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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-KSB

(Mark One)

For the fiscal year ended December 31, 2003

OR

For the transition period from                      to                     

Commission file number: 0-20928

VAALCO Energy, Inc.

(Name of small business issuer in its charter)

Issuer’s telephone number: (713) 623-0801

Securities registered under Section 12(b) of the Exchange Act:

None

Securities registered under Section 12(g) of the Exchange Act:

Common Stock, $.10 par value

(Title of class)

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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    x    No    ¨.

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will 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-KSB or any amendment to this Form 10-KSB    x.

The registrant’s revenues for the fiscal year ended December 31, 2003 were $35,983,037.

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, as of March 25, 2004 was $21,954,405.

As of March 26, 2004, there were outstanding 21,380,060 shares of Common Stock, $.10 par value per share, of the registrant. In addition, as of such date there were outstanding 10,000 shares of Preferred Stock convertible into 27,500,000 shares of Common Stock.

Documents incorporated by reference: Definitive proxy statement of VAALCO Energy, Inc. relating to the Annual Meeting of Stockholders to be filed within 120 days after the end of the fiscal year covered by this Form, which is incorporated into Part III of this 10-KSB.

Transitional Small Business Disclosure Format:    Yes    ¨    No    x.

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VAALCO ENERGY, INC.

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PART I

Item 1.     Business

BACKGROUND

VAALCO Energy, Inc., a Delaware corporation, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. As used herein, the terms “Company” and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. VAALCO owns producing properties and conducts exploration activities as operator of consortiums internationally in the Philippines and Gabon. Domestically, the Company has minor interests in the Texas Gulf Coast area.

VAALCO’s Philippine subsidiaries include Alcorn (Philippines) Inc., Alcorn (Production) Philippines Inc. and Altisima Energy, Inc. VAALCO’s Gabon subsidiaries are VAALCO Gabon (Etame), Inc. and VAALCO Production (Gabon), Inc. VAALCO Energy (USA), Inc. holds interests in certain properties located in the United States.

In connection with a merger with 1818 Oil Corp. in 1998, the Company issued to the 1818 Fund II, L.L.P. (the “1818 Fund”) Common Stock and Preferred Stock which votes as a class with the Common Stock on an as converted basis, representing approximately 65% of the outstanding voting power of the Company on an as converted basis (excluding options and warrants). In addition, the terms of the Preferred Stock acquired by the 1818 Fund provide that while the Preferred Stock is outstanding, the holders of Preferred Stock voting together as a class are entitled to elect three directors of the Company. Accordingly, the 1818 Fund is able to control all matters submitted to a vote of the stockholders of the Company, including the election of directors. (See “Risk Factors – Control by 1818 Fund”).

RECENT DEVELOPMENTS

The Company’s primary source of revenue was from the Etame field located offshore the Republic of Gabon. During 2003, the Etame field produced approximately 5.0 million barrels (1.2 million barrels net to the Company). The Company also continued production operations offshore the Philippines and in the Texas Gulf Coast.

During 2003, the Company completed the processing of seismic data acquired in late 2002, and identified several exploration prospect locations on the Etame permit, and up to two new development well locations for the Etame field. The Company drilled an exploration well commencing in December 2003 and reaching total depth in January 2004. The well, the Ebouri No. 1, resulted in a new Gamba sand discovery logging 14 meters of oil pay in a 17 meter Gamba sand. Two sidetracks were performed to delineate the discovery, each of which logged a comparable amount of oil pay in the Gamba. The Company is performing economic studies to determine the feasibility of developing the discovery. The Company intends to spud the second of the two exploration locations in the second quarter of 2004. The budget for the two exploration wells is $14.5 million ($4.4 million net to the Company).

The Company submitted a Phase 2 Development Plan for the Etame field to the Gabon government for approval in October 2003. The Company plans to drill one new development well in the Etame field in the first half of 2004. A second development well will be drilled based on the outcome of the first development well. The budget for adding the first development well is $28.8 million ($8.7 million net to the Company) and includes laying two new flowlines and umbilicals from the well site to the floating production, storage and offloading system (“FPSO”) onsite in the Etame field. The extra flowline and umbilical are to be laid with the first development well to eliminate the need to mobilize lay vessel equipment when the second development well is drilled. The Company plans to use cash on hand and cash flow from operations to fund the planned exploration and development wells.

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During the course of preparing the Phase 2 development plan in the third quarter of 2003, the Company determined that the Etame-2V well drilled in 1999 was not in a suitable location for completion in the Etame field. Accordingly, the Company has written off as a non-cash exploration expense the $1.5 million expenditure associated with this well, which was previously carried as work in progress on the Company’s balance sheet. During the third quarter of 2003, a $260,000 non-cash write off was taken for leases that expired in Alabama and Mississippi.

During September 2003, the crude oil transport vessel used in the Philippines was placed into dry dock for refurbishment. In October 2003, the Company’s Philippines crude oil purchaser, Caltex, announced the closure of their refinery in the Philippines. The Company recently signed a contract with Shell Oil to sell crude production from its Philippines oil fields.

To fund its share of the Phase 1 Etame field development costs, on April 19, 2002, the Company entered into a $10.0 million credit facility with the International Finance Corporation (“IFC”), a subsidiary of the World Bank. During 2003 the Company has repaid $3.0 million of the loan as called for under the facility repayment schedule.

The credit facility required that the Company provide $10.0 million of cash collateral to secure borrowings under the facility until the project completion date. The Company borrowed the $10.0 million that it used as cash collateral from the 1818 Fund II, L.L.P. and another investor that is not affiliated with the Company (the “1818 Fund Loan”).

The Company was notified by the IFC that the project completion date occurred on March 31, 2003. On April 1, 2003, the $10.0 million cash collateral posted by the Company was released and the 1818 Fund Loan was repaid.

In connection with the 1818 Fund Loan, the Company issued warrants to purchase 15.0 million shares of its common stock to the 1818 Fund (7.5 million of which terminated when the loan was repaid on April 1, 2003). The Company issued the other lender warrants to purchase 4.5 million shares of common stock on the same terms as the warrants issued to the 1818 Fund (2.25 million of which terminated when the loan was repaid on April 1, 2003). As the Company only drew a total of $10.0 million of the $13.0 million available under the loan facility, the 1818 Fund was required to return an additional 2.25 million warrants. In connection with the 1818 Fund Loan, a total of 7.5 million warrants to purchase shares of common stock remain outstanding. The Company was carrying unamortized debt discount of $1.5 million associated with the issuance of the warrants at March 31, 2003. This amount was expensed in connection with the repayment of the 1818 Fund loan in the second quarter of 2003.

GENERAL

The Company’s current strategy is to maximize the value of the reserves discovered in Gabon through further development of the Etame field and delineation of the Ebouri discovery. The Company will also drill selected exploration prospects on its Gabon acreage. The Company will utilize cash flows from Etame field operations to fund the exploration and development costs.

International

The Company’s international strategy is to pursue selected opportunities that are characterized by reasonable entry costs, favorable economic terms, high reserve potential relative to capital expenditures and the availability of existing technical data that may be further developed using current technology. The Company believes that it has unique management and technical expertise in identifying international opportunities and establishing favorable operating relationships with host governments and local partners familiar with the local practices and infrastructure. The Company owns producing properties and conducts exploration activities as operator of consortiums internationally in the Philippines and Gabon.

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Domestic

The Company’s domestic strategy is to produce existing reserves. There are no plans to drill new domestic wells at this time.

CUSTOMERS

Substantially all of the Company’s crude oil and natural gas is sold at the well head at posted or indexed prices under short-term contracts, as is customary in the industry. In Gabon, the Company sells crude oil under a contract with Shell Western Supply and Trading, Limited. In the Philippines, for most of 2003, the Company marketed its crude oil under an agreement with Caltex. In October 2003, Caltex announced the closure of its refinery in the Philippines. Subsequently, the Company signed a contract with Shell Oil to sell crude production from its Philippines oil fields. While the loss of Shell as a buyer might have a material effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil. Domestic production is sold under two contracts, one for oil and one for gas. The Company has access to several alternative buyers for oil and gas sales domestically.

EMPLOYEES

As of December 31, 2003, the Company had 28 full-time employees, five of who were located in Gabon and 17 of whom were located in the Philippines. The Company also utilizes contractors to staff its international operations. The Company is not subject to any collective bargaining agreements and believes its relations with its employees are satisfactory.

COMPETITION

The oil and gas industry is highly competitive. Competition is particularly intense with respect to acquisitions of desirable oil and gas reserves. There is also competition for the acquisition of oil and gas leases suitable for exploration and the hiring of experienced personnel. Competition also exists with other industries in supplying the energy needs of consumers. In addition, the producing, processing and marketing of oil and gas is affected by a number of factors beyond the control of the Company, the effects of which cannot be accurately predicted.

The Company’s competition for acquisitions, exploration, development and production include the major oil and gas companies in addition to numerous independent oil companies, individual proprietors, drilling and acquisition programs and others. Many of these competitors possess financial and personnel resources substantially in excess of those available to the Company, giving those competitors an enhanced ability to pay for desirable leases and to evaluate, bid for and purchase properties or prospects. The ability of the Company to generate reserves in the future will depend on its ability to select and acquire suitable producing properties and prospects for future drilling and exploration.

ENVIRONMENTAL REGULATIONS

General

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in the United States and also are subject to the laws and regulations of the Philippines and Gabon. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the Company’s capital expenditures, earnings or competitive position with respect to its existing assets and operations. The Company cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.

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Solid and Hazardous Waste

The Company currently owns or leases, and in the past owned or leased, properties that have been used for the exploration and production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. In addition, some of these properties are or have been operated by third parties. The Company has no control over such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. The Company could in the future be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

The Company generates wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The Environmental Protection Agency (“EPA”) and various state agencies have limited the disposal options for certain wastes, including wastes designated as hazardous under RCRA and state analogs (“Hazardous Wastes”). Furthermore, it is possible that certain wastes generated by the Company’s oil and gas operations that are currently exempt from treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes under RCRA or other applicable statutes and, therefore, may be subject to more rigorous and costly disposal requirements.

Superfund

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, the Company has generated and will generate wastes that may fall within CERCLA’s definition of Hazardous Substance. The Company may also be the owner or operator of sites on which Hazardous Substances have been released. To its knowledge, neither the Company nor its predecessors have been designated as a PRP by the EPA under CERCLA; the Company also does not know of any prior owners or operators of its properties that are named as PRPs related to their ownership or operation of such properties.

Clean Water Act

The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and hazardous substances and of other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances and other pollutants. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the

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case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require the Company to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, the Company may be liable for penalties and costs.

Oil Pollution Act

The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of CWA, imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, the Company may be liable for costs and damages.

The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill. Certain amendments to the OPA that were enacted in 1996 require owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10 million in specified state waters and $35 million in federal outer continental shelf (“OCS”) waters, with higher amounts, up to $150 million based upon worst case oil-spill discharge volume calculations. The Company believes that it has established adequate proof of financial responsibility for its offshore facilities.

Air Emissions

The Company’s operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require the Company to forego construction, modification or operation of certain air emission sources.

Coastal Coordination

There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation’s coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development.

In Texas, the Legislature enacted the Coastal Coordination Act (“CCA”), which provides for the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. The act establishes the Texas Coastal Management Program (“CMP”). The CMP is limited to the nineteen counties that border the Gulf of Mexico and its tidal bays. The act provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. This review may impact agency permitting and review activities and add an additional layer of review to certain activities undertaken by the Company.

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OSHA and other Regulations

The Company is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require the Company to organize and/or disclose information about hazardous materials used or produced in its operations. The Company believes that it is in substantial compliance with these applicable requirements.

Forward-Looking Information and Risk Factors

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 (“Exchange Act”). All statements other than statements of historical fact included in this Report (and the exhibits hereto), including without limitation, statements regarding the Company’s financial position and estimated quantities and net present values of reserves, are forward looking statements. The Company can give no assurances that the assumptions upon which such statements are based will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations (“Cautionary Statements”) are disclosed in the section “Risk Factors,” elsewhere herein and in other periodic reports filed under the Exchange Act, which are herein incorporated by reference. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified by the Cautionary Statements.

Environmental and Other Regulations

The laws and regulations of the United States, Philippines and Gabon regulate the Company’s business. These laws and governmental regulations, which cover matters including drilling operations, taxation and environmental protection, may be changed from time to time in response to economic or political conditions. (See “Foreign Operations”). The Company prepared an Environmental Impact Assessment for its development of the Etame field, and filed the report with the Government of Gabon and the IFC.

The Company’s domestic operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company’s domestic operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, including natural resource damages. In addition, the Company could be liable for environmental damages caused by, among others, previous property owners or operators. As a result, substantial liabilities to third parties or governmental entities may be incurred; the payment of which could have a material adverse effect on the Company’s financial condition, results of operations and liquidity. The Company maintains insurance coverage for its operations, including limited coverage for sudden environmental damages, but does not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Moreover, the Company does not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages is available at a reasonable cost. Accordingly, the Company may be subject to liability or may lose substantial portions of its properties in the event of certain environmental damages. The Company could incur substantial costs to comply with environmental laws and regulations.

Substantial portions of the Company’s producing properties are located offshore. The costs to abandon offshore wells may be substantial. For financial accounting purposes the Company will adopt Statement of Financial Accounting Standards 143 – Accounting for Asset Retirement Obligations on January 1, 2003. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. No assurances can be given that such reserves will be sufficient to cover such costs in the future as they are incurred.

The recent trend toward stricter standards in environmental legislation and regulation in the U.S. is likely to continue. If such legislation were enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general.

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In addition, while the Company believes that it is currently in compliance with environmental laws and regulations applicable to the Company’s operations in the Philippines, Gabon and the U.S., no assurances can be given that the Company will be able to continue to comply with such environmental laws and regulations without incurring substantial costs.

Volatility of Oil and Gas Prices and Markets

The Company’s revenues, cash flow, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas. The Company’s ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and gas prices. The Company’s production in the Philippines is from mature offshore fields with high production costs. The Company’s margin on sales from these fields (the price received for oil less the production costs for the oil) is lower than the margin on oil production from many other areas. As a result, the profitability of the Company’s production in the Philippines is affected more by changes in prices than production located in other areas. Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include international political conditions, the domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels and overall economic conditions. In addition, various factors, including the availability and capacity of gas gathering systems and pipelines, the effect of federal, state and foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect the Company’s ability to market its oil and gas production. Any significant decline in the price of oil or gas would adversely affect the Company’s revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of the Company’s oil and gas properties and its planned level of capital expenditures.

Replacement of Reserves

The Company’s future success depends upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Except to the extent that the Company conducts successful exploration or development activities or acquires properties containing proved reserves, the estimated net proved reserves of the Company will generally decline as reserves are produced. There can be no assurance that the Company’s planned development and exploration projects and acquisition activities will result in significant additional reserves or that the Company will have continuing success drilling productive wells at economic finding costs. The drilling of oil and gas wells involves a high degree of risk, especially the risk of dry holes or of wells that are not sufficiently productive to provide an economic return on the capital expended to drill the wells. In addition, the Company’s drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, political instability, economic/currency imbalances, compliance with governmental requirements or delays in the delivery of equipment and availability of drilling rigs. Certain of the Company’s oil and gas properties are operated by third parties or may be subject to operating committees controlled by national oil companies and, as a result, the Company has limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties.

Substantial Capital Requirements

The Company makes, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas reserves. Historically, the Company has financed these expenditures primarily with cash flow from operations, debt, asset sales, and private sales of equity. During 2004, the Company will participate in the further exploration and development of the Etame Block offshore Gabon. The Company is the operator for the Block and thus responsible for contracting on behalf of all the remaining parties participating in the project. The Company relies on the timely payment of cash calls by its partners to pay for the 69.65% share of the budget for which the partners are responsible. (See “Drilling Risks, Operating Hazards and Uninsured Risks”).

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Drilling Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. The Company’s drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company’s control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.

Operating Hazards and Uninsured Risks

The oil and gas business involves a variety of operating risks, including fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company’s production facilities are also subject to hazards inherent in marine operations, such as capsizing, sinking, grounding, collision and damage from severe weather conditions. The relatively deep offshore drilling conducted by the Company overseas involves increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable. The impact that any of these risks may have upon the Company is increased due to the low number of producing properties owned by the Company. The Company and operators of properties in which it has an interest maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant unfavorable event not fully covered by insurance could have a material adverse effect on the Company’s financial condition, results of operations and cash flows. Furthermore, the Company cannot predict whether insurance will continue to be available at a reasonable cost or at all.

Uncertainties in Estimating Reserves and Future Net Cash Flows

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating the underground accumulations of oil and gas that cannot be measured in an exact manner. The estimates included herein are based on various assumptions required by the Securities and Exchange Commission (the “Commission”), including unescalated prices and costs and capital expenditures, and, therefore, are inherently imprecise indications of future net revenues. Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this document. In addition, the Company’s reserves may be subject to downward or upward revision based upon production history, results of future development, availability of funds to acquire additional reserves, prevailing oil and gas prices and other factors. Moreover, the calculation of the estimated present value of the future net revenue using a 10% discount rate as required by the Commission is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company’s reserves or the oil and gas industry in general.

It is also possible that reserve engineers may make different estimates of reserves and future net revenues based on the same available data. In calculating reserves on a BOE basis, gas was converted to oil at the ratio of six Mcf of gas to one Bbl of oil. While this conversion ratio approximates the energy equivalent of oil and gas on a Btu basis, it may not represent the relative prices received by the Company on the sale of its oil and gas production.

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The estimated future net revenues attributable to the Company’s net proved reserves are prepared in accordance with the Commission guidelines, and are not intended to reflect the fair market value of the Company’s reserves. In accordance with the rules of the Commission, the Company’s reserve estimates are prepared using period end prices received for oil and gas. Future reductions in prices below those prevailing at year-end 2003 would result in the estimated quantities and present values of the Company’s reserves being reduced.

A substantial portion of the Company’s proved reserves are or will be subject to service contracts, production sharing contracts and other arrangements. The quantity of oil and gas the Company will ultimately receive under these arrangements will differ based on numerous factors, including the price of oil and gas, production rates, production costs, cost recovery provisions and local tax and royalty regimes. Changes in many of these factors do not affect estimates of U.S. reserves in the same way they affect estimates of proved reserves in foreign jurisdictions, or will have a different effect on reserves in foreign countries than in the United States. As a result, proved reserves in foreign jurisdictions may not be comparable to proved reserve estimates in the United States.

Foreign Operations

The Company’s international assets and operations are subject to various political, economic and other uncertainties, including, among other things, the risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favor or require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of the United States.

The Company’s private ownership of oil and gas reserves under oil and gas leases in the United States differs distinctly from its ownership of foreign oil and gas properties. In the foreign countries in which the Company does business, the state generally retains ownership of the minerals and consequently retains control of (and in many cases, participates in) the exploration and production of hydrocarbon reserves. Accordingly, operations outside the United States may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges.

The majority of the Company’s proven reserves are located offshore of the Republic of Gabon. The Company carries a gross investment of approximately $22.5 million on its balance sheet associated with the Etame Block offshore Gabon ($15.2 million net of accumulated depletion, depreciation and amortization costs). The Company has operated in Gabon since 1995 and believes it has good relations with the current Gabonese government. However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect the operations or cash flows of the Company.

Certain of the Company’s producing properties are located offshore Palawan Island in the Philippines, and, consequently, a portion of the Company’s assets is subject to regulation by the government of the Philippines. Although there has been unrest and uncertainty in the Philippines, to date, the country’s Office of Energy Affairs has been largely unaffected by political changes. The Company has operated in the Philippines since 1985 and believes that it has good relations with the current Philippine government. However, there can be no assurance that present or future administrations or governmental regulations in the Philippines will not materially adversely affect the operations or cash flows of the Company.

All of the Company’s current Philippine producing properties are located in fields covered under Service Contract No. 14. To obtain favorable tax treatment, Philippine nationals must own at least 15% of Service Contract No. 14. Residents of the Philippines currently own in excess of 15% of Blocks A, B, C and D of Service Contract 14. The Company’s ability to export oil produced in the Philippines is restricted by the terms of Service Contract No. 14. The Company currently sells its oil production within the Philippines and therefore may be exposed to foreign currency risk.

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Control by 1818 Fund

In connection with a merger with 1818 Oil Corp. in 1998, the Company issued to the 1818 Fund Common Stock and Preferred Stock which votes as a class with the Common Stock on an as converted basis, representing approximately 65% of the outstanding voting power of the Company on an as converted basis (excluding options and warrants). In addition, the terms of the Preferred Stock acquired by the 1818 Fund provide that while the Preferred Stock is outstanding, the holders of Preferred Stock voting together as a class are entitled to elect three directors of the Company. In connection with the 1818 Fund loan, the Company issued warrants to purchase 5.25 million shares of its common stock to the 1818 Fund at a price of $0.50 per share. (See “Background – Recent Developments” for a discussion of the line of credit.) Accordingly, the 1818 Fund is able to control all matters submitted to a vote of the stockholders of the Company, including the election of directors.

In connection with the 1818 Oil Corp. merger, the Company made certain changes to its bylaws which require that at least a majority of the directors constituting the entire board of directors, which majority must include at least one of the directors elected by the holders of Preferred Stock, approve each of the following transactions effected by either the Company or, as applicable, any subsidiary of the Company, (i) any issuance of or agreement to issue any equity securities, including securities convertible into or exchangeable for such equity securities (other than issuances pursuant to an employee benefit plan); (ii) the declaration of any dividend; (iii) the incurrence, assumption of or refinancing of indebtedness; (iv) the adoption of any employee stock option or similar plan; (v) entering into employment or consulting agreements with annual compensation exceeding $100,000; (vi) any merger or consolidation; (vii) the sale, conveyance, exchange or transfer of the voting stock or all or substantially all of the assets; (viii) the sale or other disposition to another person, or purchase, lease or other acquisition from another person, of any material assets, rights or properties; (ix) certain expenditures in excess of $300,000; (x) the formation of any entity that is not wholly-owned by the Company; (xi) material changes in accounting methods or policies; (xii) any amendment, modification or restatement of the certificate of incorporation or bylaws; (xiii) the settlement of any claim or other action against the Company or subsidiary in an amount in excess of $50,000; (xiv) approval or amendment of the annual operating budget; (xv) any other action which is not in the ordinary course of business; and the agreement to take any of the foregoing actions. Accordingly, none of the foregoing actions can be taken by the Company without the approval of at least one director designated by the holders of the Preferred Stock.

Acquisition Risks

The Company intends to acquire oil and gas properties. Although the Company performs a review of the acquired properties that it believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, the Company will focus its due diligence efforts on the higher valued properties and will sample the remainder. However, even an in-depth review of all properties and records may not necessarily reveal existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural or environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. The Company may be required to assume preclosing liabilities, including environmental liabilities, and may acquire interests in properties on an “as is” basis. There can be no assurance that the Company’s acquisitions will be successful.

Reliance on Key Personnel

The Company is highly dependent upon its executive officers and key employees, particularly Messrs. Gerry and Scheirman. The unexpected loss of the services of any of these individuals could have a detrimental effect on the Company. The Company does not maintain key man life insurance on any of its employees.

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Reliance on Sole Purchaser

In October 2003, the Company’s purchaser of crude oil in the Philippines announced closure of its refinery in the Philippines. This refinery closing forced the Company to shut in its Philippines production in the fourth quarter of 2003. Subsequently the Company entered into a crude oil purchase contract with Shell Oil related to the Company’s Philippines operations. The loss of Shell oil as a purchaser of the Company’s Philippines production could force the shut in of the Company’s Philippines production and could have a material adverse effect on the Company’s results of operations.

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Item 2.     Properties

Gabon

VAALCO has an interest in an offshore block in Gabon, the Etame Block. Interest in the block vests in a production-sharing contract entered into by the Company’s subsidiary VAALCO (Gabon) Etame, Inc., providing for two three-year terms, which commenced in July 1995. In July 2001, the Company negotiated a five-year extension of the Etame Block on behalf of the consortium, consisting of a three-year initial term and a two-year follow on term. The consortium committed to drill two additional exploration wells during the initial three-year term which expires in July 2004. The consortium paid a $1.0 million signing bonus ($0.3 million net to the Company) associated with the five-year extension. At December 31, 2003, VAALCO owned a 30.35% interest in the production-sharing contract covering the Etame Block, and 28.1% of the exploitation area surrounding the Etame field development. The exploitation area was subject to a 7.5% back-in by the Government of Gabon, which occurred upon field startup.

The Etame Block is a 3,073 square kilometer area acquired in July 1995, containing the Etame and Ebouri discoveries drilled by the Company and two former Gulf Oil Company discoveries, the North and South Tchibala discoveries. These discoveries consist of subsalt reservoirs that lie 20 miles offshore in approximately 250 feet of water depth. The Company and its partners undertook an obligation to the Government of Gabon to obtain and process seismic data and to drill one commitment well on the Etame Block over the three-year primary term of the license. This commitment was satisfied with the drilling of the Etame 1V discovery in 1998.

During 1998, the consortium of companies owning the Etame Block production sharing contract agreed to renew the production sharing contract for three additional years, thereby taking on a commitment to drill two additional exploration wells and to perform a 3-D seismic reprocessing. A delineation well, the Etame 2V well, was drilled in January 1999 followed by the the third exploration commitment well, the Etame 3V well was drilled in February 2001. In June 2001, drilling of the Etame 4V delineation well was completed.

As a result of the two successful delineation wells drilled in 2001, the Etame consortium approved a budget to develop the field. An application for commerciality was filed with the government of Gabon, and in November 2001, the consortium was awarded a 50 square kilometer Exploitation Area surrounding the field. The Exploitation Area has a term of up to 20 years to permit the field to be developed and produced.

The Phase I initial development consisted of completing three subsea wells connected to an FPSO at a cost of approximately $57.3 million ($17.4 million net to the Company inclusive of $1.5 million for the Company share of the Gabon Government carried 7.5% interest). On September 8, 2002, the Etame field commenced production at an average rate of approximately 14,500 BOPD. The Company sold a total of 6.5 million gross barrels (1.6 million net barrels) since field startup through December 31, 2003. During 2003 the field produced approximately 5 million gross barrels (1.2 million net barrels). Production continues at rates between 14,500 and 15,000 BOPD as of the date of this filing.

To fund its share of the Phase 1 development project, the Company negotiated a line of credit of $10.0 million through the IFC. (See “Background – Recent Developments” for a discussion of the line of credit.

During 2003, the Company completed the processing of seismic data acquired in late 2002, and identified several exploration prospect locations near the Etame field, and up to two new development well locations for the Etame field. The Company drilled the exploration well the Ebouri No. 1, commencing in December 2003. The well resulted in a new Gamba sand discovery logging 14 meters of oil pay in a 17 meter Gamba sand. Two sidetracks were performed to delineate the discovery, each of which logged a comparable amount of oil pay in the Gamba. The Company is performing economic studies to determine the feasibility of developing the discovery. The Company intends to spud the second exploration well location in the second quarter of 2004. The budget for the two exploration wells is $14.5 million ($4.4 million net to the Company).

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The Company submitted a Phase 2 Development Plan for the Etame field to the Gabon government for approval in October 2003. The Company plans to drill one new development well in the Etame field in the first half of 2004. A second development well will be drilled based on the outcome of the first development well. The budget for adding the first development well is $28.8 million ($8.7 million net to the Company) and includes laying two new flowlines and umbilicals from the well site to the floating production, storage and offloading system (“FPSO”) onsite in the Etame field. The extra flowline and umbilical are to be laid with the first development well to eliminate the need to mobilize lay vessel equipment when the second development well is drilled. The Company plans to use cash on hand and cash flow from operations to fund the planned exploration and Phase 2 development wells.

Philippines

The Company has an interest in two service contracts in the Philippines. Service Contract No. 14 covers 158,000 offshore acres and Service Contract No. 6 covers 131,000 offshore acres. The Company produces the Nido and Matinloc fields with a total gross production for 2003 of approximately 150,000 bbls or 410 BOPD.

Nido Field

The Nido field is covered by Service Contract No. 14 and has four producing wells. The field is produced using the cyclic method under which the field is shut in for a period of time (generally 60 days) and then opened up to produce (generally four to five days). During 2003, the four wells in the field produced at an equivalent rate of 218 BOPD compared to 404 BOPD in 2002. The field was shut in during the fourth quarter of 2003 while a new crude oil sales contract was negotiated. The Company has an approximate 22.1% working interest and an approximate 17.4% net revenue interest in the field.

Matinloc Field

The Matinloc field is located within the contract area covered by Service Contract No. 14 and has three producing wells. During 2003, the field produced approximately 70,000 bbls or 192 BOPD. The field was shut in during the fourth quarter of 2003 while a new crude oil sales contract was negotiated. The Company has an approximate 38.1% working interest and an approximate 26.8% net revenue interest in the field.

Galoc Field

The Galoc field is located within the contract area covered by Service Contract No. 14 and is currently not producing. Four wells have been drilled in this field, of which one well in 1,150 feet of water has undergone a long-term testing program. The Galoc reservoir is made up of a sandstone turbidite fan sequence that was deposited on top of the Lower Miocene limestone in a deep-water environment. Previous wells tested in excess of 5,000 BOPD. The Galoc field is one of the areas being studied extensively for the potential to drill an additional delineation well in the field. During 2002, the Company and its partners granted an exclusive development study option to a large oil company to determine if they wished to pursue the development of the field. The large oil company completed its study in October 2003 and declined to develop the field.

Domestic Properties

The Company has interest in seven producing wells in Brazos County, Frio County and Dimmit County, Texas producing from the Buda/Georgetown formations. The Company also owns certain non-operated interests in Ship Shoal areas of the Gulf of Mexico. During 2003 the wells produced approximately 6,600 bbls of oil and 51 million cubic feet of gas net to the Company. No capital expenditures are anticipated in 2004 for these properties.

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Aggregate Production

Aggregate production data (net to the Company) for all of the Company’s operations for the years 2003 and 2002 are shown below. The production figures exclude the amounts paid to the Gabon government as profit oil tax:

Company Owned Production

RESERVE INFORMATION

A reserve report as of December 31, 2003 has been opined on by Netherland Sewell & Associates, independent petroleum engineers. There have been no estimates of total proved net oil or gas reserves filed with or included in reports to any federal authority or agency other than the Commission since the beginning of the last fiscal year. The reserves are located in Gabon, the Philippines and Texas.

The standardized measure of discounted cash flows does not include all of the costs of abandoning the Company’s non-producing properties.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties.

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The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown are recoverable under the service contracts and the reserves in place remain the property of the Philippine government.

In accordance with the guidelines of the Commission, the Company’s estimates of future net cash flow from the Company’s properties and the present value thereof are made using oil and natural gas contract prices in effect as of year end and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The contract price as of December 31, 2003 was $14.92 per Bbl and $13.92 per Bbl of oil for Matinloc and the Nido fields respectively. In Gabon, the price was $30.15 per barrel representing a $0.15 discount to the spot price of Dated Brent Crude at December 31, 2003. See Financial Statements and Supplementary Data for certain additional information concerning the proved reserves of the Company.

Drilling History

The Company did not drill or participate in any exploration or development wells for the periods ended December 31, 2003 and 2002. An exploration well spudded in December 2003 reached total depth in January 2004 and resulted in a discovery. Three suspended wells were completed as producers in Gabon and one suspended well was completed in the United States in 2002.

Acreage and Productive Wells

Below is the total acreage under lease and the total number of productive oil and gas wells of the Company as of December 31, 2003:

Office Space

The Company leases its offices in Houston, Texas (approximately 8,000 square feet), in Port Gentil, Gabon (approximately 6,000 square feet) and in Manila, The Republic of the Philippines (approximately 4,000 square feet), which management believes are suitable and adequate for the Company’s operations.

Item 3.     Legal Proceedings

The Company is currently not a party to any material litigation.

Item 4.     Submission of Matters to a Vote of Security Holders

None.

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PART II

Item 5.     Market for Common Equity and Related Stockholder Matters

General

The Company’s Common Stock trades on the OTC Bulletin Board. The following table sets forth the range of high and low sales prices of the Common Stock for the periods indicated. The prices represent adjusted prices between dealers, do not include retail markups, markdowns or commissions and do not necessarily represent actual transactions. As of December 31, 2003 there were approximately 100 holders of record of the Company’s Common Stock.

On March 25, 2004 the last reported sale price of the Common Stock on the OTC Bulletin Board was $1.81 per share.

Dividends

The Company has not paid cash dividends and does not anticipate paying cash dividends on the Common Stock in the foreseeable future.

Item 6.     Management’s Discussion and Analysis or Plan of Operations

INTRODUCTION

The Company’s results of operations are dependent upon the difference between prices received for its oil and gas production and the costs to find and produce such oil and gas. Oil and gas prices have been and are expected in the future to be volatile and subject to fluctuations based on a number of factors beyond the control of the Company. The Company does not presently engage in any hedging activities and has no plans to do so in the near future.

The Company operates the Etame field on behalf of a consortium of five companies offshore of the Republic of Gabon. The field was developed in 2002 at a total cost approximately $57.3 million ($17.4 million net to the Company inclusive of $1.5 million of the Company share of the Gabon Government carried 7.5% interest). The Etame field produces at approximately 14,500 to 15,000 BOPD.

The Company’s production in the Philippines is from mature offshore fields with high production costs. The Company’s margin on sales from these fields (the price received for oil less the production costs for the oil) is lower than the margin on oil production from many other areas. As a result, the profitability of the Company’s production in the Philippines is affected more by changes in oil prices than production located in other areas.

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The Company’s results of operations are also affected by currency exchange rates. While oil sales are denominated in U.S. dollars, operating costs in the Philippines and a portion of operating costs in Gabon are denominated in local currencies. An increase in the exchange rate of the local currencies to the dollar will have the effect of increasing operating costs while a decrease in the exchange rate will reduce operating costs. The Gabon local currency is tied to the Euro, which appreciated substantially against the dollar in 2003.

A substantial portion of the Company’s oil production is located offshore of Gabon and the Philippines. In Gabon, the Company produces into a 1.1 million barrel tanker and sells cargos to Shell Oil at spot market prices. In the Philippines, the Company produces into 10,000 to 15,000 barrel barges, which transport the oil to market. In the Philippines, due to weather and other factors, the Company’s production is generally highest during the first and fourth quarters of the year. Weather is not normally a factor affecting Gabon oil sales.

CRITICAL ACCOUNTING POLICIES

The following describes the critical accounting policies used by VAALCO in reporting its financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting, such is the case with accounting for oil and gas activities described below. In those cases, the Company’s reported results of operations would be different should it employ an alternative accounting method.

Successful Efforts Method of Accounting for Oil and Gas Activities. The Securities and Exchange Commission (“SEC”) prescribes in Regulation SX the financial accounting and reporting standards for companies engaged in oil and gas producing activities. Two methods are prescribed: the successful efforts method and the full cost method. Like many other oil and gas companies, VAALCO has chosen to follow the successful efforts method. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there are risk associated with future success and as such earnings are best represented by attachment to the drilling operations of the Company.

Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. For financial accounting purposes the Company adopted SFAS 143 – Accounting for Asset Retirement Obligations on January 1, 2003. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred.

In accordance with accounting under successful efforts, the Company reviews proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value. This may occur if a field discovers lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field.

Undeveloped acreage and Work in Progress. At December 31, 2003, the Company had $1,905,000 of work in progress associated with the Ebouri exploration well drilling at year-end 2003 and also associated with seismic costs in Gabon. Unproved properties are assessed quarterly for impairment in value, with any impairment charged to expense. During 2003, $260,000 of leases that expired in Alabama and Mississippi were expensed.

In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets,”

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which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS Nos. 141 and 142 clarify that more assets should be distinguished and classified between tangible and intangible. The staff of the SEC and the accounting industry are currently in discussion regarding the application of SFAS Nos. 141 and 142 to companies engaged in the oil and gas business. SFAS Nos. 141 and 142 may require oil and gas companies to classify cost associated with the acquisition of contractual property rights (such as the Company’s concessions in Gabon and the Philippines and the Company’s leases in the United States) as intangible assets. Fee mineral interests would be classified as tangible assets. Consistent with industry practice, the Company has not classified contractual mineral rights as intangible assets. If it is ultimately determined that SFAS Nos. 141 and 142 require classification of contractual mineral rights as intangible assets, the Company’s oil and gas properties would be reduced by $59,000 and intangible assets would be increased by a like amount at December 31, 2003. The provisions of SFAS Nos. 141 and 142 impact only the balance sheet and associated footnote disclosures, and reclassifications would not impact the Company’s cash flows or results of operations.

In August 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible, long-lived assets and the associated asset retirement costs. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. As required by SFAS No. 143, the Company adopted this new accounting standard effective January 1, 2003. The Company had previously recorded certain asset retirement obligations at gross amounts. Effective January 1, 2003, the Company recognized $1.7 million of income as a result of the adoption of SFAS No. 143.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3. The Company has adopted the provisions of SFAS No. 146 for restructuring activities effective January 1, 2003. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. The impact that SFAS No. 146 will have on the consolidated financial statements will depend on the circumstances of any specific exit or disposal activity.

In November 2002, FASB Interpretation (“FIN”) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” elaborates on the disclosure to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. This Interpretation also incorporates, without change, the guidance in FIN No. 34, which is being superceded. As set forth in the Interpretation, the disclosures required are designed to improve the transparency of the financial statement information about the guarantor’s obligations and liquidity risks related to guarantees issued. The fair values of guarantees entered into after December 31, 2002, must be recorded as a liability of the guarantor in its financial statements. Existing guarantees as of December 31, 2002 are grandfathered from the recognition provisions, unless they are later modified, but they are still required to be disclosed. The disclosure requirements are effective for periods ending after December 15, 2002. See Note 7 for the required disclosures as of December 31, 2003.

In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities – An Interpretation of Accounting Research Bulletin 51”. FIN 46 addresses consolidation by business enterprises of variable interest entities (“VIEs”) and the primary objective is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such

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entities are known as VIEs. FIN 46 requires an entity to consolidate a VIE if the entity has a variable interest (or combination of variable interests) that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. The guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. However, on October 8, 2003, the FASB decided to grant a broader deferral of the implementation of FIN 46. Pursuant to this deferral, the Company must complete its evaluation of VIEs that existed prior to February 1, 2003, and the consolidation of those for which it is the primary beneficiary for financial statements issued for the first period ending after December 15, 2003. Consolidation of previously existing VIEs will be required in the Partnership’s December 31, 2003 financial statements. The Company has no VIEs to consolidate as of December 31, 2003.

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. The Company adopted SFAS No. 149 on July 1, 2003. The adoption of SFAS No. 149 had no effect on the Company’s financial position, results of operations or cash flows.

In May 2003, The FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). The Company adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on the Company financial position, results of operations or cash flows.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2003 was $22.6 million, as compared to $0.8 million in 2002. Net funds provided by operations in 2003 included net income of $8.9 million, non-cash depreciation, depletion and amortization of $5.9 million and working capital increases of $4.1 million primarily as a result of the Etame field operations in Gabon. It also included the add back of non-cash exploration expense of $1.8 million associated with the write off of the Etame 2V well in Gabon and certain acreage acquired prior to 2003, and non-cash add back of $1.3 million of minority interest expense. In 2002, net cash uses included $4.0 million reduction in accounts with partners. It also included $1.5 million of development and operating costs advanced on behalf of the Government of Gabon for their 7.5% carried working interest share of the Etame field. This amount is carried as an Other Receivable. Offsetting these cash uses was an increase of $4.7 million in trade accounts payable net of trade accounts receivable.

Net cash used in investing activities for 2003 was $1.9 million, as compared to net cash used in investing activities of $15.9 million in 2002. In 2003, the Company added to its investment in Gabon by participating in the Ebouri No. 1 well, which was classified as work in progress at year end 2003. The well was subsequently suspended as a discovery well in 2004. In 2002, the Company invested $15.6 million to fund its share of the development of the Etame Block.

In 2003, net cash used by financing activities was $5.4 million consisting primarily of $13.0 million of debt reduction, financed in part by the use of $7.9 million of funds in escrow. Net cash provided by financing activities in 2002 was $13.0 million consisting of borrowings of $20.0 million from the IFC and the 1818 Fund and $3.3 million from the sale of stock of VAALCO’s subsidiary VAALCO International, Inc. This was offset by $10.0 million of funds placed in escrow to guarantee the IFC loan.

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Capital Expenditures

During 2003 the Company spent $1.9 million on activities associated with the Phase 2 development and to commence the drilling of an exploration well. During 2004, the Company anticipates participating in additional exploration and development opportunities on the Etame Block, which will be funded by cash flow from operations. Total Phase 2 development and exploration capital expenditures for 2004 are budgeted to be approximately $12.0 million net to the Company.

Historically, the Company’s primary sources of capital resources has been from cash flows from operations, private sales of equity, borrowings and purchase money debt. At December 31, 2003 the Company had cash balances of $23 million. The Company believes that this cash balance combined with cash flow from operations will be sufficient to fund the Company’s 2004 capital expenditure budget of approximately $12 million, required debt repayments of $4 million and additional investments in working capital resulting from potential growth. As operator of Etame field the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from it partners prior to significant funding commitments.

To fund its share of the Phase 1 Etame field development costs, on April 19, 2002, the Company entered into a $10.0 million credit facility with the International Finance Corporation (“IFC”), a subsidiary of the World Bank. During the year ended December 31, 2003 the Company repaid $3.0 million of the loan as called for under the facility repayment schedule.

The credit facility required that the Company provide $10.0 million of cash collateral to secure borrowings under the facility until the project completion date. The Company borrowed the $10.0 million that it used as cash collateral from the 1818 Fund II, L.L.P. and another investor that is not affiliated with the Company.

The Company was notified by the IFC that the project completion date occurred on March 31, 2003. On April 1, 2003, the $10.0 million cash collateral posted by the Company was released. The $10.0 million of cash collateral was used to repay the 1818 Fund Loan on April 1, 2003. Also during April 2003, the Company paid accrued interest expense on the 1818 Fund loan of $0.7 million. Project completion marked the end of the Phase 1 development of the Etame field.

On September 8, 2002, the company commenced production from the Etame field offshore Gabon. Through 2003 total field production sold was 6.5 million bbls (1.6 million bbls net to the Company). The Company also produces oil from the Matinloc and Nido fields in the South China Sea, the Philippines.

Substantially all of the Company’s crude oil and natural gas is sold at the well head at posted or index prices under short-term contracts, as is customary in the industry. In Gabon, the Company markets its crude oil under and agreement with Shell Western Trading and Supply, Limited. In the Philippines, for most of 2003, the Company marketed its crude oil in the Philippines under an agreement with Caltex. In October 2003, Caltex announced the closure of its refinery in the Philippines. Subsequently, the Company recently signed a contract with Shell Oil to sell crude production from its Philippines oil fields. While the loss of Shell Oil as a buyer might have a material adverse effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil.

Domestically, the Company produces from wells in Brazos County, Frio County and Dimmit County, Texas. During 2003, the Company had net production of 6,600 bbls of oil and 51 million cubic feet of gas. Domestic production is sold via separate contracts for oil and gas. The Company has access to several alternative buyers for oil and gas sales domestically.

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Contractual Obligations

In addition to its lending relationships and obligations, the Company has contractual obligations under operating leases. The table below summarizes these obligations and commitments at December 31, 2003 (in thousands):

Payment Period

RESULTS OF OPERATIONS

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Amounts stated hereunder have been rounded to the nearest $100,000.

Revenues

Total oil and gas sales for 2003 were $36.0 million as compared to $10.0 million for 2002. Revenues in 2003 benefited from a full year of production from the Etame field, where the Company sold 1,226,000 net bbls at an average price of $28.54 per barrel. Revenues from the Philippines and Texas in 2003 were approximately $1.0 million. In September 2002, the Etame field was placed on production, and the Company sold approximately 302,000 net bbls of oil, generating $8.9 million in revenues in that year. The balance of the 2002 revenues was from Texas and the Philippines.

Operating Costs and Expenses

Production expenses for 2003 were $9.3 million as compared to $2.8 million for 2002. In 2003, the Etame field was on production for a full year compared to only four months of production expenses in 2002.

Exploration costs for 2003 were $2.1 million as compared to $0.3 million for 2002. Exploration costs in 2003 consisted of a $1.5 million write off of the Etame 2V well, which had previously been carried as work in progress, and the $0.3 million write off of certain leases that expired in Alabama and Mississippi. In 2003 exploration expense also included $0.3 million for seismic reprocessing in Gabon. In 2002 exploration costs were primarily costs of seismic reprocessing in Gabon.

Depreciation, depletion and amortization of properties for 2003 and 2002 were $5.9 million and $2.1 million respectively. Depletion in 2003 included the full year effect of Etame production accounting for $5.6 million of the year’s total. The balance was associated with the Texas wells, ($0.2 million) and depletion of the asset recorded related to abandonment obligations ($0.2 million). Depletion in 2002 included $1.8 million associated with Etame production. The balance was associated with the Texas wells.

General and administrative expenses for 2003 were $2.3 million as compared to $2.0 million for 2002. Increased activity associated with the full year’s production activity at the Etame field was the primary reason for the increase in 2003.

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Operating Income

Operating income for 2003 was $16.4 million as compared to a $2.9 million income for 2002. The full year of production operations from the Etame field in 2003 was responsible for the 2003 operating income, compared to only four months production from the Etame field in 2002.

Other Income (Expense)

Interest income for 2003 was $0.1 million compared to $0.2 million in 2002. Both the 2003 and 2002 amounts represent interest earned and accrued on cash balances and funds in escrow.

Interest expense of $2.6 million was recorded in 2003 associated with the financings for the development of the Etame field as compared to $0.8 million in 2002. In 2003, interest expense included $1.6 million of non cash amortization of debt discount associated with the issuance of warrants in connection with the 1818 Fund Loan.

Income Taxes

In 2003, the Company incurred $5.3 million of foreign income taxes. $5.5 million was paid in Gabon associated with the Etame field production. The Company recognized a deferred tax benefit of $0.2 million in the Philippines. In 2002 the Company incurred income taxes of $1.4 million, all but $10,000 of which was paid in Gabon.

Minority Interest

A provision for minority interest in the Gabon subsidiary was made for $1.3 million and $0.3 million in 2003 and 2002 respectively.

Cumulative Effect of Accounting Change

In 2003 the Company experienced a one time gain of $1.7 million associated with the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.”

Net Income

Net income attributable to common stockholders for 2003 was $8.9 million as compared to a net income of $0.4 million in 2002. The full year impact of profitable production operations in Gabon was responsible for the increase in net income in 2003. The commencement of production in September 2003 from the Etame field was the primary contributor to net income in 2002.

Item 7.     Financial Statements and Supplementary Data

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholders of VAALCO Energy, Inc. and Subsidiaries:

We have audited the consolidated balance sheet of VAALCO Energy, Inc. and its subsidiaries (“VAALCO”) as of December 31, 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2003. These financial statements are the responsibility of VAALCO’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of VAALCO as of December 31, 2003, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 9 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

Deloitte & Touche LLP

Houston, Texas

March 30, 2004

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(in thousands of dollars, except number of shares and par value amounts)

See notes to consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

(in thousands of dollars, except per share amounts)

See notes to consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2002

(in thousands of dollars, except share data)

See notes to consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(in thousands of dollars)

See notes to consolidated financial statements.

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VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2003

(in thousands of dollars unless otherwise indicated)

1.    ORGANIZATION

VAALCO Energy, Inc., a Delaware corporation, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. As used herein, the terms “Company” and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. VAALCO owns producing properties and conducts exploration activities as operator of consortiums internationally in the Philippines and Gabon. Domestically, the Company has interests in the Texas Gulf Coast area. In both Gabon and the Philippines, VAALCO serves as the operator for groups of companies which own the working interests in the production sharing contracts, collectively referred to as consortiums.

VAALCO’s subsidiaries include Alcorn (Philippines) Inc., Alcorn (Production) Philippines Inc., Altisima Energy, Inc., VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Energy (USA), Inc. and 1818 Oil Corp.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The portion of the income and net assets applicable to the Company non-controlling interest in the majority-owned operations of the Company’s Gabon subsidiary is reflected as minority interest. All significant transactions within the consolidated group have been eliminated in consolidation.

Cash and Cash Equivalents—For purposes of the statements of consolidated cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Funds in Escrow—Escrow Cash includes cash that is contractually restricted for non-operational purposes such as debt service and capital expenditures. Restricted cash and cash equivalents are classified as a current or non-current asset based on their designated purpose. Current amounts represent an escrow for the IFC loan ($1.1 million) and an escrow to secure a letter of credit associated with an ongoing drilling program ($1.0 million). Long term amounts represent an escrow to secure charter payments for the Floating Production Storage and Offloading tanker (“FPSO”) in Gabon ($0.8 million) and for the abandonment of certain Gulf of Mexico properties ($38).

Inventory—Materials and supplies are valued at the lower of cost, determined by the weighted-average method, or market. Crude oil inventories are carried at the lower of cost or market and represent the Company’s share of crude oil production produced and stored on the tanker, but unsold. Cost represents the production expenses excluding depletion.

Income Taxes—VAALCO accounts for income taxes under an asset and liability approach that recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statements and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized.

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VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Property and Equipment—The Company follows the successful efforts method of accounting for exploration and development costs. Under this method, exploration costs, other than the cost of exploratory wells, are charged to expense as incurred. Exploratory well costs are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved reserves, the associated costs are expensed at that time. All development costs, including developmental dry hole costs, are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. The Company recognizes gains/losses for the sale of developed properties based upon an allocation of property costs between the interests sold and the interests retained based on the fair value of those interests.

The Company reviews its oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value.

Depletion of wells, platforms and other production facilities are provided on a field basis under the unit-of-production method based upon estimates of proved developed reserves. For financial accounting purposes the Company adopted Statement of Financial Accounting Standards (“SFAS”) 143 – “Accounting for Asset Retirement Obligations” on January 1, 2003 (See Note 9). This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. Provision for depreciation of other property is made primarily on a straight-line basis over the estimated useful life of the property. The annual rates of depreciation are as follows:

Investments—The Company invests funds in escrow and excess cash in certificates of deposit and commercial paper issued by banks with maturities typically not exceeding 90 days.

Foreign Exchange Transactions—For financial reporting purposes, the subsidiaries use the United States dollar as their functional currency. Monetary assets and liabilities denominated in foreign currency are translated to U.S. dollars at the rate of exchange in effect at the balance sheet date, and items of income and expense are translated at average monthly rates. Nonmonetary assets and liabilities are translated at the exchange rate in effect at the time such assets were acquired and such liabilities were incurred. Gains and losses on foreign currency transactions are included in income currently. The Company incurred a loss on foreign currency transactions of $7 in 2003 and $53 in 2002.

Accounts With Partners—Accounts with partners represent cash calls due or excess cash calls paid by the partners for exploration, development and production expenditures made by the following subsidiaries of the Company: Alcorn (Production) Philippines Inc. and VAALCO Gabon (Etame), Inc.

Revenue Recognition—The Company recognizes revenues from crude oil and natural gas sales upon delivery to the buyer.

Stock-Based Compensation—SFAS No. 123, “Accounting for Stock-Based Compensation” encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value as determined by generally recognized option pricing models such as the Black-Scholes model or the binomial model. Because of the inexact and subjective nature of deriving non-freely traded employee stock

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

option values using these methods, the Company has adopted the disclosure-only provisions of SFAS No. 123 and continues to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, no compensation cost has been recognized for the Company’s stock-based plans. Had compensation cost for the Company’s stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans consistent with the optional method prescribed by SFAS No. 123, the Company’s net income and net income per share would have been adjusted to the pro forma amounts indicated below (in thousands, except per share data):

The total stock based employee compensation expense was determined under the fair value based method for all awards, net of related tax effects.

The effects of applying SFAS No. 123 in the disclosure may not be indicative of future amounts as additional awards in future years are anticipated.

The valuation of the options is based upon a Black Scholes model assuming expected volitality of 38 %, risk-free interest rate of 5.5%, expected life of options of 3 to 5 years, depending upon the award and expected dividend yield of 0%.

Fair Value of Financial Instruments—The Company’s financial instruments consist primarily of cash, trade accounts, note receivables, trade payables and debt. The book values of cash, trade receivables, and trade payables are representative of their respective fair values due to the short-term maturity of these instruments. The book value of the Company’s notes receivable and debt instruments are considered to approximate the fair value, as the interest rates are adjusted based on rates currently in effect.

Risks and Uncertainties—The Company’s interests are located overseas in certain offshore areas of the Philippines and Gabon.

Substantially all of the Company’s crude oil and natural gas is sold at the well head at posted or index prices under short-term contracts, as is customary in the industry. In Gabon, the Company sells crude oil under a contract with Shell Western Supply and Trading, Limited. Shell Western Supply and Trading, Limited accounted for 97% and 89% of total revenues in 2003 and 2002 respectively. In the Philippines, for most of 2003, the Company marketed its crude oil share in the Philippines under an agreement with Caltex. In October 2003, Caltex announced the closure of their refinery in the Philippines. The Company recently signed a new contract with Shell Oil to sell crude production from its Philippines oil fields. While the loss of these buyers might have a material effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil. Domestic production is sold under two contracts, one for oil and one for gas. The Company has access to several alternative buyers for oil and gas sales domestically.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Estimates of oil and gas values as made in the financial statements require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such estimates of value. The information set forth herein is therefore subjective and, since judgments are involved, may not be comparable to estimates of value made by other companies. The Company considers its estimates to be reasonable; however, due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available.

3.    RECENT ACCOUNTING PRONOUNCEMENTS

In June 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3. The Company has adopted the provisions of SFAS No. 146 for restructuring activities effective January 1, 2003. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. The impact that SFAS No. 146 will have on the consolidated financial statements will depend on the circumstances of any specific exit or disposal activity.

In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS Nos. 141 and 142 clarify that more assets should be distinguished and classified between tangible and intangible. The staff of the SEC and the accounting industry are currently in discussion regarding the application of SFAS Nos. 141 and 142 to companies engaged in the oil and gas business. SFAS Nos. 141 and 142 may require oil and gas companies to classify costs associated with the acquisition of contractual property rights (such as the Company’s concessions in Gabon and the Philippines and the Company’s leases in the United States) as intangible assets. Fee mineral interests would be classified as tangible assets. Consistent with industry practice, we have not classified contractual mineral rights as intangible assets. If it is ultimately determined that SFAS Nos. 141 and 142 require classification of contractual mineral rights as intangible assets, the Company’s oil and gas properties would be reduced by $59 and intangible assets would be increased by a like amount at December 31, 2003. The provisions of SFAS No. 141 and 142 impact only the balance sheet and associated footnote disclosures, and reclassifications would not impact the Company’s cash flows or results of operations.

In December 2002, FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure. SFAS No. 148 amends SFAS No. 123 “Accounting for Stock Based Compensation” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. During the year ending December 31, 2003, officers of the Company exercised options for 395,479 shares utilizing cashless provisions, resulting in a compensation expense of $444, which was recorded as a general and administrative expense. The provisions of SFAS No. 148 had no material effect on the Company’s financial position or results of operations for the year ended December 31, 2002.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In November 2002, FASB Interpretation (“FIN”) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” elaborates on the disclosure to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. This Interpretation also incorporates, without change, the guidance in FIN No. 34, which is being superceded. As set forth in the Interpretation, the disclosures required are designed to improve the transparency of the financial statement information about the guarantor’s obligations and liquidity risks related to guarantees issued. The fair values of guarantees entered into after December 31, 2002, must be recorded as a liability of the guarantor in its financial statements. Existing guarantees as of December 31, 2002 are grandfathered from the recognition provisions, unless they are later modified, but they are still required to be disclosed. The disclosure requirements are effective for periods ending after December 15, 2002. See Note 7 for the required disclosures as of December 31, 2003.

In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities—An Interpretation of Accounting Research Bulletin 51”. FIN 46 addresses consolidation by business enterprises of variable interest entities (“VIEs”) and the primary objective is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an entity to consolidate a VIE if the entity has a variable interest (or combination of variable interests) that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. The guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. However, on October 8, 2003, the FASB decided to grant a broader deferral of the implementation of FIN 46. Pursuant to this deferral, the Company must complete its evaluation of VIEs that existed prior to February 1, 2003, and the consolidation of those for which it is the primary beneficiary for financial statements issued for the first period ending after December 15, 2003. The Company has no VIEs to consolidate as of December 31, 2003.

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. The Company adopted SFAS No. 149 on July 1, 2003. The adoption of SFAS No. 149 had no impact on the Company’s financial position, results of operations or cash flows.

In May 2003, The FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). The Company adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on the Company’s financial position, results of operations or cash flows.

Use of Estimates in Financial Statement Preparation—The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities as well as certain disclosures. The Company’s financial statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.

Reclassifications—Certain amounts from 2002 have been reclassified to conform to the 2003 presentation.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

4.    STOCKHOLDERS’ EQUITY

The Company is authorized to issue up to 100 million shares of Common Stock. Stockholder’s equity consists of preferred stock, common stock, options and warrants. Set out below is a summary of the number of shares on an as converted basis assuming cash exercise of all warrants and options. Certain options and warrants have cashless exercise features that would alter the number of shares issued if this feature were utilized.

The following discussion of shares under option incorporates options granted by the predecessor VAALCO and the Company.

In 1996 options were granted to an officer and director for 1,000,000 shares of the Common Stock of the Company at exercise prices of $0.375 per share for 400,000 shares, $0.50 for 300,000 shares and $1.00 for 300,000 shares. The options vested over a term of three years were exercisable for five years from the vesting date. A total of 520,000 of the options were forfeited in 2002. The remainder of the options were exercised in 2003. The Company recorded $276 of non-cash compensation expense associated with the exercise of 221,000 net stock options by the officer of the Company.

In 1996, a former officer of the Company was granted warrants to purchase shares of the Company’s Common Stock. The warrants expired August 31, 2003 and consisted of the right to purchase 250,000 shares of Common Stock at an exercise price of $0.50 per share; 250,000 shares of Common Stock at an exercise price of $2.50 per share; 250,000 shares of Common Stock at an exercise price of $5.00 per share; and 250,000 shares of Common Stock at an exercise price of $7.50 per share. The 250,000 warrants at $0.50 per share were exercised in 2003. The remainder of the warrants expired unexercised.

In 1997, another officer of the Company was granted options to purchase 1,000,000 shares at $0.625 per share, vesting 500,000 shares at August 1, 1997 and 500,000 shares at August 1, 1998. A total of 500,000 options were forfeited in 2002. The remaining options were exercised in 2003. The Company recorded $167 of non-cash compensation expense associated with the exercise of 174,479 net stock options by the officer of the Company.

An investment banking firm was granted 345,325 warrants to purchase the Company’s Common Stock on July 31, 1997 in connection with the private placement of Common Stock. The warrants had a term of five years from the date of issuance and consist of the right to purchase shares at $1.00 per share. The same investment banking firm was granted 100,000 warrants to purchase the Company’s Common Stock on April 1, 1998 in connection with the private placement of Common Stock. The warrants had a term of five years from the date of issuance and consist of the right to purchase shares at $2.00 per share. The banking firm exercised 345,325 warrants in 2002 under the cashless exercise feature and received a total of 31,386 shares of common stock. The remaining 100,000 warrants expired unexercised in 2003.

On November 29, and December 15, 2000, options to purchase a total of 600,000 shares were granted at $0.30 per share to two technical representatives of the Company. The options have a term of five years from the date of issuance. These options vested six months after issuance. An additional 200,000 options were issued to the technical representatives during 2001 at $0.30 per share, expiring on December 15, 2005. During 2002 and 2003, the technical representatives exercised 55,000 and 50,000 options, respectively.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On June 10, 2002 and August 30, 2002 respectively, 15,000,000 and 4,500,000 warrants to purchase common stock at $0.50 per share were issued in connection with the 1818 Loan (See Note 8). 12,000,000 of the warrants were surrendered back to the Company upon the project completion of the Etame field. The remaining 7,500,000 warrants are issued and outstanding.

On June 19, 2003 the board of directors awarded 100,000 and 25,000 options to two directors, respectively, to purchase common stock at $1.04 per share. The options are fully vested and have a term of five years. None of the options were exercised as of December 31, 2003.

On December 16, 2003 the board of directors awarded 3,721,000 options to a group of officers, employees, consultants and directors to purchase common stock at $1.16 per share. The options have a term of three years, and vested one third upon issuance, one third on the first anniversary of the issuance date and one third upon the second anniversary date of the issuance. All of the options remain unexercised as of December 31, 2003.

Information with respect to the Company’s warrants and stock options is as follows:

The following table summarizes information about stock options and warrants outstanding as of December 31, 2003: