock began trading publicly on the American Stock Exchange under the symbol DVN. In October 2004, we transferred our common stock listing to the New York Stock Exchange. Our principal and administrative offices are located at 20 North Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).
We have a two-pronged operating strategy. First, we invest the vast majority of our capital budget in low-risk exploitation and development projects on our extensive North American property base which provides reliable and repeatable production and reserves additions. To supplement that strategy, we annually invest a measured amount of capital in high-impact, long cycle-time projects to replenish our development inventory for the future. The philosophy that underlies the execution of this strategy is to strive to increase value on a per share basis by:
During 1988, we expanded our capital base with our first issuance of common stock to the public. This transaction began a substantial expansion program that has continued through the subsequent years. This expansion is attributable to both a focused mergers and acquisitions program spanning a number of years and an active ongoing exploration and development drilling program. Total proved reserves increased from 8 MMBoe1 at year-end 1987 to 2,376 MMBoe2 at year-end 2006.
During the same time period, we have grown proved reserves from 0.66 Boe1 per diluted share at the end of 1987 to 5.30 Boe2 per diluted share at the end of 2006. This represents a compound annual growth rate of 12%. We have also increased production from 0.09 Boe1 per diluted share in 1987 to 0.48 Boe2 per diluted share in 2006, for a compound annual growth rate of 9%. This per share growth is a direct result of successful execution of our strategic plan and other key transactions and events.
1 Excludes the effects of mergers in 1998 and 2000 that were accounted for as poolings of interests.
2 Excludes reserves in Egypt that are held for sale and classified as discontinued operations as of December 31, 2006.
We achieved a number of significant accomplishments in our operations during 2006, including those discussed below.
In addition to production growth, our U.S. onshore properties also demonstrated significant growth in proved reserves. U.S onshore production in 2006 of 110 MMBoe was more than offset by 265 MMBoe of additions from extensions and discoveries during the year, as well as 105 MMBoe added through acquisitions, primarily the Chief acquisition. The additional reserves added by drilling and acquisition activities caused our 2006 U.S. onshore proved reserves to increase 21% compared to the end of 2005.
Specific Gulf of Mexico developments in 2006 included the following:
On November 14, 2006, we announced our plans to divest our operations in Egypt. At December 31, 2006, our Egyptian operations had proved reserves of eight million Boe. Subsequently, on January 23, 2007, we announced our plans to divest our operations in West Africa, including Equatorial Guinea, Cote dIvoire, and other countries in the region. At December 31, 2006, our West African operations had proved reserves of 90 million Boe. We anticipate completing the sale of our Egyptian operations in the first half of 2007 and our West African operations in the third quarter of 2007. Divesting these properties will allow us to redeploy our financial and intellectual capital to the significant growth opportunities we have developed onshore in North America and in the deepwater Gulf of Mexico. Additionally, we will sharpen our focus in North America and concentrate our international operations in Brazil and China, where we have established competitive advantages.
Pursuant to accounting rules for discontinued operations, our Egyptian operations were classified as discontinued operations at the end of 2006. Accordingly, we have classified all amounts related to our operations in Egypt as discontinued. Therefore, all amounts for all periods presented in this document related to our continuing operations exclude Egypt. Our West African operations did not meet the criteria to be considered discontinued operations at the end of 2006. Therefore, all amounts related to our operations in West Africa are still presented in this document as part of our continuing operations. Beginning in 2007, our operations in West Africa will be considered and classified as discontinued.
Notes 14 and 15 to the consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this report contain information on our segments and geographical areas.
The spot market for oil and gas is subject to volatility as supply and demand factors fluctuate. We may periodically enter into financial hedging arrangements, fixed-price contracts or firm delivery commitments with a portion of our oil and gas production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Our oil production is sold under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. All of our oil production is sold at variable or market-sensitive prices.
Our gas production is also sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of February 2007, approximately 75% of our natural gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as spot market sales. Another 23% of our production was committed under various long-term contracts which dedicate the natural gas to a purchaser for an extended period of time but still at market sensitive prices. Our remaining gas production was sold under long-term fixed price contracts.
The primary objective of our marketing and midstream operations is to add value to us and other producers to whom we provide such services by gathering, processing and marketing oil and gas production in a timely and efficient manner. Our most significant marketing and midstream asset is the Bridgeport
processing plant and gathering system located in North Texas. These facilities serve not only our gas production from the Barnett Shale but also gas production of other producers in the area.
Our marketing and midstream revenues are primarily generated by:
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. Existing gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries.
The principal customers for our crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked or shipped to storage, refining or pipeline facilities.
During 2006, revenues received from ExxonMobil and its affiliates were $1.1 billion, or 10% of our consolidated revenues. No purchaser accounted for over 10% of our revenues in 2005 or 2004.
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 such legislation, numerous government agencies have issued extensive laws and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, production and marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and gas companies of similar size.
The following are significant areas of government control and regulation in the United States, Canada and other international locations in which we operate.
Our oil and gas operations are subject to various federal, state, provincial, local and international laws and regulations, including regulations related to the acquisition of seismic data; the location of wells; drilling and casing of wells; well production; spill prevention plans; the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the restoration of properties upon which wells have been drilled; the calculation and disbursement of royalty payments and production taxes; the plugging and abandoning of wells; the transportation of production; and, in international operations, minimum investments in the country of operations.
Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells which may be drilled in a unit; the rate of production allowable from oil and natural gas wells; and the unitization or pooling of oil and natural gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.
Certain of our U.S. oil and natural gas leases are granted by the federal government and administered by various federal agencies, including the Bureau of Land Management and the Minerals Management Service (MMS) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. The MMS has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands. The Federal Energy Regulatory Commission also has jurisdiction over certain U.S. offshore activities pursuant to the Outer Continental Shelf Lands Act.
The royalty system in Canada is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.
An order from Canadas National Energy Board (NEB) is required for oil and natural gas exports from Canada. Any oil or natural gas export to be made pursuant to an export contract of a certain duration or covering a certain quantity requires an exporter to obtain an export license from the NEB, which requires the approval of the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts meet certain criteria prescribed by the NEB. The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.
The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval.
Many of our international licenses are governed by Production Sharing Contracts (PSCs) between the concessionaires and the granting government agency. PSCs are contracts that define and regulate the framework for investments, revenue sharing, and taxation of mineral interests in foreign countries. Unlike most domestic leases, PSCs have defined production terms and time limits of generally 30 years. PSCs also generally contain sliding scale revenue sharing provisions. As a result, at either higher production rates or higher cumulative rates of return, PSCs generally allow the government partner to retain higher fractions of revenue.
We are subject to various federal, state, provincial, local and international laws and regulations concerning occupational safety and health and the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things, assessing the environmental impact of seismic acquisition, drilling or construction activities; the generation, storage, transportation and disposal of waste materials; the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and the development of emergency response and spill contingency plans. The application of worldwide standards, such as ISO 14000 governing Environmental Management Systems, are required to be implemented for some international oil and gas operations.
In 1997, numerous countries participated in an international conference under the United Nations Framework Convention on Climate Change and adopted an agreement known as the Kyoto Protocol (the Protocol). The Protocol became effective February 14, 2005, and requires reductions of certain emissions that contribute to atmospheric levels of greenhouse gases. Certain countries in which we operate (but not the United States) have ratified the Protocol. Presently, it is not possible to accurately estimate the costs we could incur to comply with any laws or regulations developed to achieve such emissions reductions, but such expenditures could be substantial. In 2006, Devon published its Corporate Climate Change Position and Strategy. Key components of the strategy include initiation of energy conservation measures, tracking emerging climate changes legislation and publication of a corporate greenhouse gas emission inventory by the end of 2007. All provisions of the strategy are in progress.
We consider the costs of environmental protection and safety and health compliance necessary and manageable parts of our business. With the efforts of our Environmental, Health and Safety Department, we have been able to plan for and comply with environmental and safety and health initiatives without materially altering our operating strategy. We anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. While our unreimbursed expenditures in 2006 concerning such matters were immaterial, we cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, salt water or other substances. However, we do not maintain 100% coverage concerning any environmental claim, and no coverage is maintained with respect to any penalty or fine required to be paid because of a violation of law.
As of December 31, 2006, we had approximately 4,600 employees. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.
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 Devons corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer), and documents Devon files or furnishes to the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.
Our business activities, and the oil and gas industry in general, are subject to a variety of risks. Although we have a diversified asset base, a strong balance sheet and a history of generating sufficient cash to fund capital expenditure and investment programs and to pay dividends, if any of the following risk factors should occur, our profitability, financial condition and/or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
Our financial results are highly dependent on the prices of and demand for oil, natural gas and NGLs. A significant downward movement of the prices for these commodities could have a material adverse effect on our estimated proved reserves, revenues and operating cash flows, as well as the level of planned drilling activities. Such a downward price movement could also have a material adverse effect on our profitability, the carrying value of our oil and gas properties and future growth. Historically, prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve
estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Additional discussion of our policies regarding estimating and recording reserves is described in Item 2. Properties Proved Reserves and Estimated Future Net Revenue.
Discoveries or Acquisitions of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production
The production rate from oil and gas properties generally declines as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies, identify additional producing zones in existing wells, secondary recovery reserves or tertiary recovery reserves, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
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. Higher recent commodity prices have increased drilling and operating costs of existing properties. Higher prices have also increased the costs of properties available for acquisition, and there are a greater number of publicly traded companies and private-equity firms with the financial resources to pursue acquisition opportunities. Certain of our competitors have financial and other resources substantially larger than ours, and they have also established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations.
Our operations outside North America are based primarily in Azerbaijan, Brazil, China and various countries in West Africa. As a result, we face political and economic risks and other uncertainties that are less prevalent for our operations in North America. Such factors include, but are not limited to:
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 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 international countries in which we operate. In addition, we are also subject to the laws and regulations of various states, provinces and local governments. Pursuant to such legislation, numerous government departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Changes in such legislation have affected, and at times in the future could affect, our future operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability. While such legislation can change at any time in the future, those laws and regulations outside North America to which we are subject generally include greater risk of unforeseen change.
As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, provincial, local and international laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have a significant impact on our operations and profitability.
Exploration, development, production and processing of oil, natural gas and NGLs can be hazardous and involve unforeseen occurrences such as hurricanes, blowouts, cratering, fires and loss of well control. These occurrences can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. We maintain insurance against certain losses or liabilities in accordance with customary industry practices and in amounts that management believes to be prudent. However, insurance against all operational risks is not available to us. Due to changes in the marketplace following the 2005 hurricanes in the Gulf of Mexico, we currently have only a de minimis amount of coverage for any damage that may be caused by future named windstorms in the Gulf of Mexico.
Substantially all of our properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage located in our core operating areas. These interests entitle us to drill for and produce oil, natural gas and NGLs from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral and net profits interests, foreign government concessions and other forms of direct and indirect ownership in oil and gas properties.
We also have certain midstream assets, including natural gas and NGL processing plants and pipeline systems. Our most significant midstream assets are our assets serving the Barnett Shale region in North Texas. These assets include approximately 2,700 miles of pipeline, two gas processing plants with 680 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator.
Proved Reserves and Estimated Future Net Revenue
The SEC defines proved oil and gas reserves as the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment as discussed in Item 1A. Risk Factors. As a result, we have developed internal policies for estimating and recording reserves. Our policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance, and assign responsibilities for reserves bookings to our Reserve Evaluation Group (the Group). Our policies also require that reserve estimates be made by qualified reserves estimators (QREs), as defined by the Society of Petroleum Engineers standards. A list of our QREs is kept by the Senior Advisor Corporate Reserves. All QREs are required to receive education covering the fundamentals of SEC proved reserves assignments.
The Group is responsible for internal reserves evaluation and certification and includes the Manager E&P Budgets and Reserves and the Senior Advisor Corporate Reserves. The Group reports independently of any of our operating divisions. The Vice President Planning and Evaluation is directly responsible for overseeing the Group and reports to the President of Devon. No portion of the Groups compensation is 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 2006 reserves estimates for all our offshore Gulf of Mexico properties and for 99% of our International proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2006 reserves estimates for 87% of our domestic onshore properties. AJM Petroleum Consultants prepared estimates covering 46% of our 2006 Canadian reserves and audited an additional 39% of our Canadian reserves.
Set forth below is a summary of the reserves which were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2006, 2005 and 2004.
Prepared reserves are those quantities of reserves which were prepared by an independent petroleum consultant. Audited reserves are those quantities of reserves which were estimated by our employees and audited by an independent petroleum consultant. An audit is an examination of a 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 internal and external reviews, three independent members of our Board of Directors have been assigned to a Reserves Committee. The Reserves Committee meets at lease twice a year to discuss reserves issues and policies and periodically meets separately with our senior reserves engineering personnel and our independent petroleum consultants. The Reserves Committee assists the Board of Directors with the oversight of the following:
The following table sets forth our estimated proved reserves and the related estimated pre-tax future net revenues, pre-tax 10% present value and after-tax standardized measure of discounted future net cash flows as of December 31, 2006. These estimates correspond with the method used in presenting the Supplemental Information on Oil and Gas Operations in Note 15 to our consolidated financial statements included herein.
These amounts were calculated using prices and costs in effect for each individual property as of December 31, 2006. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yield average prices over the life of our properties of $46.11 per Bbl of oil, $5.06 per Mcf of natural gas and $27.63 per Bbl of NGLs. These prices compare to the December 31, 2006, NYMEX cash price of $61.05 per Bbl for crude oil and the Henry Hub spot price of $5.64 per MMBtu for natural gas.
The present value of after-tax future net revenues discounted at 10% per annum (standardized measure) was $16.6 billion at the end of 2006. Included as part of standardized measure were discounted future income taxes of $7.5 billion. Excluding these taxes, the present value of our pre-tax future net revenue (pre-tax 10% present value) was $24.1 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors which are more consistent from company to company. We also understand that securities analysts use the pre-tax 10% present value measure in similar ways.
(3) See Note 15 to the consolidated financial statements included in Item 8. Financial Statements and Supplementary Data.
As presented in the previous table, we had 1,674 MMBoe of proved developed reserves at December 31, 2006. Proved developed reserves consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding our proved developed reserves at December 31, 2006.
No estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of the last fiscal year except in filings with the SEC and
the Department of Energy (DOE). Reserve estimates filed with the SEC correspond with the estimates of our reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.
The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 2006. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.
Certain information concerning oil, natural gas and NGL production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 2006, is set forth in Item 7. 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 operations that were classified as discontinued at the end of 2006.
Exploratory Well Activity
For the wells being drilled as of December 31, 2006 presented in the tables above, the following table summarizes the results of such wells as of February 1, 2007.
The following table sets forth our producing wells as of December 31, 2006. The table does not include our Egyptian operations that were classified as discontinued at the end of 2006.
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2006. The table does not include our Egyptian operations that were classified as discontinued at the end of 2006.
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 22,434 of our wells. As operator, we receive reimbursement for direct expenses incurred in the performance of our duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.
Organization Structure and Property Profiles
Our properties are located within the U.S. onshore and offshore regions, Canada, and certain locations outside North America. The following table presents proved reserve information for our significant properties as of December 31, 2006, along with their production volumes for the year 2006. Included in the table are certain U.S. offshore properties which currently have no proved reserves or production. Such properties are considered significant because they may be the source of significant growth in proved reserves and production in the future. Also included in the table are properties located in West Africa that we intend to sale in 2007. The table does not include our Egyptian operations that were classified as discontinued at the end of 2006. Additional summary profile information for our significant properties is provided following the table.
Barnett Shale The Barnett Shale, located in north central Texas, is our largest property both in terms of production and proved reserves. Our leases include approximately 725,000 net acres located primarily in Denton, Johnson, Parker, Tarrant and Wise counties. The Barnett Shale is a non-conventional reservoir and it produces natural gas and natural gas liquids. We have an average working interest in the Barnett Shale of greater than 90%.
During 2006, we acquired additional Barnett Shale assets from Chief. The Chief acquisition added approximately 100 MMBoe of proved reserves, 169,000 net acres and some 2,000 additional drilling locations to our Barnett Shale holdings. We drilled 383 gross wells in the Barnett Shale in 2006 and expect to drill 385 gross wells in the area in 2007.
Carthage The Carthage area in east Texas includes primarily Harrison, Marion, Panola and Shelby counties. We hold approximately 126,000 net acres in the area. Our Carthage area wells produce primarily natural gas and natural gas liquids from conventional reservoirs. Our average working interest in this area is about 85%. We drilled 122 gross wells at Carthage in 2006 and plan to drill 150 gross wells in the area in 2007.
Permian Basin, Texas Our oil and gas properties in the Permian Basin of west Texas comprise approximately 1.2 million net acres. Our acreage is located primarily in Andrews, Crane, Martin, Terry, Ward and Yoakum counties. The Permian Basin produces both oil and natural gas from conventional reservoirs. Our average working interest in these properties is about 40%. We drilled 95 gross wells in the Permian Basin of west Texas in 2006, and we plan to drill another 100 gross wells in the area in 2007.
Washakie Our Washakie area leases are concentrated in Carbon and Sweetwater counties in southern Wyoming. We hold about 157,000 net acres in the Washakie area. Washakie produces primarily natural gas from conventional reservoirs. Our average working interest in the Washakie area is about 76%. In 2006, we drilled 137 wells at Washakie, and we plan to drill another 105 wells in the area in 2007.
Groesbeck The Groesbeck area of east Texas includes portions of Freestone, Leon, Limestone and Robertson counties. We hold about 173,000 net acres of land in the Groesbeck area. Groesbeck produces primarily natural gas from conventional reservoirs. Our average working interest in the area is approximately 72%. In 2006, we drilled 31 gross wells in the area. Our plans anticipate drilling 34 additional gross wells in the Groesbeck area in 2007.
Permian Basin, New Mexico We also own oil and gas properties in the Permian Basin in south eastern New Mexico. We hold about 342,000 net acres concentrated in Eddy and Lea counties. We produce conventional oil and natural gas from the Permian Basin in New Mexico, and have an average working interest of about 75% in these properties. In 2006, we drilled 82 gross wells in this area, and we expect to drill another 44 gross wells in 2007.
Deepwater Producing Our assets in the Gulf of Mexico include four significant producing properties located in deep water (greater than 600 feet). These properties are Magnolia, Nansen, Red Hawk and Zia. They are all located on federal leases and total approximately 48,000 net acres. The properties produce both crude oil and natural gas. Our working interest is 65% in Zia and 50% in each of the other three properties.
We drilled a total of two gross deepwater producing wells in 2006 and expect to drill four additional gross wells in 2007.
Deepwater Development In addition to our four significant deepwater producing properties, we are in the process of developing two other deepwater projects, Merganser and Cascade. Merganser and Cascade are located on federal leases encompassing a total of approximately 11,500 net acres. We have 50% working interests in both properties.
We drilled two producing wells at Merganser in 2006. These wells are expected to commence producing natural gas in mid-2007. No additional drilling is planned at Merganser.
We announced in 2006 our plans to develop the 2002 Cascade discovery using an FPSO vessel. Cascade is expected to begin producing primarily oil in late 2009. Additional drilling at Cascade is in the planning stage.
Deepwater Exploration Our exploration program in the Gulf of Mexico is focused primarily on deepwater opportunities. Our deepwater exploratory prospects include Miocene-aged objectives (five million to 24 million years) and older and deeper Lower Tertiary objectives. We hold federal leases comprising approximately 1.2 million net acres in our deepwater exploration inventory.
In 2006, various drilling and testing operations provided evidence that our Lower Tertiary properties may be a source of meaningful reserve and production growth in the future. Prior to 2006, we had drilled three discovery wells in the Lower Tertiary. These include Cascade in 2002 (see Deepwater Development above), St. Malo in 2003 and Jack in 2004. Operations in 2006 included a successful production test of the Jack No. 2 well and participation in the Kaskida discovery, which is our fourth Lower Tertiary discovery. We currently hold 273 blocks in the Lower Tertiary and have identified 19 additional prospects to date.
At St. Malo, in which our working interest is 22.5%, we plan to drill a second delineation well in late 2007 or early 2008. At Jack, where our working interest is 25%, we continue to evaluate with our partners our development options following the successful production test in 2006.
In addition to the 2006 Kaskida discovery, a subsequent sidetrack well at Kaskida was drilled in 2006 and another well operation is planned for 2007. Our working interest in Kaskida is 20%, and we believe Kaskida is the largest of our four Lower Tertiary discoveries to date. The Kaskida discovery was our first in the Keathley Canyon deepwater lease area. Twelve of the 19 additional Lower Tertiary exploratory prospects we have identified to date are on our Keathley Canyon acreage.
Also in 2006, we participated in a Miocene discovery on the Mission Deep prospect in which we have a 50% working interest. We have fifteen additional prospects in our deepwater Miocene inventory.
In total, we drilled three exploratory and delineation wells in the deepwater Gulf of Mexico in 2006, and plan to drill six such wells in 2007. Our working interests in these exploratory opportunities range from 20% to 100%.
Jackfish We are currently developing our 100%-owned Jackfish thermal heavy oil project in the non-conventional oil sands of east central Alberta. We will employ steam-assisted gravity drainage at Jackfish, and we expect to begin steam injection in the second quarter of 2007. Production is expected to eventually reach 35,000 barrels per day by the end of 2008 We drilled 19 pairs of producing and steam-injection wells in 2006, bringing the total number of well-pairs to 24. We hold approximately 80,000 net acres in the entire Jackfish area, which can support expansion of the original project. We requested regulatory approval in late September 2006 to increase the scope and size of the original project. We expect to decide in 2007 whether to proceed with this expansion, which could eventually add an additional 35,000 barrels per day of production.
Deep Basin Our properties in Canadas Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 646,000 net acres in the Deep Basin. The area produces primarily natural gas and natural gas liquids from conventional reservoirs. Our average working interest in the
Deep Basin is 46%. We drilled 115 gross wells in the Deep Basin in 2006 and plan to drill 57 gross wells in the area in 2007.
Lloydminster Our Lloydminster properties are located to the south and east of Jackfish in eastern Alberta and western Saskatchewan. Lloydminster produces heavy oil by conventional means without steam injection. We hold 2.1 million net acres and have a 97% average working interest in our Lloydminster properties. In 2006, we drilled 397 gross wells in the area and plan to drill 395 gross wells in 2007.
Peace River Arch The Peace River Arch is located in west central Alberta. We hold approximately 476,000 net acres in the area, which produces primarily natural gas and natural gas liquids from conventional reservoirs. Our average working interest in the area is about 69%. We drilled 82 gross wells in the Peace River Arch in 2006, and we expect to drill 62 additional wells here in 2007.
Northeast British Columbia Our Northeast British Columbia properties are located primarily in British Columbia and to a lesser extent in north western Alberta. We hold approximately 1.2 million net acres in the area. These properties produce principally natural gas from conventional reservoirs. We hold a 72% average working interest in these properties. We drilled 64 gross wells in the area in 2006, and we plan to drill 68 wells here in 2007.
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. Our production from ACG increased significantly in late 2006 following the payout of carried interest agreements with various partners in the field. Our production will increase again in 2007 as we benefit from a full year of the higher ownership interest after these payouts. We expect our share of ACG production in 2007 to total approximately 12 MMBoe. ACG produces crude oil from conventional reservoirs. We hold approximately 6,000 net acres in the ACG field and have a 5.6% working interest. In 2006, we participated in drilling 15 gross wells at ACG and expect to drill 13 gross wells in 2007.
China Our production in China is from the Panyu field in the Pearl River Mouth Basin in the South China Sea. Panyu produces oil from conventional reservoirs. In addition to Panyu, which is located on block 15/34, we also hold leases in two exploratory blocks offshore China. In total, we have 4.4 million net acres under lease in China. We have a 24.5% working interest at Panyu and 100% working interests in the exploratory blocks. We drilled six gross wells in China in 2006, all in the Panyu field. In 2007, we expect to drill seven gross wells in the Panyu field.
Brazil We expect to commence oil production in Brazil in 2007 from our Polvo field. Polvo, which we operate with a 60% interest, is located offshore in block BM-C-8. In addition to our development project at Polvo, we also hold acreage in nine exploratory blocks. In aggregate, we have 835,000 net acres in Brazil. Our working interests range from 18% to 100% in these blocks. We drilled three gross wells in Brazil in 2006 and plan to drill 11 gross wells in Brazil in 2007.
Equatorial Guinea All of our oil production from the West African country of Equatorial Guinea is from the offshore Zafiro field in the Gulf of Guinea. Zafiro is located on block B, and we also have interests in three additional exploratory blocks. We hold 518,000 net acres in the four blocks combined. Zafiro produces crude oil from conventional reservoirs. Our working interests (participating interests under the terms of the production sharing contracts) range from 24% to 38% in the four blocks. In 2006, we drilled 10 gross wells in Equatorial Guinea, all in the Zafiro field. In 2007, we plan to drill 10 gross wells in Equatorial Guinea. Equatorial Guinea is included in the West African assets we intend to sell during 2007.
Title to properties 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, generally including a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the Wright case). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. On February 1, 2006, the Court entered a scheduling order in which trial is set for November 2007. We believe we have acted reasonably, have legitimate and strong defenses to all allegations in the suit, and have paid royalties in good faith. We do not currently believe that we are subject to material exposure in association with this lawsuit and no related liability has been recorded in our consolidated financial statements.
The SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, we received a subpoena issued by the SEC pursuant to a formal order of investigation. We have cooperated fully with the SECs requests for information in this inquiry. After responding in 2005 to such requests for information, we have not been contacted by the SEC. In the event that we receive any further inquiries, we will work with the SEC in connection with its investigation.
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 2006.
Our common stock is traded on the New York Stock Exchange (the NYSE). On February 15, 2007, there were 16,228 holders of record of our common stock. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE and dividends paid per share.
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.
On August 3, 2005, we announced that our Board of Directors had authorized the repurchase of up to 50 million shares of our common stock. As of the end of the fourth quarter of 2006, 43.5 million shares remain available for purchase under this program. We suspended this stock repurchase program during the second quarter of 2006 in conjunction with our acquisition of Chief. In conjunction with the sales of our Egyptian and West African assets in 2007, we expect to resume this program in late 2007 by using a portion of the sale proceeds to repurchase common stock. Although this program expires at the end of 2007, it could be extended if necessary.
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. Reference is made to Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data. Our discussion and analysis will relate to the following subjects:
Devon is one of the largest U.S. based independent oil and gas producers and processors of natural gas and natural gas liquids in North America. Our portfolio of oil and gas properties provides stable production and a platform for future growth. About 90 percent of our production is from North America. We also operate in selected international areas, including Azerbaijan, Brazil and China. Our production mix is about 65 percent natural gas and 35 percent oil and natural gas liquids such as propane, butane and ethane. We are currently producing about 2.3 billion cubic feet of natural gas each day, or about 3 percent of all the gas consumed in North America.
In managing our global operations, we have an operating strategy that is focused on creating and increasing value per share. Key elements of this strategy are replacing oil and gas reserves, growing production and exercising capital discipline. We must also control operating costs and manage commodity pricing risks to achieve long-term success. The discussion and analysis of our results of operations and other related information will refer to these factors.
2006 was one of the best years in Devons history. We achieved key operational successes and continued to execute our strategy to increase value per share. As a result, we delivered record amounts for earnings per share and operating cash flow and grew proved reserves to a new all-time high. Key measures of our financial and operating performance for 2006, as well as certain operational developments, are summarized below:
We produced 214 million Boe in 2006, representing a 4% decrease compared to 2005. Excluding the effects of production lost due to the sale of non-core properties in the first half of 2005, our year-over-year production remained constant. Operating costs increased due to inflationary pressure driven by the effects of
higher commodity prices and due to the weakened U.S. dollar compared to the Canadian dollar. Per unit lease operating expenses increased 17% to $6.95 per Boe.
During 2006, we utilized cash on hand, cash flow from operations, and $1.8 billion of commercial paper borrowings to fund our capital expenditures, repay $862 million in debt and repurchase $253 million of our common stock. We ended the year with $1.3 billion of cash and short-term investments.
From an operational perspective, our deepwater Gulf of Mexico exploration program has reached several important milestones related to the Lower Tertiary trend. To date, we have drilled four discovery wells in the Lower Tertiary Cascade in 2002, St. Malo in 2003, Jack in 2004 and Kaskida in the third quarter of 2006. Also in the third quarter of 2006, we announced the successful production test of the Jack No. 2 well in the Lower Tertiary. We currently hold 273 blocks in the Lower Tertiary and have identified 19 additional exploratory prospects within these blocks to date. These achievements support our positive view of the Lower Tertiary and demonstrate the growth potential of our high-impact exploration strategy on long-term production, reserves and value.
On June 29, 2006, we acquired Chiefs oil and gas assets located in the Barnett Shale area of Texas for $2.2 billion. This transaction added 99.7 million Boe of proved reserves and 169,000 net acres to our Barnett Shale assets. This acquisition combined with our organic growth continues to extend our leadership position in the Barnett Shale and provides years of additional drilling inventory.
On November 14, 2006, we announced our plans to divest our operations in Egypt. At December 31, 2006, Egypt had proved reserves of eight million Boe. Subsequently, on January 23, 2007, we announced our plans to divest our operations in West Africa, including Equatorial Guinea, Cote dIvoire, and other countries in the region. At December 31, 2006, our West Africa operations had proved reserves of 90 million Boe, or 4% of total proved reserves. We anticipate completing the sale of our Egyptian assets in the first half of 2007 and our West African assets in the third quarter of 2007. Divesting these properties will allow us to redeploy our financial and intellectual capital to the significant growth opportunities we have developed onshore in North America and in the deepwater Gulf of Mexico. Additionally, we will sharpen our focus in North America and concentrate our international operations in Brazil and China, where we have established competitive advantages.
Looking to 2007, we intend to use the proceeds from the sales of our operations in Egypt and West Africa to repay our outstanding commercial paper and resume common stock repurchases. In addition, our operational accomplishments to date have laid the foundation for continued growth in future years, at competitive unit costs, that we expect will continue to create additional value for our investors. In 2007, we expect to deliver reserve additions of 350 to 370 million Boe with related capital expenditures in the range of $5.3 to $5.7 billion. We expect production related to our continuing operations to increase approximately 10% from 2006 to 2007, which reflects the significant reserve additions in 2005 and 2006, and those expected in 2007.
Results of Operations
Changes in oil, gas and NGL production, prices and revenues from 2004 to 2006 are shown in the following tables. The amounts for all periods presented exclude our Egyptian operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
The average prices shown in the preceding tables include the effect of our oil and gas price hedging activities. Following is a comparison of our average prices with and without the effect of hedges for each of the last three years.
The following table details the effects of changes in volumes and prices on our oil, gas and NGL revenues between 2004 and 2006.
2006 vs. 2005 Oil revenues decreased $270 million due to a seven million barrel decrease in production. Production lost from properties divested in 2005 accounted for four million barrels of the decrease. A contractual reduction of our share of production from one of our international properties in mid-2005 also lowered 2006 volumes. These decreases were partially offset by a three million barrel increase in production resulting from reaching payout of certain carried interests in Azerbaijan.
Oil revenues increased $1.1 billion as a result of a 53% increase in our realized price. The expiration of oil hedges at the end of 2005 and a 17% increase in the average NYMEX West Texas Intermediate index price caused the increase in our realized oil price.
2005 vs. 2004 Oil revenues decreased $347 million due to a 12 million barrel decrease in production. Production lost from the 2005 property divestitures accounted for seven million barrels of the decrease. We also suspended certain domestic production in 2005 and 2004 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The volumes suspended in 2005 were one million barrels more than in 2004. The remainder of the decrease is due to certain international properties in which our ownership interest decreased after we recovered our costs under the applicable production sharing contracts.
Higher realized prices caused oil revenues to increase $607 million in 2005. Our 2005 oil prices rose primarily due to a 37% increase in the average NYMEX West Texas Intermediate index price.
2006 vs. 2005 A 12 Bcf decrease in production caused gas revenues to decrease by $86 million. Production lost from the 2005 property divestitures caused a decrease of 35 Bcf. As a result of the previously mentioned hurricanes, gas volumes suspended in 2006 were three Bcf more than those suspended in 2005. These decreases were partially offset by the June 2006 Chief acquisition, which contributed 10 Bcf of production during the last half of 2006, and additional production from new drilling and development in our U.S. onshore and offshore properties.
A 13% decline in average prices caused gas revenues to decrease $766 million in 2006.
2005 vs. 2004 A 64 Bcf decrease in production caused gas revenues to decrease by $337 million. Production associated with the 2005 property divestitures caused a decrease of 89 Bcf. We also suspended certain domestic gas production in 2005 and 2004 due to the previously mentioned hurricanes. The volumes suspended in 2005 were 12 Bcf more than in 2004. These decreases were partially offset by new drilling and development and increased performance in U.S. onshore and offshore properties.
A 32% increase in average gas prices contributed $1.4 billion of additional revenues in 2005.
The following table details the changes in our marketing and midstream revenues and operating costs and expenses between 2004 and 2006. The changes due to prices in the table represent the net effect on both revenues and expenses due to changes in the market prices for natural gas and NGLs.
2006 vs. 2005 Volume increases in our gas pipeline, gas sales and NGL marketing activities caused both revenues and expenses to increase in 2006. This additional activity was primarily due to our continued growth in the Barnett Shale and higher natural gas deliveries from third-party producers.
2005 vs. 2004 Volume decreases in 2005 caused both revenues and expenses to decline in 2005. The lower activity was primarily attributable to the sale of certain non-core assets in 2004 and 2005.
The details of the changes in oil, gas and NGL production and operating expenses between 2004 and 2006 are shown in the table below.
2006 vs. 2005 Lease operating expenses increased $164 million in 2006 largely due to higher commodity prices. Commodity price increases in 2005 and the first half of 2006 contributed to industry-wide inflationary pressures on materials and personnel costs. Additionally, consideration of higher commodity prices contributed to our decision to perform more well workovers and maintenance projects to maintain or improve production volumes. Commodity price increases also caused operating costs such as ad valorem taxes, power and fuel costs to rise.
A higher Canadian-to-U.S. dollar exchange rate in 2006 caused a $34 million increase in our costs. Lease operating expenses also increased $33 million due to the June 2006 Chief acquisition and the payouts of our carried interests in Azerbaijan in the last half of 2006. The increases in our lease operating expenses were partially offset by a decrease of $82 million related to properties that were sold in 2005.
The factors described above were also the primary factors causing lease operating expenses per Boe to increase during 2006. Although we divested properties in 2005 that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar had a greater effect on our per unit costs than the property divestitures.
2005 vs. 2004 Lease operating expenses increased $65 million in 2005 largely due to higher commodity prices. As addressed above, commodity price increases led to overall industry inflation. Additionally, a higher Canadian-to-U.S. dollar exchange rate in 2005 caused a $30 million increase in 2005. Partially offsetting these increases was a decrease of $144 million in lease operating expenses related to properties that were sold in 2005.
The increases described above were also the primary factors causing lease operating expenses per Boe to increase. Although we divested properties that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar had a greater effect on our per unit costs than the property divestitures.
The following table details the changes in production taxes between 2004 and 2006. The majority of our production taxes are assessed on our onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the changes due to revenues in the table primarily relate to changes in oil, gas and NGL revenues from our U.S. onshore properties.
2006 vs. 2005 Production taxes increased $29 million due to an increase in the effective production tax rate in 2006. A new Chinese Special Petroleum Gain tax was the primary contributor to the higher rate.
2005 vs. 2004 Production taxes increased $30 million due to an increase in the effective production tax rate in 2005. An increase in Russian export tax rates was the primary contributor to the higher rate.
DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the depletable base. The depletable base represents the net capitalized investment plus future development costs in those reserves. Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by
production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.
The following table details the changes in DD&A of oil and gas properties between 2004 and 2006. The changes due to volumes in the table represent the effect on DD&A due to decreases in combined oil, gas and NGL production.
2006 vs. 2005 Oil and gas property related DD&A increased $370 million in 2006 due to an increase in the DD&A rate from $8.86 per Boe in 2005 to $10.59 per Boe in 2006. The largest contributor to the rate increase was inflationary pressure on both the costs incurred during 2006 as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase include the June 2006 Chief acquisition and the transfer of previously unproved costs to the depletable base as a result of 2006 drilling activities. A reduction in reserve estimates due to the effects of 2006 year-end commodity prices also contributed to the rate increase.
2005 vs. 2004 Oil and gas property related DD&A increased $99 million in 2005 due to an increase in the DD&A rate from $8.41 per Boe in 2004 to $8.86 per Boe in 2005. The largest contributor to the rate increase was the effect of inflationary pressure on finding and development costs for reserve discoveries and extensions. Changes in the Canadian-to-U.S. dollar exchange rate also caused the rate to increase. These increases were partially offset by a decrease in the rate as a result of our 2005 property divestitures.
Our net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a 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.
2006 vs. 2005 Gross G&A increased $192 million. Higher employee compensation and benefits costs caused gross G&A to increase $149 million. Of this increase, $34 million represented stock option expense recognized pursuant to our adoption in 2006 of Statement of Financial Accounting Standard No. 123(R), Share-Based Payment. An additional $28 million of the increase related to higher restricted stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $11 million increase in costs.
2005 vs. 2004 Gross G&A increased $32 million. Higher employee compensation and benefits costs caused gross G&A to increase $35 million. Of this increase, $17 million related to higher restricted stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $9 million increase in costs. These increases were partially offset by an $8 million decrease in rent expense resulting primarily from the abandonment of certain Canadian office space in 2004.
The factors discussed above were also the primary factors that caused the $88 million and $15 million increases in capitalized G&A in 2006 and 2005, respectively.
The following schedule includes the components of interest expense between 2004 and 2006.
Interest based on debt outstanding decreased from 2004 to 2006 primarily due to the net effect of debt repayments during 2005 and 2006. This was partially offset by the effect of increased commercial paper borrowings during the last half of 2006 related to the acquisition of the Chief properties.
During 2005, we redeemed our $400 million 6.75% notes due March 15, 2011 and our zero coupon convertible senior debentures prior to their scheduled maturity dates. The other interest category in the table above includes $81 million in 2005 related to these early retirements.
During 2004, we repaid the balance under our $3 billion term loan credit facility prior to the scheduled repayment date. The other interest category in the table above includes $16 million in 2004 related to this early repayment.
During 2006 and 2005, we reduced the carrying value of certain of our oil and gas properties due to full cost ceiling limitations and unsuccessful exploratory activities. A detailed description of how full cost ceiling limitations are determined is included in the Critical Accounting Policies and Estimates section of this report. A summary of these reductions and additional discussion is provided below.
We have committed to drill four wells in Nigeria. The first two wells were unsuccessful. After drilling the second unsuccessful well in the first quarter of 2006, we determined that the capitalized costs related to these two wells should be impaired. Therefore, in the first quarter of 2006, we recognized an $85 million impairment of our investment in Nigeria equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There was no tax benefit related to this impairment.
During the second quarter of 2006, we drilled two unsuccessful exploratory wells in Brazil and determined that the capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, we recognized a $16 million impairment of our investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There was no tax benefit related to this impairment. The two wells were unrelated to Devons Polvo development project in Brazil.
As a result of a decline in projected future net cash flows, the carrying value of our Russian properties exceeded the full cost ceiling by $10 million at the end of the third quarter of 2006. Therefore, we recognized a $20 million reduction of the carrying value of our oil and gas properties in Russia, offset by a $10 million deferred income tax benefit.
Our interests in Angola were acquired through the 2003 Ocean Energy merger. Our Angolan drilling program discovered no proven reserves. After drilling three unsuccessful wells in the fourth quarter of 2005, we determined that all of the Angolan capitalized costs should be impaired.
Prior to the fourth quarter of 2005, we were capitalizing the costs of previous unsuccessful efforts in Brazil pending the determination of whether proved reserves would be recorded in Brazil. We have been successful in our drilling efforts on block BM-C-8 in Brazil and are currently developing the Polvo project on this block. The ultimate value of the Polvo project is expected to be in excess of the sum of its related costs, plus the costs of the previous unrelated unsuccessful efforts in Brazil which were capitalized. However, the Polvo proved reserves will be recorded over a period of time. At the end of 2005, it was expected that a small initial portion of the proved reserves ultimately expected at Polvo would be recorded in 2006. Based on preliminary estimates developed in the fourth quarter of 2005, the value of this initial partial booking of proved reserves was not sufficient to offset the sum of the related proportionate Polvo costs plus the costs of the previous unrelated unsuccessful efforts. Therefore, we determined that the prior unsuccessful costs unrelated to the Polvo project should be impaired. These costs totaled approximately $42 million. There was no tax benefit related to this Brazilian impairment.
The details of the changes in fair value of derivative financial instruments between 2004 and 2006 are shown in the table below.
The change in the fair value of the embedded option relates to the debentures exchangeable into shares of Chevron Corporation common stock. These expenses were caused primarily by increases in the price of Chevron Corporations common stock.
In 2005, we recognized a $39 million loss on certain oil derivative financial instruments that no longer qualified for hedge accounting because the hedged production exceeded actual and projected production under these contracts. The lower than expected production was caused primarily by hurricanes that affected offshore production in the Gulf of Mexico.
The following schedule includes the components of other income between 2004 and 2006.
Interest and dividend income increased from 2004 to 2005 primarily due to an increase in cash and short-term investment balances and higher interest rates.
During 2005, we sold certain non-core midstream assets for a net gain of $150 million. Also during 2005, we incurred a $55 million loss on certain commodity hedges that no longer qualified for hedge accounting and were settled prior to the end of their original term. These hedges related to U.S. and Canadian oil production from properties sold as part of our 2005 property divestiture program. This loss was partially offset by a $7 million gain related to interest rate swaps that were settled prior to the end of their original term in conjunction with the early redemption of the $400 million 6.75% senior notes in 2005.
The gains in 2005 and 2004 from changes in foreign exchange rates were primarily related to $400 million of Canadian subsidiary debt that was denominated in U.S. dollars. The debt was retired in 2005.
The following table presents our total income tax expense related to continuing operations and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate for each of the past three years. The primary factors causing our effective rates to vary from 2004 to 2006, and differ from the U.S. statutory rate, are discussed below.
In 2006, 2005 and 2004, deferred income taxes were reduced $243 million, $14 million and $36 million, respectively, due to Canadian statutory rate reductions that were enacted in each such year.
In 2006, deferred income taxes increased $39 million due to the effect of a new income-based tax enacted by the state of Texas that replaces a previous franchise tax. The new tax is effective January 1, 2007.
In 2006 and 2005, income taxes were reduced $12 million and $25 million, respectively, due to a new U.S. tax deduction for companies with domestic production activities, including oil and gas extraction.
In 2005, we recognized $28 million of taxes related to our repatriation of $545 million to the U.S. The cash was repatriated due to tax legislation that allowed qualifying companies to repatriate cash from foreign operations at a reduced income tax rate. Substantially all of the cash repatriated by us in 2005 related to earnings of our Canadian subsidiary.
Results of Discontinued Operations
On November 14, 2006, we announced our plans to divest our operations in Egypt. We anticipate completing the sale of our Egyptian operations in the first half of 2007. Pursuant to accounting rules for discontinued operations, Egypt is considered a discontinued operation at the end of 2006. As a result, the Egypt financial results for 2006 and all prior periods have been reclassified and are presented as discontinued operations.
Following are the components of the results of discontinued operations between 2004 and 2006.
Capital Resources, Uses and Liquidity
The following discussion of capital resources and liquidity should be read in conjunction with the consolidated financial statements included in Item 8. Financial Statements and Supplementary Data.
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents from 2004 to 2006. The table presents capital expenditures on a cash basis. Therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this document. Additional discussion of these items follows the table.
Net cash provided by operating activities (operating cash flow) is our primary source of capital and liquidity. Changes in operating cash flow are largely due to the same factors that affect our net earnings, with the exception of those earnings changes due to such noncash expenses as DD&A, property impairments, derivative fair value changes and deferred income tax expense. As a result, our operating cash flow increased in 2006 and 2005 compared to the previous years largely due to increases in net earnings, as discussed in the Results of Operations section of this report.
In 2005, we generated $2.2 billion in pre-tax proceeds from sales of property and equipment. These consisted of $2.0 billion related to the sale of non-core oil and gas properties and $0.2 billion related to the sale of non-core midstream assets. Net of related income taxes, these proceeds were $1.8 billion for oil and gas properties and $0.1 billion for midstream assets.
On June 29, 2006, we acquired Chief for $2 billion of cash and the assumption of $0.2 billion of liabilities. We funded a portion of the purchase price with $1.4 billion of borrowings issued under our commercial paper program. As a result of the Chief acquisition and success in other onshore U.S. locations, we accelerated certain oil and gas development activities into the last half of 2006. We borrowed an additional $0.4 billion of commercial paper to fund this accelerated development.
The increases in operating cash flow have enabled us to invest larger amounts in capital projects. As a result, excluding the acquisition of the Chief properties, our capital expenditures increased 38% in 2006. The majority of this increase related to our expenditures for the acquisition, drilling or development of oil and gas properties, which totaled $5.0 billion in 2006, excluding the Chief acquisition. Inflationary pressure driven by higher commodity prices and increased drilling activities in the Barnett Shale, Gulf of Mexico, Carthage and Groesbeck areas of the U.S. contributed to the increase. In addition, the payouts of our carried interests in Azerbaijan in the last half of 2006 and the weaker U.S. dollar impact on our Canadian operations also contributed to the increase.
Capital expenditures in 2005 increased 32% compared to 2004 primarily due to an increase in our expenditures for the acquisition, drilling or development of oil and gas properties, which totaled $3.9 billion in 2005. Increased drilling activities in the Barnett Shale, the approximately $200 million acquisition of Iron River acreage in Canada and the $74 million purchase of the Serpentina FPSO in offshore Equatorial Guinea were large contributors to the increase. Inflationary pressure driven by higher commodity prices and the weaker U.S. dollar also caused our expenditures to increase from 2004 to 2005.
Our net debt retirements were $0.9 billion, $1.3 billion and $1.0 billion in 2006, 2005 and 2004, respectively. These amounts consisted of payments at the scheduled maturity dates with the exception of the following payments. The 2006 amount includes $0.2 billion related to the repayment of debt acquired in the Chief acquisition. The 2005 amount includes $0.8 billion related to the retirement of zero coupon convertible debentures due in 2020 and 6.75% notes due in 2011. The 2004 amount includes $635 million for the payment of the outstanding balance under a $3 billion term loan credit facility due in 2006.
In August 2005, we completed a share repurchase program that began in October 2004. Under this program, we repurchased 49.6 million shares of our common stock at a total cost of $2.3 billion, or $46.69 per share. In August 2005, we announced another program to repurchase up to an additional 50 million shares of our common stock. During 2005 and 2006, we repurchased 6.5 million shares for $387 million, or $59.80 per share, under this program.
Our common stock dividends were $199 million, $136 million and $97 million in 2006, 2005 and 2004, respectively. We also paid $10 million of preferred stock dividends in 2006, 2005 and 2004. The 2006 and 2005 increases in common stock dividends were primarily related to a 50% increase in the dividend rate in the first quarter of both 2006 and 2005, partially offset by a decrease in outstanding shares due to share repurchases.
To maximize our income on available cash balances, we invest in highly liquid, short-term investments. The purchase and sale of these short-term investments will cause cash and cash equivalents to decrease and
increase, respectively. Short-term investment balances decreased $106 million and $287 million in 2006 and 2005, respectively, and increased $626 million in 2004.
Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain a revolving line of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. During 2007, another major source of liquidity will be proceeds from the sales of our operations in Egypt and West Africa. We expect the combination of these sources of capital will be more than adequate to fund future capital expenditures, debt repayments, common stock repurchases, and other contractual commitments as discussed later in this section.
Our operating cash flow has increased nearly 25% since 2004, reaching a total of $5.9 billion in 2006. We expect operating cash flow to continue to be our primary source of liquidity. Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.
We periodically believe it appropriate to mitigate some of the risk inherent in oil and natural gas prices. We have used a variety of avenues to achieve this partial risk mitigation. We have utilized price collars to set minimum and maximum prices on a portion of our production. We have also utilized various price swap contracts and fixed-price physical delivery contracts to fix the price to be received for a portion of future oil and natural gas production. Based on contracts currently in place, approximately 5% of our estimated 2007 natural gas production (3% of our total Boe production) is subject to either price collars, swaps or fixed-price contracts.
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases, as experienced in recent years, can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow.
Another source of liquidity is our $2.5 billion five-year, syndicated, unsecured revolving line of credit (the Senior Credit Facility). The Senior Credit Facility includes a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million. Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2006, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of December 31, 2006, net of $1.8 billion of outstanding commercial paper and $284 million of outstanding letters of credit, was approximately $408 million.
The Senior Credit Facility matures on April 7, 2011, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 7 anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. We are working to obtain lender approval to extend the current maturity date of April 7, 2011 to April 7, 2012. If successful, this maturity date extension will be effective April 7, 2007, provided we have not experienced a material adverse effect, as defined in the Senior Credit Facility agreement, at that date.
The Senior Credit Facility contains only one material financial covenant. This covenant requires our ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in our
consolidated financial statements. As defined in the agreement, total funded debt excludes the debentures that are exchangeable into shares of Chevron Corporation common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2006, our debt to capitalization ratio as calculated pursuant to this covenant was 27.3%.
Our access to funds from the Senior Credit Facility is not restricted under any material adverse effect clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrowers financial condition, operations, properties or business considered as a whole, the borrowers ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our Senior Credit Facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.
We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $2 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. As of December 31, 2006, we had $1.8 billion of commercial paper debt outstanding at an average rate of 5.37%.
We receive debt ratings from the major ratings agencies in the United States. In determining our debt ratings, the agencies consider a number of items including, but not limited to, debt levels, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Liquidity, asset quality, cost structure, reserve mix, and commodity pricing levels are also considered by the rating agencies. Our current debt ratings are BBB with a positive outlook by Standard & Poors, Baa2 with a positive outlook by Moodys and BBB with a positive outlook by Fitch.
There are no rating triggers in any of our contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs for the Senior Credit Facility from LIBOR plus 45 basis points to a new rate of LIBOR plus 65 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2006, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.
In February 2007, we provided guidance for our 2007 capital expenditures which are expected to range from $5.7 billion to $6.2 billion. This represents the largest planned use of our 2007 operating cash flow, with the high end of the range being 11% higher than our 2006 capital expenditures, excluding the Chief acquisition. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if oil and natural gas prices fluctuate from current estimates, we could choose to defer a portion of these planned 2007 capital expenditures until later periods, or accelerate capital expenditures planned for periods beyond 2007 to achieve the desired balance between sources and uses of liquidity. Based upon current oil and natural gas price expectations for 2007, we anticipate having adequate capital resources to fund our 2007 capital expenditures.
In August 2005, we announced a program to repurchase up to 50 million shares of our common stock. We had repurchased 6.5 million shares under this program through the middle of 2006 when the program was suspended as a result of the Chief acquisition. In conjunction with the sales of our Egyptian and West African operations, we expect to resume this repurchase program in late 2007 by using a portion of the sales proceeds to repurchase common stock. Although this program expires at the end of 2007, it could be extended if necessary.
A summary of our contractual obligations as of December 31, 2006, is provided in the following table.
Funded Status. As compared to the projected benefit obligation, our qualified and nonqualified defined benefit plans were underfunded by $178 million and $133 million at December 31, 2006 and 2005, respectively. A detailed reconciliation of the 2006 changes to our underfunded status is included in Note 6 to the accompanying consolidated financial statements. Of the $178 million underfunded status at the end of 2006, $156 million is attributable to various nonqualified defined benefit plans which have no plan assets. However, we have established certain trusts to fund the benefit obligations of such nonqualified plans. As of December 31, 2006, these trusts had investments with a fair value of $59 million. The value of these trusts is included in noncurrent other assets in our accompanying consolidated balance sheets.
As compared to the accumulated benefit obligation, our qualified defined benefit plans were overfunded by $59 million at December 31, 2006. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. Our current intentions are to provide sufficient funding in future years to ensure the accumulated benefit obligation remains fully funded. The actual amount of contributions required during this period will depend on investment returns from the plan assets. Required contributions also depend upon changes in actuarial assumptions made during the same period, particularly the discount rate used to calculate the present value of the accumulated benefit obligation. For 2007, we anticipate the accumulated benefit obligation will remain fully funded without contributing to our defined benefit plans. Therefore, we dont expect to contribute to the plans during 2007.
Pension Estimate Assumptions. Our pension expense is recognized on an accrual basis over employees approximate service periods and is generally calculated independent of funding decisions or requirements. We recognized expense for our defined benefit pension plans of $31 million, $26 million and $26 million in 2006, 2005 and 2004, respectively. We estimate that our pension expense will approximate $43 million in 2007.
The calculation of pension expense and pension liability requires the use of a number of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. We believe that the two most critical assumptions affecting pension expense and liabilities are the expected long-term rate of return on plan assets and the assumed discount rate.
We assumed that our plan assets would generate a long-term weighted average rate of return of 8.40% at both December 31, 2006 and 2005. We developed these expected long-term rate of return assumptions by
evaluating input from external consultants and economists as well as long-term inflation assumptions. The expected long-term rate of return on plan assets is based on a target allocation of investment types in such assets. The target investment allocation for our plan assets is 50% U.S. large cap equity securities; 15% U.S. small cap equity securities, equally allocated between growth and value; 15% international equity securities, equally allocated between growth and value; and 20% debt securities. We expect our long-term asset allocation on average to approximate the targeted allocation. We regularly review our actual asset allocation and periodically rebalance the investments to the targeted allocation when considered appropriate.
Pension expense increases as the expected rate of return on plan assets decreases. A decrease in our long-term rate of return assumption of 100 basis points (from 8.40% to 7.40%) would increase the expected 2007 pension expense by $6 million.
We discounted our future pension obligations using a weighted average rate of 5.72% at both December 31, 2006 and 2005. The discount rate is determined at the end of each year based on the rate at which obligations could be effectively settled. This rate is based on high-quality bond yields, after allowing for call and default risk. We consider high quality corporate bond yield indices, such as Moodys Aa, when selecting the discount rate.
The pension liability and future pension expense both increase as the discount rate is reduced. Lowering the discount rate by 25 basis points (from 5.72% to 5.47%) would increase our pension liability at December 31, 2006, by $25 million, and increase estimated 2007 pension expense by $3 million.
At December 31, 2006, we had actuarial losses of $214 million which will be recognized as a component of pension expense in future years. These losses are primarily due to reductions in the discount rate since 2001 and increases in participant wages. We estimate that approximately $15 million and $13 million of the unrecognized actuarial losses will be included in pension expense in 2007 and 2008, respectively. The $15 million estimated to be recognized in 2007 is a component of the total estimated 2007 pension expense of $43 million referred to earlier in this section.
Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our defined benefit pension plans will impact future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.
On August 17, 2006, the Pension Protection Act was signed into law. Beginning in 2008, this act will cause extensive changes in the determination of both the minimum required contribution and the maximum tax deductible limit. Because the new required contribution will approximate our current policy of fully funding the accumulated benefit obligation, the changes are not expected to have a significant impact on future cash flows.
Beginning with our December 31, 2006 balance sheet, Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106, and 132(R), requires us to recognize on our consolidated balance sheet the funded status of our defined benefit plans. The funded status is measured as the difference between the projected benefit obligation and the fair value of plan assets. As a result, we recognized as liabilities the actuarial losses and other costs that were previously unrecognized under prior accounting rules, and the net effect was also recorded as a reduction to stockholders equity on December 31, 2006. This reduction was $140 million, or less than 1% of our stockholders equity.
For a detailed discussion of contingencies and legal matters, see Item 3. Legal Proceedings and Note 8 of the accompanying consolidated financial statements.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known.
The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regard to estimates used. Our critical accounting policies and significant judgments and estimates related to those policies are described below. We have reviewed these critical accounting policies with the Audit Committee of the Board of Directors.
Full Cost Ceiling Calculations
We follow the full cost method of accounting for our oil and gas properties. The full cost method subjects companies to quarterly calculations of a ceiling, or limitation on the amount of properties that can be capitalized on the balance sheet. The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense, except as discussed in the following paragraph. The ceiling limitation is imposed separately for each country in which we have oil and gas properties.
If, subsequent to the end of the quarter but prior to the applicable financial statements being published, prices increase to levels such that the ceiling would exceed the costs to be recovered, a writedown otherwise indicated at the end of the quarter is not required to be recorded. A writedown indicated at the end of a quarter is also not required if the value of additional reserves proved up on properties after the end of the quarter but prior to the publishing of the financial statements would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end of the quarter. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
The discounted present value of future net revenues for our proved oil, natural gas and NGL reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Certain of our reserve estimates are prepared or audited by outside petroleum consultants, while other reserve estimates are prepared by our engineers. See Note 15 of the accompanying consolidated financial statements.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. In the past five years, annual revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 1% of the previous years estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that a 10% discount factor be used
and that prices and costs in effect as of the last day of the period are held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs. Rather, they are based on such prices and costs in effect as of the end of each quarter when the ceiling calculation is performed. In calculating the ceiling, we adjust the end-of-period price by the effect of cash flow hedges in place. This adjustment requires little judgment as the end-of-period price is adjusted using the contract prices for our cash flow hedges. We had no such hedges outstanding at December 31, 2006.
Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been volatile. On any particular day at the end of a quarter, prices can be either substantially higher or lower than our long-term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Derivative Financial Instruments
The majority of our historical derivative instruments have consisted of commodity financial instruments used to manage our cash flow exposure to oil and gas price volatility. We have also entered into interest rate swaps to manage our exposure to interest rate volatility. The interest rate swaps mitigate either the cash flow effects of interest rate fluctuations on interest expense for variable-rate debt instruments, or the fair value effects of interest rate fluctuations on fixed-rate debt. We also have an embedded option derivative related to the fair value of our debentures exchangeable into shares of Chevron Corporation common stock.
All derivatives are recognized at their current fair value on our balance sheet. Changes in the fair value of derivative financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. If such criteria are met for cash flow hedges, the effective portion of the change in the fair value is recorded directly to accumulated other comprehensive income, a component of stockholders equity, until the hedged transaction occurs. The ineffective portion of the change in fair value is recorded in the statement of operations. If hedge accounting criteria are met for fair value hedges, the change in the fair value is recorded in the statement of operations with an offsetting amount recorded for the change in fair value of the hedged item.
A derivative instrument qualifies for hedge accounting treatment if we designate the instrument as such on the date the derivative contract is entered into or the date of an acquisition or business combination which includes derivative contracts. Additionally, we must document the relationship between the hedging instrument and hedged item, as well as the risk-management objective and strategy for undertaking the instrument. We must also assess, both at the instruments inception and on an ongoing basis, whether the derivative is highly effective in offsetting the change in cash flow of the hedged item.
The estimates of the fair values of our commodity derivative instruments require substantial judgment. For these instruments, we obtain forward price and volatility data for all major oil and gas trading points in North America from independent third parties. These forward prices are compared to the price parameters contained in the hedge agreements. The resulting estimated future cash inflows or outflows over the lives of the hedge contracts are discounted using LIBOR and money market futures rates for the first year and money market futures and swap rates thereafter. In addition, we estimate the option value of price floors and price caps using an option pricing model. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices, regional price differentials and interest rates. Fair values of our other derivative instruments require less judgment to estimate and are primarily based on quotes from independent third parties such as counterparties or brokers.
Quarterly changes in estimates of fair value have only a minimal impact on our liquidity, capital resources or results of operations, as long as the derivative instruments qualify for hedge accounting treatment. Changes in the fair values of derivatives that do not qualify for hedge accounting treatment can have a significant impact on our results of operations, but generally will not impact our liquidity or capital resources. Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding the effects that changes in market prices will have on our derivative financial instruments, net earnings and cash flow from operations is included in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
We have grown substantially during recent years through acquisitions of other oil and natural gas companies. Most of these acquisitions have been accounted for using the purchase method of accounting, and recent accounting pronouncements require that all future acquisitions will be accounted for using the purchase method.
Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired companys assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill is assessed for impairment at least annually.
There are various assumptions we make in determining the fair values of an acquired companys assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by our engineers and that of outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.
However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies end-of-period price and cost information to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a business combination must be based on our estimates of future oil, natural gas and NGL prices. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.
We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the business combination based upon our cost of capital.
We also apply these same general principles to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we consider to be an appropriate risk-weighting factor in each particular instance. It is common for the discounted future net
revenues of probable and possible reserves to be reduced by factors ranging from 30% to 80% to arrive at what we consider to be the appropriate fair values.
Generally, in our business combinations, the determination of the fair values of oil and gas properties requires much more judgment than the fair values of other assets and liabilities. The acquired companies commonly have long-term debt that we assume in the acquisition, and this debt must be recorded at the estimated fair value as if we had issued such debt. However, significant judgment on our behalf is usually not required in these situations due to the existence of comparable market values of debt issued by peer companies.
Except for the 2002 Mitchell merger, our mergers and acquisitions have involved other entities whose operations were predominantly in the area of exploration, development and production activities related to oil and gas properties. However, in addition to exploration, development and production activities, Mitchells business also included substantial marketing and midstream activities. Therefore, a portion of the Mitchell purchase price was allocated to the fair value of Mitchells marketing and midstream facilities and equipment. This consisted primarily of natural gas processing plants and natural gas pipeline systems.
The Mitchell midstream assets primarily served gas producing properties that we also acquired from Mitchell. Therefore, certain of the assumptions regarding future operations of the gas producing properties were also integral to the value of the midstream assets. For example, future quantities of natural gas estimated to be processed by natural gas processing plants were based on the same estimates used to value the proved and unproved gas producing properties. Future expected prices for marketing and midstream product sales were also based on price cases consistent with those used to value the oil and gas producing assets acquired from Mitchell. Based on historical costs and known trends and commitments, we also estimated future operating and capital costs of the marketing and midstream assets to arrive at estimated future cash flows. These cash flows were discounted at rates consistent with those used to discount future net cash flows from oil and gas producing assets to arrive at our estimated fair value of the marketing and midstream facilities and equipment.
In addition to the valuation methods described above, we perform other quantitative analyses to support the indicated value in any business combination. These analyses include information related to comparable companies, comparable transactions and premiums paid.
In a comparable companies analysis, we review the public stock market trading multiples for selected publicly traded independent exploration and production companies with comparable financial and operating characteristics. Such characteristics are market capitalization, location of proved reserves and the characterization of those reserves that we deem to be similar to those of the party to the proposed business combination. We compare these comparable company multiples to the proposed business combination company multiples for reasonableness.
In a comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. We compare these comparable transaction multiples to the proposed business combination transaction multiples for reasonableness.
In a premiums paid analysis, we use a sample of selected independent exploration and production company transactions in addition to selected transactions of all publicly traded companies announced recently, to review the premiums paid to the price of the target one day, one week and one month prior to the announcement of the transaction. We use this information to determine the mean and median premiums paid and compare them to the proposed business combination premium for reasonableness.
While these estimates of fair value for the various assets acquired and liabilities assumed have no effect on our liquidity or capital resources, they can have an effect on the future results of operations. Generally, the higher the fair value assigned to both the oil and gas properties and non-oil and gas properties, the lower future net earnings will be as a result of higher future depreciation, depletion and amortization expense. Also, a higher fair value assigned to the oil and gas properties, based on higher future estimates of oil and gas prices, will increase the likelihood of a full cost ceiling writedown in the event that subsequent oil and gas
prices drop below our price forecast that was used to originally determine fair value. A full cost ceiling writedown would have no effect on our liquidity or capital resources in that period because it is a noncash charge, but it would adversely affect results of operations. As discussed in Managements Discussion and Analysis of Financial Condition and Results of Operations Capital Resources, Uses and Liquidity, in calculating our debt-to-capitalization ratio under our credit agreement, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or goodwill impairments.
Our estimates of reserve quantities are one of the many estimates that are involved in determining the appropriate fair value of the oil and gas properties acquired in a business combination. As previously disclosed in our discussion of the full cost ceiling calculations, during the past five years, our annual revisions to our reserve estimates have averaged approximately 1%. As discussed in the preceding paragraphs, there are numerous estimates in addition to reserve quantity estimates that are involved in determining the fair value of oil and gas properties acquired in a business combination. The inter-relationship of these estimates makes it impractical to provide additional quantitative analyses of the effects of changes in these estimates.
Valuation of Goodwill
Goodwill is tested for impairment at least annually. This requires us to estimate the fair values of our own assets and liabilities in a manner similar to the process described above for a business combination. Therefore, considerable judgment similar to that described above in connection with estimating the fair value of an acquired company in a business combination is also required to assess goodwill for impairment.
Generally, the higher the fair value assigned to both the oil and gas properties and non-oil and gas properties, the lower goodwill would be. A lower goodwill value decreases the likelihood of an impairment charge. However, unfavorable changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.
Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates, other than to note the historical average changes in our reserve estimates previously set forth.
In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109. Interpretation No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprises financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. This Interpretation is effective for fiscal years beginning after December 15, 2006, and we will adopt it in the first quarter of 2007. We do not expect the adoption of Interpretation No. 48 to have a material impact on our financial statements and related disclosures.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements. Statement No. 157 provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. However, this Statement does not require any new fair value measurements. Statement No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently assessing the effect, if any, the adoption of Statement No. 157 will have on our financial statements and related disclosures.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106, and 132(R). Statement No. 158 requires the recognition of the overfunded or underfunded status of a defined benefit postretirement plan in the balance sheet. We adopted this recognition requirement
as of December 31, 2006. The effects of this adoption are summarized in Note 6 of the accompanying consolidated financial statements. Statement No. 158 also requires the measurement of plan assets and benefit obligations as of the date of the employers fiscal year-end. The Statement provides two alternatives to transition to a fiscal year-end measurement date. This measurement requirement is effective for fiscal years ending after December 15, 2008. We have not yet adopted this measurement requirement, but we do not expect such adoption to have a material effect on our results of operations, financial condition, liquidity or compliance with debt covenants.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115. Statement No. 159 permits entities to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which we elect the fair value measurement option would be reported in earnings. Statement No. 159 is effective for fiscal years beginning after November 15, 2007. However, early adoption is permitted for fiscal years beginning on or before November 15, 2007, provided we also elect to apply the provisions of Statement No. 157, Fair Value Measurements, at the same time. We are currently assessing the effect, if any, the adoption of Statement No. 159 will have on our financial statements and related disclosures.
The forward-looking statements provided in this discussion are based on our examination of historical operating trends, the information which was used to prepare the December 31, 2006 reserve reports and other data in our possession or available from third parties. These forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for our oil, natural gas and NGLs during 2007 will be substantially similar to those of 2006, unless otherwise noted. We make reference to the Disclosure Regarding Forward-Looking Statements at the beginning of this report. Amounts related to Canadian operations have been converted to U.S. dollars using a projected average 2007 exchange rate of $0.89 U.S. dollar to $1.00 Canadian dollar.
On November 14, 2006, we announced our intent to divest our Egyptian oil and gas assets and terminate our operations in Egypt. We expect to complete this asset sale during the first half of 2007. Subsequently on January 23, 2007, we announced our intent to divest our West African oil and gas assets and terminate our operations in West Africa. We expect to complete this asset sale by the end of the third quarter in 2007. All Egyptian and West African related revenues, expenses and capital will be reported as discontinued operations in our 2007 financial statements. Accordingly, all forward-looking estimates in the following discussion exclude amounts related to our operations in Egypt and West Africa, unless otherwise noted. The assets held for sale represented less than five percent of our 2006 production and December 31, 2006 proved reserves.
Set forth in the following paragraphs are individual estimates of oil, gas and NGL production for 2007. We estimate, on a combined basis, that our 2007 oil, gas, and NGL production will total approximately 219 to 221 MMBoe. Of this total, approximately 92% is estimated to be produced from reserves classified as proved at December 31, 2006. The following estimates for oil, gas and NGL production are calculated at the midpoint of the estimated range for total production.
Oil production in 2007 is expected to total approximately 55 MMBbls. Of this total, approximately 99% is estimated to be produced from reserves classified as proved at December 31, 2006. The expected production by area is as follows: