UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Devon Energy Corporation

(Exact name of Registrant as Specified in its Charter)

Registrant’s telephone number, including area code:

(405) 235-3611

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

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

None

          Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).     Yes þ     No o

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes o     No þ

          Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes þ     No o

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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, 2005, was $22,809,387,806.

          On February 28, 2006, 441,865,011 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statement for the 2006 annual meeting of stockholders — Part III

TABLE OF CONTENTS

DEFINITIONS

      As used in this document:

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

      This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information which was used to prepare the December 31, 2005 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.

PART I

General

      Devon Energy Corporation, including its subsidiaries, (“Devon”) is an independent energy company engaged primarily in oil and gas exploration, development and production, the transportation of oil, gas, and NGLs and the processing of natural gas. We own oil and gas properties principally in the United States and Canada and, to a lesser degree, various regions located outside North America, including Azerbaijan, Brazil, China, Egypt, Russia and West Africa. In addition to our oil and gas operations, we have marketing and midstream operations. These include the marketing of natural gas, crude oil and NGLs, and the construction and operation of pipelines, storage and treating facilities and gas processing plants. A detailed description of our significant properties and associated 2005 developments can be found under “Item 2. Properties”.

      Through our predecessors, 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).

Availability of Reports

      We make available free of charge on our internet website, www.devonenergy.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(a) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file or furnish them to the SEC.

Strategy

      We have a two-pronged operating strategy. First, we invest the vast majority of our capital budget in low-risk exploitation and development projects on our extensive North American property base which provides reliable and repeatable production and reserves additions. To supplement that strategy, we annually invest a measured amount of capital in high-impact, long-cycle time projects to replenish our development inventory for the future. The philosophy that underlies the execution of this strategy is to strive to increase value on a per share basis by:

Financial Information about Segments and Geographical Areas

      Notes 14 and 15 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain information on our segments and geographical areas.

Development of Business

      During 1988, we expanded our capital base with our first issuance of common stock to the public. This transaction began a substantial expansion program that has continued through the subsequent years. This expansion is attributable to both a focused mergers and acquisitions program spanning a number of years and an active ongoing exploration and development drilling program. Total proved reserves increased

from 8 MMBoe at year-end 1987 (without giving effect to the 1998 and 2000 mergers accounted for as poolings of interests) to 2,112 MMBoe at year-end 2005.

      During the same time period, we have grown proved reserves from 0.66 Boe per diluted share at year-end 1987 (without giving effect to the 1998 and 2000 poolings) to 4.49 Boe per diluted share at year-end 2005. This represents a compound annual growth rate of 12%. We also increased production from 0.09 Boe per diluted share in 1987 (without giving effect to the 1998 and 2000 poolings) to 0.48 Boe per diluted share in 2005, a compound annual growth rate of 10%. This per share growth is a direct result of successful execution of our strategic plan and other key transactions and events. A number of these recent key transactions and events, as well as a summary of our recent drilling activities are presented below and in the next section of this report entitled “Drilling Activities”:

Drilling Activities

      The following tables set forth the results of our drilling activity for the past five years.

Total Properties

United States Properties

Canadian Properties

International Properties

      As of December 31, 2005, we were participating in the drilling of 149 gross (99.37 net) wells in the U.S., 33 gross (16.55 net) wells in Canada and 35 gross (8.58 net) wells internationally. Of these wells, through February 1, 2006, 57 gross (34.13 net) wells in the U.S., 11 gross (8.90 net) wells in Canada, and 2 gross (0.30 net) wells internationally had been completed as productive. An additional 1 gross (0.06 net) well in the U.S was a dry hole. The remaining wells were still in progress.

Customers

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

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

      No purchaser accounted for over 10% of our revenues in 2005.

Oil and Natural Gas Marketing

      The spot market for oil and gas is subject to volatility as supply and demand factors fluctuate. We may periodically enter into financial hedging arrangements, fixed-price contracts or firm delivery commitments with a portion of our oil and gas production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

      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.

      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 2006, approximately 79% 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 19% were committed under various long-term contracts which dedicate the natural gas to a purchaser for an extended period of time, but still at market sensitive prices. Our remaining gas production was sold under long-term fixed price contracts.

Marketing and Midstream Activities

      The primary objective of our marketing and midstream group 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 revenue sources are primarily generated by:

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

Competition

      See “Item 1A. Risk Factors”.

Seasonal Nature of Business

      Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Government Regulation

      The oil and gas industry is subject to various types of regulation throughout the world. Legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous government agencies have issued extensive laws and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, production and marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and gas companies of similar size.

      The following are significant areas of government control and regulation in the United States, Canada and international locations in which we operate.

      Exploration and Production. Our United States operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production. Our operations are also subject to various 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, and the unitization or pooling of oil and gas properties. In this regard, 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 establish maximum rates of production from oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.

      Certain oil and gas leases, including our offshore Gulf of Mexico leases, most of our leases in the San Juan Basin and many of our leases in southeast New Mexico, Montana and Wyoming, are granted by the federal government and administered by various federal agencies, including the Minerals Management Service of the Department of the Interior (“MMS”). Such leases require compliance with detailed federal regulations and orders which 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 (“FERC”) also has jurisdiction over certain offshore activities pursuant to the Outer Continental Shelf Lands Act.

      Environmental and Occupational Regulations. Various federal, state and local laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of contaminants or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect our exploration, development, processing, and production operations and related costs. We are also subject to laws and regulations concerning occupational safety and health. We consider the costs of environmental protection and safety and health compliance necessary and manageable parts of our business. We maintain our own internal Environmental, Health and Safety Department. This department is responsible for instituting and maintaining an environmental and safety compliance program for Devon. The program includes field inspections of properties and internal assessments of our compliance procedures. We have been able to plan for and comply with new environmental and safety and health initiatives without materially altering our operating strategies.

      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, 100% coverage is not maintained concerning any environmental claim, and no coverage is maintained with respect to any penalty or fine required to be paid because of violation of any federal, state or local law. We are committed to meeting our responsibilities to protect the environment wherever we operate and 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. Our unreimbursed expenditures in 2005 concerning such matters were immaterial, but we cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

      We are subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and similar state statutes. In response to claims associated with these activities, we recognize liabilities when reasonable estimates are possible. Such liabilities are primarily for estimated costs associated with remediation. We have not used discounting in determining our accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in our consolidated financial statements. We adjust the liabilities when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.

      Certain of our subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of December 31, 2005, our consolidated balance sheet included $4 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities. We do not currently believe there is a reasonable possibility of incurring additional material costs in excess of the existing liabilities recognized for such environmental remediation activities. With respect to the sites in which our subsidiaries are PRPs, our conclusion is based in large part on our (i) participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, our monetary exposure is not expected to be material.

     Canadian Regulations

      Exploration and Production. Our Canadian operations are subject to federal and provincial governmental regulations. Such regulations include requiring licenses for the drilling of wells, regulating the location of wells and the method and ability to produce wells, surface usage and the restoration of land

upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production from wells. Our Canadian operations are also subject to various conservation regulations, including the regulation of the size of spacing units, the number of wells which may be drilled in a unit, the unitization or pooling of oil and gas properties, the rate of production allowable from oil and gas wells, and the ability to produce oil and gas. In Canada, the effect of such regulation is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.

      Royalties and Incentives. Each province and the federal government of Canada have legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime 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 governments of Canada, Alberta, British Columbia and Saskatchewan have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our cash flow.

      Pricing and Marketing. The price of oil, natural gas and NGLs sold is determined by negotiation between buyers and sellers. An order from the National Energy Board (“NEB”) is required for oil exports from Canada. Any oil export to be made pursuant to an export contract of longer than one year, in the case of light crude, and two years, in the case of heavy crude, requires an exporter to obtain an export license from the NEB. The issue of such a license requires the approval of the Government of Canada. Natural gas exported from Canada is also subject to similar regulation by the NEB. Natural gas exports for a term of less than two years, or for a term of two to twenty years in quantities of not more than 20,000 Mcf per day, must be made pursuant to an NEB order. Any natural gas exports to be made pursuant to a contract of larger duration (to a maximum of 25 years) or in larger quantities require an exporter to obtain a 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 which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

      Environmental Regulation. The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be monitored, abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. We are committed to meeting our responsibilities to protect the environment wherever we operate and 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. Our unreimbursed expenditures in 2005 concerning such matters were immaterial, but we cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

      The North American Free Trade Agreement. The North American Free Trade Agreement (“NAFTA”) grants Canada the freedom to determine whether exports to the United States or Mexico will be allowed. In making this determination, Canada must ensure that any export restrictions do not (i) reduce the proportion of energy exported relative to the supply of the energy resource; (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements.

      Kyoto Protocol. The Kyoto Protocol calls for Canada to reduce its greenhouse gas emissions to 6 percent below 1990 levels during the period between 2008 and 2012. The protocol is expected to affect the operation of all industries in Canada, including the oil and gas industry. As details of the implementation of emissions reduction legislation related to this protocol have yet to be finalized, the effect on our operations cannot be determined at this time.

      Investment Canada Act. The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval.

      Exploration and Production. Our oil and gas concessions and operating licenses or permits are granted by host governments and administered by various foreign government agencies. Such foreign governments require compliance with detailed regulations and orders which regulate, among other matters, seismic, drilling and production operations on areas covered by concessions and permits and calculation and disbursement of royalty payments, taxes and minimum investments to the government.

      Regulations include requiring permits for acquiring seismic data; drilling wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Our operations are also subject to regulations which may limit the number of wells or the locations at which we can drill.

      Production Sharing Contracts. Many of our international licenses are governed by Production Sharing Contracts (“PSCs”) between the concessionaires and the granting government agency. PSCs are contracts that define and regulate the framework for investments, revenue sharing, and taxation of mineral interests in foreign countries. Unlike most domestic leases, PSCs have defined production terms and time limits of generally 30 years. Many PSCs allow for recovery of investments including carried government percentages. PSCs generally contain sliding scale revenue sharing provisions. For example, at either higher production rates or higher cumulative rates of return, PSCs allow governments to generally retain higher fractions of revenue.

      Environmental Regulations. Various government laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of waste or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect our exploration, development, processing and production operations and related costs. In general, this consists of preparing Environmental Impact Assessments in order to receive required environmental permits to conduct seismic acquisition, drilling or construction activities. Such regulations also typically include requirements to develop emergency response plans, waste management plans, environmental protection plans and spill contingency plans. In some countries, the application of worldwide standards, such as ISO 14000 governing Environmental Management Systems, are required to be implemented for international oil and gas operations. Additionally, the Kyoto Protocol will have requirements similar to those for Canada for the oil and gas industry in Azerbaijan, Brazil, China, Egypt, Equatorial Guinea, Nigeria and Russia. As details of the implementation of emissions reduction initiatives related to this protocol have yet to be announced, the effect on our international operations, if any, cannot be determined at this time.

Employees

      As of December 31, 2005, our staff consisted of 4,075 full-time employees. We believe we have good labor relations with our employees.

Item 1A.     Risk Factors

      Our business activities, and the oil and gas industry in general, are subject to a variety of risks. Although we have a diversified asset base, a strong balance sheet and a history of generating sufficient cash to fund capital expenditure and investment programs and to pay dividends, if any of the following risk factors should occur, our profitability, financial condition and/or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

Oil, Natural Gas and NGL Prices are Volatile

      Our financial results are highly dependent on the prices of and demand for oil, natural gas and NGLs. A significant downward movement of the prices for these commodities could have a material adverse effect on our estimated proved reserves, revenues and operating cash flows. Such a downward price movement could also have a material adverse effect on our profitability, the carrying value of our oil and gas properties and future growth. Historically, prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:

Estimates of Oil, Natural Gas and NGL Reserves are Uncertain

      The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Additional discussion of our policies regarding estimating and recording reserves is described in “Item 2. Properties — Proved Reserves and Estimated Future Net Revenue”.

Discoveries or Acquisitions of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production

      The production rate from oil and gas properties generally declines as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies, identify additional producing zones in existing wells, secondary recovery reserves or

tertiary recovery reserves, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.

Future Exploration and Drilling Results are Uncertain and Involve Substantial Costs

      Substantial costs are often required to locate and acquire properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling and completing wells are often uncertain. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:

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

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

      Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Higher recent commodity prices have increased the costs of properties available for acquisition, and there are a greater number of companies with the financial resources to pursue acquisition opportunities. Certain of our competitors have financial and other resources substantially larger than ours, and they have also established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations.

International Operations Have Uncertain Political, Economic and Other Risks

      We have international operations in Angola, Azerbaijan, Brazil, China, Cote d’Ivoire, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Nigeria and the Russian Republic of Tatarstan. 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 management’s attention from our more significant assets. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. This could adversely affect our interests and our future profitability.

      The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.

Government Laws and Regulations Can Change

      Our operations are subject to federal laws and regulations in the United States, Canada and the other international countries in which we operate. In addition, we are also subject to the laws and regulations of various states, provinces and local governments. Pursuant to such legislation, numerous government departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Changes in such legislation have affected, and at times in the future could affect, our future operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Although we are unable to predict changes to existing laws and regulations, such changes could

significantly impact our profitability. While such legislation can change at any time in the future, those laws and regulations outside North America to which we are subject generally include greater risk of unforeseen change.

Environmental Matters and Costs Can Be Significant

      As an owner or lessee and operator of oil and gas properties, we are subject to various federal, provincial, state, 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.

Insurance Does Not Cover All Risks

      Exploration, development, production and processing of oil, natural gas and NGLs can be hazardous and involve unforeseen occurrences such as hurricanes, blowouts, cratering, fires and loss of well control. These occurrences can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. We maintain insurance against certain losses or liabilities in accordance with customary industry practices and in amounts that management believes to be prudent. However, insurance against all operational risks is not available to us.

Item 1B.     Unresolved Staff Comments

      Not applicable.

      Substantially all of our properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage located in our core operating areas. These interests entitle us to drill for and produce oil, natural gas and NGLs from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral and net profits interests, foreign government concessions and other forms of direct and indirect ownership in oil and gas properties.

      We also have certain midstream assets, including natural gas and NGL processing plants and pipeline systems. Our most significant midstream assets are our assets serving the Barnett Shale development in North Texas. These assets include approximately 2,600 miles of pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL fractionator.

Proved Reserves and Estimated Future Net Revenue

      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”). The 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 QREs is kept by the Senior Advisor — Corporate Reserves. All QREs are required to receive education covering the fundamentals of SEC proved reserves assignments.

      The Group is responsible for internal reserves evaluation and certification and includes the Manager — E&P Budgets and Reserves and the Senior Advisor — Corporate Reserves. The Group reports independently of any of our operating divisions. The Vice President — Planning and Evaluation is directly responsible for overseeing the Group and reports to the President of Devon. No portion of the Group’s compensation is dependent on the quantity of reserves booked.

      Throughout the year, the Group performs internal audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major changes (additions and

revisions) to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants as discussed below.

      In addition to internal audits, we engage three independent petroleum consulting firms to perform both external reserves preparation and audits. Ryder Scott Company, L.P. prepared the reserves estimates for all offshore Gulf of Mexico properties and for 98% of the international proved reserves. LaRoche Petroleum Consultants, Ltd. audited the reserves estimates for 87% of the domestic onshore properties. AJM Petroleum Consultants prepared estimates covering 46% of our Canadian reserves and audited an additional 26% 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 2005, 2004 and 2003.

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

      We follow what we believe to be a rational approach not only to recording oil and gas reserves, but also to subjecting these reserves to reviews by independent petroleum consultants. In 2004 and 2003, 63% of our company-wide reserves were prepared or audited by an independent petroleum consulting firm. In 2005, 85% of our company-wide reserves were prepared or audited by an independent petroleum consulting firm. We expect the 2005 percent to be indicative of the coverage provided by independent reviews in 2006. This approach provides a high degree of assurance about the validity of our reserve estimates. This is evidenced by the fact that in the past five years, our annual performance related revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 1% of the previous year’s estimate.

      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, 2005. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 15 to our Consolidated Financial Statements included herein.

      As presented in the previous table, we had 1,599 MMBoe of proved developed reserves at December 31, 2005. 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, 2005.

      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 (i) in filings

with the SEC and (ii) in filings with 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, 2005. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.

Production, Revenue and Price History

      Certain information concerning oil, natural gas and NGL production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 2005, is set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Well Statistics

      The following table sets forth our producing wells as of December 31, 2005:

Developed and Undeveloped Acreage

      The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2005.

Operation of Properties

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

      We are the operator of 18,784 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.

      Our North American properties are concentrated within five geographic areas. Operations in the United States are focused in the Permian Basin, the Mid-Continent, the Rocky Mountains and onshore and offshore Gulf Coast regions. Canadian properties are focused in the Western Canadian Sedimentary Basin in Alberta and British Columbia. Properties outside North America are located primarily in Azerbaijan, China, Egypt and areas in West Africa, including Equatorial Guinea, Gabon, and Cote d’Ivoire. Additionally, we have exploratory interests, but no current producing assets, in other international countries including Angola, Brazil, Ghana and Nigeria. Maintaining a tight geographic focus in selected core areas has allowed us to improve operating and capital efficiency.

      The following table sets forth proved reserve information on the most significant geographic areas in which our properties are located as of December 31, 2005.

      Our Permian Basin assets are located in portions of Southeast New Mexico and West Texas. These assets include conventional oil and gas properties producing from a wide variety of geologic formations and depths. Our leasehold position in Southeast New Mexico encompasses 108,000 net acres of developed lands and 221,000 net acres of undeveloped land and minerals. Historically, we have been a very active operator in this area, developing gas from the high productivity Morrow formation and oil in the lower risk Delaware formation.

      In the West Texas portion of the Permian Basin, we maintain a base of oil production with long-life reserves. Many of these reserves are from both operated and non-operated positions in large enhanced oil recovery units such as the Wasson ODC Unit, the Willard Unit, the Reeves Unit, the North Welch Unit and the Anton Irish (Clearfork) Unit. These oil-producing units often exhibit low decline rates. We also own a significant acreage position in West Texas with more than 200,000 net acres of developed lands and more than 273,000 net acres of undeveloped land and minerals at December 31, 2005.

      The Mid-Continent region includes portions of Texas, Oklahoma and Kansas. These areas encompass a wide variety of geologic formations and productive depths and produce both oil and natural gas. Our Mid-Continent production has historically come from conventional oil and gas properties. However, the Barnett Shale in North Texas, acquired in 2002, is a non-conventional gas resource. The Mid-Continent region represented 24% of our proved reserves at December 31, 2005. Approximately 80% of our proved reserves in the Mid-Continent area are in the Barnett Shale.

      The Barnett Shale, our largest producing field, is known as a tight gas formation. This means that in its natural state, the formation is resistant to the production of natural gas. However, the application of available technology has made the Barnett Shale a low-risk and highly profitable natural gas operation. Cumulative natural gas production from our wells in the Barnett Shale surpassed one trillion cubic feet during 2005. We hold 552,000 net acres and over 2,100 producing wells in the Barnett Shale. Our average working interest is more than 80%.

      We have been successful in extracting gas from the Barnett Shale by using light sand fracturing. Light sand fracturing yields better results than earlier techniques, is less expensive and can be used to complete new wells and to refracture existing wells to increase production rates. We are also applying horizontal drilling, closer well spacing and reservoir optimization techniques to further enhance the value of the Barnett Shale.

      Our marketing and midstream operations gather and process our Barnett Shale production along with Barnett Shale production from unrelated third parties. The Barnett Shale gathering system consists of approximately 2,600 miles of pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL fractionator.

      In 2006, we plan to drill a total of 325 new Barnett Shale wells including 266 horizontal and 59 vertical wells. We began an infill drilling program on our core area acreage in 2005 and plan to drill 50 to 60 horizontal infill wells in 2006. Current net production from the Barnett Shale is approximately 95 MBoe per day.

      Our operations in the Rocky Mountain region include properties in Wyoming, Montana, Utah, and Northern New Mexico. These assets include conventional oil and gas properties and coalbed natural gas projects. Approximately 17% of our proved reserves in the Rocky Mountains are from coalbed natural gas. We began producing coalbed natural gas in the San Juan Basin of New Mexico in the mid-1980s and began drilling coalbed natural gas wells in the Powder River Basin of Wyoming in 1998. As of December 31, 2005, we had approximately 1,360 producing coalbed natural gas wells in the Powder River Basin. Net coalbed natural gas production from the basin was approximately 11 MBoe per day as of December 31, 2005. We plan to drill about 250 new wells in the Powder River Basin in 2006.

      The Washakie field in Wyoming is another significant natural gas producing area in our Rocky Mountain region. In 2005, we drilled 88 wells in the Washakie field, including 53 wells we operate. In 2006, we plan to drill up to 70 wells and participate in another 35 outside-operated wells. We have interests in over 200,000 gross acres and an inventory of more than 300 drilling locations. Our current net production from Washakie is approximately 16 MBoe per day.

      Our Gulf Coast onshore properties are located in South and East Texas, Louisiana and Mississippi. Most of the wells in the region are completed in conventional sandstone formations.

      Our operations in South Texas have focused on exploration in the Edwards, Wilcox and Frio-Vicksburg formations. We drilled three exploratory discoveries on our Gulf Coast acreage in 2005. Drilling plans in 2006 include 34 new wells and 64 recompletions.

      East Texas is an important conventional gas producing region, and Carthage and Groesbeck are two of the primary producing areas of this region. Wells produce from the Cotton Valley sands, the Travis Peak sands and from shallower sands and carbonates. We have interests in over 2,300 producing wells in East Texas and plans to drill 139 wells in Carthage and over 30 wells in Groesbeck in 2006.

      We have an active exploration program under way in the Bossier Trend in North Louisiana. We hold about 200,000 net acres in seven Bossier prospect areas. We drilled exploratory test wells on the Vixen and North Vixen prospects in 2005. Plans for 2006 include test wells on three additional Bossier prospects.

      The offshore Gulf of Mexico accounted for 13% of our 2005 production. We operate over 300 platforms and caissons in the Gulf of Mexico. Gulf of Mexico operations are typically differentiated by water depth. The shallow water shelf is defined by water depths of 600 feet or less. We operate in both the shelf and deepwater areas.

      In 2005, we continued development of the deepwater Magnolia field (Garden Banks 783). At December 31, 2005, six Magnolia wells were producing approximately 10 MBoe per day to our interest. The final two Magnolia producing wells will be completed in 2006. Also in 2006, we will complete two producing gas wells in the deepwater Merganser field (Atwater Valley 37). Merganser will produce into the Independence Hub, which is expected to be completed in early 2007. We expect our net share of production from Merganser to be approximately eight MBoe per day.

      In addition to our producing properties, we have a significant inventory of exploration prospects in the Gulf of Mexico. The current prospect inventory includes 15 shelf prospects, 18 deepwater prospects in the lower Tertiary trend and 17 deepwater Miocene prospects.

      On the shallow-water shelf, the industry is exploring for oil and gas reserves at depths in excess of 15,000 feet. We drilled a “deep shelf” discovery well on the Big Bend prospect (Mustang Island A-110) in 2005. We are the operator of Big Bend with a 50% working interest.

      In the deepwater Gulf of Mexico, almost all historical production of oil and gas has been from Miocene aged reservoirs. We currently produce approximately 50 MBoe per day from the deepwater Gulf. During 2006, we expect to drill exploratory wells on three Miocene prospects.

      In recent years, the industry has begun to explore for oil below the Miocene in older formations that are collectively referred to as the lower Tertiary. To date, we have participated in three lower Tertiary discoveries.

      Cascade (Walker Ridge 206) was our first discovery in the lower Tertiary trend. We drilled successful appraisal wells on the prospect in 2005. Also in 2005, we drilled a successful appraisal of the Jack lower Tertiary discovery (Walker Ridge 759). An extended production test of the Jack appraisal well is planned for 2006. Using information obtained from a successful production test, we and our partners will be able to determine a development plan for the Jack discovery. We hold 25% working interests in Jack and Cascade. Our third lower Tertiary discovery is St. Malo (Walker Ridge 678). Additional appraisal drilling on St. Malo is pending partner approval and rig availability. We have a 22.5% working interest in the St. Malo discovery.

      We are among the largest independent oil and gas producers in Canada and operate in most of the producing basins in Western Canada. As of December 31, 2005, 30% of our proved reserves were in Canada.

      Many of the Canadian basins where we operate are accessible for drilling only in the winter when the ground is frozen. Consequently, the winter season, from December through March, is the most active drilling period. We expect to drill about 380 wells in the 2005-2006 winter program in Canada.

      We hold approximately 410,000 net undeveloped acres in the Deep Basin in West-Central Alberta, where we drilled 179 wells in 2005 and have another active drilling program planned for 2006. The profitability of our operations in the Deep Basin is enhanced by our ownership in nine gas processing plants in the area. Deep Basin reservoirs tend to be rich in liquids, producing up to 50 barrels of NGLs with each MMcf of gas.

      Other important oil and gas exploration and development areas in Canada include the Peace River Arch, Northeast British Columbia, Central Alberta and the Lloydminster region of Alberta and Saskatchewan. At Lloydminster, cold flow heavy oil is found in multiple horizons generally at depths of 1,000 to 2,000 feet. In 2005, we acquired 165,000 net acres in the Iron River area within the greater Lloydminster region. We expect to drill 800 wells at Iron River over the next four years.

      The oil sands of Eastern Alberta are a vast North American hydrocarbon resource. We hold over 75,000 net acres of oil sands leases in Alberta. In 2004, we received final regulatory approval to proceed with development of our Jackfish thermal oil sands project, in which we have a 100% working interest. The project is expected to produce 35 MBbls per day of heavy oil when fully operational in 2008. We expect to drill 34 horizontal wells at Jackfish in 2006 along with the construction of the Access dual pipeline. Access will transport diluent and blended crude oil between Jackfish and Edmonton.

      Beyond our core properties in the United States and Canada, we also look outside North America for longer-term reserve and production growth. At December 31, 2005, these international areas accounted for 12% of our worldwide proved reserves.

      The most significant international producing property is the ExxonMobil-operated Zafiro oil field on Block B, offshore Equatorial Guinea in West Africa. During 2005, our share of production from Zafiro averaged 37 MBbls per day. We expect to drill nine development wells on Block B in 2006. We drilled a discovery on the Esmeralda prospect on Block B in 2005. We have also identified exploratory prospects on

Block B and on three additional blocks in Equatorial Guinea. Three exploratory wells are planned on Block P in 2006. We drilled a discovery well on the Venus prospect on Block P in 2005.

      Our second most significant international producing asset is our Panyu project offshore China. Panyu, in the Pearl River Mouth of the South China Sea, was discovered in 1998. Panyu production began late in 2003. We drilled and completed five successful development wells and tested two exploratory prospects during 2005. During 2005, our share of production from China was 15 MBbls per day.

      We also have an active offshore exploration program in Brazil. We made a discovery in 2004 offshore Brazil on Block BM-C-8. Development of the Polvo discovery commenced in 2005 and first production is expected in 2007. We, in partnership with Petrobras on three blocks, were the successful bidder on three offshore blocks in Brazil’s bid round seven in 2005. We expect to drill five exploration wells in Brazil in 2006.

      In Azerbaijan, we have a 5.6% carried working interest in the Azeri-Chirag-Gunashli, or ACG, oil development project in the Caspian Sea. We estimate that the ACG field contains over five billion barrels of gross proved oil reserves. Oil production from the ACG field began ramping up in 2005 after the Central Azeri platform came on-line.. Based on economic factors existing at December 31, 2005, our net share of ACG production is expected to increase to between 30 to 35 MBbls per day in early 2007 when payout is reached.

      We also hold interests in Angola, Cote d’Ivoire, Egypt, Gabon, Ghana, Indonesia, Nigeria, and Russia. Exploratory wells in Egypt and Nigeria are planned for 2006.

Title to Properties

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

      As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, 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.

Royalty Matters

      Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which we are a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with 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. Trial is set for February 2007 if the suit continues to advance. We believe that we have acted reasonably, have legitimate and strong defenses to all allegations in the suit, and have paid royalties in good faith. We do not currently believe that we are subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.

      We have been a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post production costs from royalties we pay. A significant portion of such

production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of which we own a 75% interest. During 2005, all of the litigation was resolved for immaterial amounts.

Equatorial Guinea Investigation

      The SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea, and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, we received a subpoena issued by the SEC pursuant to a formal order of investigation. We have cooperated fully with the SEC’s previous requests for information in this inquiry and plan to continue to work with the SEC in connection with its formal investigation.

Other Matters

      We are involved in other various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no other material pending legal proceedings to which we are a party or to which any of our property is subject.

      There were no matters submitted to a vote of security holders during the fourth quarter of 2005.

PART II

Market Price

      Our common stock has been traded on the New York Stock Exchange (the “NYSE”) since October 12, 2004. Prior to October 12, 2004, our common stock was traded on the American Stock Exchange (the “AMEX”).

      The following table sets forth the high and low sales prices for our common stock as reported by the NYSE and AMEX for the periods indicated.

      On February 28, 2006, there were 16,576 holders of record of our common stock.

Dividends

      We commenced the payment of regular quarterly cash dividends on our common stock on June 30, 1993, in the amount of $0.015 per share. Effective December 31, 1996, we increased our quarterly dividend payment to $0.025 per share. Effective March 31, 2004, we increased our quarterly dividend payment to $0.05 per share. Effective March 31, 2005, we increased the quarterly dividend payment to $0.075 per share. Effective March 31, 2006, we will increase the quarterly dividend payment to $0.1125 per share. We anticipate continuing to pay regular quarterly dividends in the foreseeable future.

Issuer Purchases of Equity Securities

      The following table presents the fourth quarter of 2005 activity with respect to our stock repurchase program announced August 3, 2005.

      The following selected financial information (not covered by the report of independent registered accounting firm) should be read in conjunction with “Item 1. Business — Development of Business,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.” Note 2 to the consolidated financial statements included in Item 8 of this report contains information on the merger which occurred in 2003, as well as unaudited pro forma financial data for 2003.