UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-KSB

(Mark One)

x ANNUAL REPORT UNDER TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

OR

¨ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number: 0-20928

VAALCO Energy, Inc.

(Name of small business issuer in its charter)

Delaware	76-0274813
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
4600 Post Oak Place Suite 309 Houston, Texas	77027
(Address of principal executive offices)	(Zip code)

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

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

Title of each class	Name of each exchange on which registered
Common Stock, $.10 par value	American Stock Exchange

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

None

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, 2004 were $56,502,392.

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, as of March 1, 2005 was $91,265,774.

As of March 1, 2005, there were outstanding 32,994,250 shares of Common Stock, $.10 par value per share, of the registrant. In addition, as of such date there were outstanding 6,667 shares of Preferred Stock convertible into 18,334,250 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.

VAALCO ENERGY, INC.

TABLE OF CONTENTS

PART I
Item 1.	Business	3
Item 2.	Properties	14
Item 3.	Legal Proceedings	18
Item 4.	Submission of Matters to a Vote of Security Holders	18
PART II
Item 5.	Market for Common Equity and Related Stockholder Matters	19
Item 6.	Management’s Discussion and Analysis or Plan of Operations	19
Item 7.	Financial Statements and Supplementary Data	26
Item 8.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	52
PART III
Item 9.	Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act	52
Item 10.	Executive Compensation	52
Item 11.	Security Ownership of Certain Beneficial Owners and Management	52
Item 12.	Certain Relationships and Related Transactions	53
Item 13.	Exhibits and Reports on Form 8-K	53
Item 14.	Principal Accountant Fees and Services	55
	Glossary of Oil and Gas Terms	56

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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 a consortium internationally in Gabon, West Africa. Domestically, the Company has minor interests in the Texas Gulf Coast area.

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. VAALCO’s Philippine subsidiaries include Alcorn (Philippines) Inc., Alcorn (Production) Philippines Inc. and Altisima Energy, Inc. The Company is in the process of winding up the affairs of the Philippines subsidiaries as it sold all of its Philippines assets in 2004.

In connection with a merger with 1818 Oil Corp. in 1998, the Company issued to the 1818 Fund II, 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.

During the first quarter of 2005, the 1818 Fund exercised it right, under a registration rights agreement with the Company, to require the Company to file a registration statement covering the sale by the 1818 Fund of the common stock owned by the 1818 Fund and the shares of Common Stock which the 1818 Fund may acquire upon conversion of the Preferred Stock and exercise of Warrants held by it. Under the registration statement, the 1818 Fund may sell all or any number of the shares of Common Stock beneficially owned by it in one or more transactions, including open market sales and block trades over the American Stock Exchange, negotiated transactions and underwritten offerings. The 1818 Fund has advised the Company that the 1818 Fund is in the process of gradually liquidating the remaining positions in its portfolio, and that as part of that process plans to sell its equity interest ins the Company. The 1818 Fund further advised the Company that it does not intend to “dribble out” the shares of Common Stock beneficially owned by it, by selling such shares in the open market in unsolicited transactions.

If the 1818 Fund were to sell all or a substantial portion of the Common Stock beneficially owned by it, the 1818 Fund would no longer control matters submitted to stockholders of the Company. In addition, if the 1818 Fund sells all or a substantial portion of the Common Stock beneficially owned by it, the directors elected by the 1818 Fund as the owner of the Preferred Stock may resign from VAALCO’s board of directors. (See “Risk Factors – Control by 1818 Fund”).

RECENT DEVELOPMENTS

The Company’s primary source of revenue is from the Etame field located offshore the Republic of Gabon. The Company drilled one additional development well in the Etame field during 2004, the Etame 5H well. During 2004, the Etame field produced approximately 6.3 million barrels (1.5 million barrels net to the Company).

During 2004, the Company drilled two exploration wells on the Etame Block, the Ebouri No. 1 and the Avouma No. 1. Both wells resulted in new discoveries. The Avouma discovery is adjacent to a previous discovery known as South Tchibala. The Company has received approval from the Gabon government that it

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deems the Avouma/South Tchibala discoveries commercial and ready for development. The Company acquired new seismic data over the Ebouri discovery in January of 2005. Upon completion of a review of the processed data, the Company anticipates filing for a development permit for the Ebouri discovery.

In February 2005, the Company accepted a proposal from a drilling contractor to lease a drilling rig to drill the Etame 6H well, which is a fifth development well in the Etame field. The company plans to drill the well commencing late in the second quarter of 2005. After completing the Etame 6H well, the Company will drill an exploration well in the vicinity of the Avouma discovery with the same rig.

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 development of the Avouma, South Tchibala and Ebouri discoveries. The Company anticipates drilling selected exploration prospects on its Gabon acreage, including at least one exploration well in 2005. The Company plans to utilize cash on hand and 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 a consortium internationally in Gabon.

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. While the loss of Shell as a buyer might have a material effect on the Company in the short 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, 2004, the Company had 12 full-time employees, five of whom were located in Gabon. 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.

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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 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.

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

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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. States such as Texas have comparable statutes. In the event contamination is discovered at a site on which the Company is or has been an owner or operator, the Company could be liable for costs of investigation and remediation and material resource damages.

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 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 in the case of offshore facilities, 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

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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.

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 STATEMENTS

This Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, which are intended to be covered by the safe harbors created by those laws. The Company has based these forward-looking statements on its current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of the Company’s operations. All statements, other than statements of historical facts, included in this Report that address activities, events or developments that the Company expects or anticipates may occur in the future, including without limitation, statements regarding the Company’s financial position, reserve quantities and net present values, business strategy, plans and objectives of the Company’s management for future operations are forward-looking statements. When the Company uses words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “probably” or similar expressions, the Company is making forward-looking statements. Many risks and uncertainties may impact the matters addressed in these forward-looking statements.

Some of the events or factors that could affect the Company’s future results and could cause results to differ materially from those expressed in the Company’s forward-looking statements include:

• the volatility of oil and natural gas prices;

• the uncertainty of estimates of oil and natural gas reserves;

• the impact of competition;

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• the availability and cost of seismic, drilling and other equipment;

• operating hazards inherent in the exploration for and production of oil and natural gas;

• difficulties encountered during the exploration for and production of oil and natural gas;

• difficulties encountered in delivering oil to commercial markets;

• general economic conditions;

• changes in customer demand and producers’ supply;

• the uncertainty of the Company’s ability to attract capital;

• compliance with, or the effect of changes in, the foreign governmental regulations regarding the Company’s exploration and production;

• actions of operators of the Company’s oil and gas properties; and

• weather conditions.

The information contained in this Report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could cause the Company’s results or performance to differ materially from those the Company expresses in its forward-looking statements. Although the Company believes that the assumptions underlying its forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements which are included in this Report, the Company’s inclusion of this information is not a representation by the Company or any other person that the Company’s objectives and plans will be achieved. When you consider the Company’s forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Report.

The Company’s forward-looking statements speak only as of the date made and the Company will not update these forward-looking statements unless the securities laws require the Company to do so. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. In light of these risks, uncertainties and assumptions, any forward-looking events discussed in this Report may not occur.

RISK FACTORS

Almost all of the value of the Company’s production and reserves is concentrated in a single field offshore Gabon, and any production problems or inaccuracies in reserve estimates related to this property would adversely impact the Company’s business.

The Etame field, consisting of four wells, constituted almost 100% of the Company’s total production for the years ended December 31, 2004 and December 31, 2003. If mechanical problems, storms or other events curtailed a substantial portion of this production, or if the actual reserves associated with this producing property are less than the Company’s estimated reserves, the Company’s results of operations and financial condition could be adversely affected.

The Company’s results of operations and financial condition could be adversely affected by changes in currency exchange rates.

The Company’s results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of operating costs in Gabon are denominated in the local currency. An increase in the exchange rate of the local currency 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 and 2004.

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A decrease in oil and gas prices may adversely affect the Company’s results of operations and financial condition.

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. Historically, world-wide oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future. Recently, medium/heavy sweet crude oils which produce higher amounts of residual fuel oil have experienced weaker demand in the marketplace. This has resulted in those crude oils trading at a discount to their traditional benchmark. These crude oils are similar to those produced from the Etame field, and the lower market price may have an adverse impact on the Company’s results of operations.

Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Company’s control. 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 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 the Company’s planned level of capital expenditures.

Unless the Company is able to replace reserves which it has produced, the Company’s cash flows and production will decrease over time.

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. The Company’s current domestic oil and gas properties are operated by third parties 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, which may not be available to the Company in the future, is required to replace and grow reserves.

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 participated in, and in 2005 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. However, if lower oil and gas prices, operating difficulties or declines in reserves result in the Company’s revenues being less than expected or limit the Company’s ability to borrow funds, or the

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Company’s partners fail to pay their share of project costs, the Company may have a limited ability to expend the capital necessary to undertake or complete future drilling programs. The Company cannot assure you that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

The Company’s drilling activities require it to risk significant amounts of capital that may not be recovered.

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.

Weather, unexpected surface conditions and other unforeseen operating hazards may adversely impact the Company’s oil and gas activities.

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, tsunamis and earthquakes. 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 maintains 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.

The Company’s reserve information represents estimates that may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of the Company’s reserves.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the Company’s control. 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

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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.

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 2004 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 that 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.

The Company has less control over its foreign investments than domestic investments and turmoil in foreign countries may affect the Company’s foreign investments.

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.

Private ownership of oil and gas reserves under oil and gas leases in the United States differs distinctly from the Company’s 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.

Almost all of the Company’s proven reserves are located offshore of the Republic of Gabon. As of December 31, 2004, the Company carried a gross investment of approximately $38.0 million on the Company’s balance sheet associated with the Etame Block offshore Gabon ($26.0 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 Company’s operations or cash flows.

Taxes payable to the government of Gabon are expected to materially increase.

Under the production sharing contract with respect to the Company’s operations in Gabon, the Company is entitled to recover its share of past exploration and development costs and ongoing production costs. Oil retained and sold by the Company to repay exploration, development and production costs is referred to as “cost oil.” At such time as past exploration and development costs are fully recovered, the Company receives cost oil only for ongoing operating and production costs. Since the cost account became fully recovered during the middle of the fourth quarter of 2004, and no further major exploration or development costs are anticipated until the middle of

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2005, commencing in the middle of the fourth quarter and continuing until major exploration and development costs are incurred, cost oil will only consist of operating and production costs. Operating and production costs averaged approximately $6.74 per barrel in 2004. The remaining oil after deducting royalties and cost oil is deemed “profit oil.” The Company pays taxes in Gabon in the form of profit oil, and with the profit oil component increasing after the exploration and development costs are recovered, taxes in Gabon will increase accordingly.

Competitive industry conditions may negatively affect the Company’s ability to conduct operations.

The Company operates in the highly competitive areas of oil exploration, development and production. The Company competes for the acquisition of exploration and production rights in oil and gas properties from foreign governments and from other oil and gas companies. These properties include exploration prospects as well as properties with proved reserves. Factors that affect the Company’s ability to compete in the marketplace include:

• the Company’s access to the capital necessary to drill wells and acquire properties;

• the Company’s ability to acquire and analyze seismic, geological and other information relating to a property;

• the Company’s ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;

• the location of, and the Company’s ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production; and

• the standards the Company establishes for the minimum projected return on an investment of the Company’s capital.

The Company’s competitors include major integrated oil companies and substantial independent energy companies, many of which possess greater financial, technological, personnel and other resources than the Company does. The Company’s competitors may use superior technology which the Company may be unable to afford or which would require costly investment by the Company in order to compete.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

The laws and regulations of Texas, the United States and Gabon regulate the Company’s business. The Company’s 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. 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.

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 and could have a significant impact on the Company’s operating costs, as wells as the oil and gas industry in general. In addition, the loan agreement dated April 19, 2002 between one of the Company’s subsidiaries and the International Finance Corporation requires the Company to comply with specified environmental guidelines. These guidelines set maximum air emission levels and liquid effluent amounts, impose requirements for proper onshore disposal of all solid and hazardous wastes, and require compliance with other similar environmental guidelines. In addition, the Company is required to utilize environmental best practices for drilling activities and produced water and chemical management, prepare emergency response and oil spill response plans, and implement monitoring and Reporting procedures. While the Company believes that it is currently in compliance with environmental laws and regulations applicable to the Company’s operations in Gabon and the U.S., including those required by the International Finance Corporation, 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.

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If the Company’s assumptions underlying accruals for abandonment costs are too low, the Company could be required to expend greater amounts than expected.

Almost all of the Company’s producing properties are located offshore. The costs to abandon offshore wells may be substantial. For financial accounting purposes, the Company adopted 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 1818 Fund, through its ownership of 65% of the voting power and all of the Preferred Stock of the Company, is able to control all matters submitted to a vote of stockholders and is able to appoint a majority of the board of directors. At least one director appointed by the holders of Preferred Stock must approve nearly all material transactions considered by the board of directors.

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 a loan from the 1818 Fund, 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. 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.

The 1818 Fund II, which owns Common and Preferred Stock representing approximately 65% of the Company’s voting power, has advised the Company that it is in the process of liquidation, and plans to sell the Common Stock beneficially owned by it, which will result in a change of control of the Company.

The 1818 Fund has advised the Company that the 1818 Fund is in the process of gradually liquidating the remaining positions in its portfolio and that, as part of that process, the 1818 Fund plans to sell its equity interest in the Company. The 1818 Fund owns Common Stock, Preferred Stock convertible into Common Stock and warrants to purchase Common Stock representing approximately 65% of the Company’s outstanding Common Stock on a fully diluted basis. The Preferred Stock votes on an as converted basis with the Common Stock. As a

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result, the 1818 Fund II can control all matters submitted to a vote of stockholders. In addition, so long as the Preferred Stock is outstanding, the holder of Preferred Stock has the right to elect three directors to the Company’s board of directors.

If the 1818 Fund were to sell a substantial portion of its Common Stock, it would cease to be able to control the vote on matters submitted to shareholders, and if were to convert all of its Preferred Stock, it would cease to have the right to appoint persons to the Company’s board of directors. Substantial sales of Common Stock by the 1818 Fund to a person or group of related persons could result in the purchaser acquiring sufficient shares of Common Stock to control or materially influence the Company’s business.

The Company relies on its senior management team and the loss of a single member could adversely affect its operations.

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 the Company’s employees.

The Company’s reliance on a single purchaser of its Gabon production could have a material adverse effect on the Company’s results of operations.

The Company sells all of its crude oil production in Gabon to Shell Western Supply and Trading, Limited. The loss of Shell oil as a purchaser of the Company’s Gabon production could force the shut in of the Company’s Gabon production until the purchaser is replaced, and could have a material adverse effect on the Company’s results of operations.

Item 2. Properties

Gabon

VAALCO has an interest in a 1,186 square mile 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., which originally provided for two three-year terms, which commenced in July 1995. The block contains 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 satisfied the first three year term obligations with the drilling of the Etame 1V discovery well 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, agreeing to drill two additional exploration wells and to perform a 3-D seismic reprocessing. The Etame 2V exploration well was drilled in January 1999 followed by the Etame 3V well in February 2001. In June 2001, drilling of the Etame 4V delineation well was completed leading to the declaration of the Etame field as being a commercial oil deposit.

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 agreed to drill two additional exploration wells during the initial three-year term which were drilled in 2004. The Company elected to enter into the follow on two-year term which expires July 2006. During this term the consortium is required to spend a minimum of $5.0 million on exploration activities, ($1.5 million net to the Company). The consortium paid a $1.0 million signing bonus ($0.3 million net to the Company) associated with the five-year extension.

The Etame consortium approved a budget to develop the Etame field in 2001. 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, (through 2021), to permit the field to be developed and produced.

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The Etame field has been developed in two phases. The Phase 1 development consisted of completing three subsea wells connected to a Floating Production, Storage and Offloading vessel (“FPSO”) at a cost of approximately $57.3 million ($17.4 million net to the Company). On September 8, 2002, the Etame field commenced production at an average rate of approximately 14,500 BOPD.

The Phase 2 Etame field development plan was submitted to the Gabon government for approval in October 2003. The Company drilled one new development well (the (Etame-5H well) in the first half of 2004. A second development well will be drilled during 2005. The cost of adding the Etame 5H well was $34.5 million ($10.5 million net to the Company) and included laying two new flowlines and umbilicals from the well site to the FPSO onsite in the Etame field. The extra flowline and umbilical were laid with the Etame 5H well to eliminate the need to mobilize lay vessel equipment when the second development well is drilled. The budget for the second Phase 2 development well, the Etame 6H well, is approximately $19.0 million ($5.8 million net to the Company). The Company has recently accepted a proposal from a drilling contractor to lease a semi-submersible rig to drill the Etame 6H well late in the second quarter of 2005.

The Company has sold a total of 12.4 million gross barrels (3.0 million net barrels) since field startup through December 31, 2004. During 2004 the Etame field produced approximately 6.3 million gross barrels (1.5 million net barrels). Production continues at rates of between 18,500 and 19,000 BOPD as of the date of this filing.

Recent Gabon Exploration Activities

During 2003, the Company completed the processing of seismic data acquired in late 2002, and identified several exploration prospect locations near the Etame field. The Company drilled the exploration well the Ebouri No. 1 well to total depth in January 2004. The well resulted in a new Gamba sand discovery logging 46 feet of oil pay in a 55 foot 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 drilled a second exploration well on the Avouma prospect in August of 2004. This resulted in another discovery that tested 6,600 BOPD from twenty feet of perforations in the Gamba sandstone. The Gamba sand was approximately 40 feet thick and contained oil pay throughout the sand.

The Company has received approval from the Gabon government that it deems the Avouma/South Tchibala discoveries commercial and ready for development. The Company acquired new seismic data over the Ebouri discovery in December of 2004. Upon completion of a review of the processed data, the Company anticipates filing for a development permit for the Ebouri discovery.

The Company plans to drill an exploratory well after the Etame 6H development well is drilled in the second quarter. The prospect is in the vicinity of the Avouma discovery. The Company plans to use cash on hand and cash flows from operations to fund the planned exploration well and Etame 6H development well, and for the Avouma/South Tchibala development during 2005.

At December 31, 2004, VAALCO owned a 30.35% interest in the production-sharing contract covering the Etame Block, and 28.1% of the development area surrounding the Etame field development. The development area was subject to a 7.5% back-in by the Government of Gabon, which occurred upon field startup.

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 2004 the wells produced approximately 2,900 bbls of oil and 22 million cubic feet of gas net to the Company. No capital expenditures are anticipated in 2005 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 2004 and 2003 are shown below. The production figures exclude discontinued operations:

Company Owned Production

	Year Ended December 31,
	2004			2003
	BOE	Bbl	Mcf	BOE		Bbl		Mcf
Average Daily Production (Oil in BOPD, gas in MCFD)	4,036	4,026	59		3,393		3,370		139
Average Sales Price ($/unit)	38.36	38.37	5.63	$	28.54	$	28.54	$	5.50
Average Production Cost ($/unit)	6.74	6.74	1.12	$	7.24	$	7.24	$	1.21

RESERVE INFORMATION

A reserve report as of December 31, 2004 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 and in Texas.

	As of December 31,
	2004		2003
Crude Oil
Proved Developed Reserves (MBbls)		4,738		6,492	(1)
Proved Undeveloped Reserves (MBbls)		3,996		2,519
Total Proved Reserves (MBbls)		8,734		9,011
Natural Gas
Proved Developed Reserves (MMcf)		54		140
Proved Undeveloped Reserves (MMcf)		—		—
Total Proved Reserves (MMcf)		54		140
Standardized measure of discounted future net cash flows at 10% (in thousands)	$	123,321	$	101,610

(1) – Includes 351 Mbbls in the Philippines which has been sold

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The following tables set forth the net proved reserves of VAALCO Energy, Inc. as of December 31, 2004 and 2003, and the changes therein during the periods then ended.

	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2003	5,453		77
Production	(1,266	)	(51	)
Revisions	4,824		114
BALANCE AT DECEMBER 31, 2003	9,011		140
Production	(1,469	)	(22	)
Revisions	96		(64	)
Additions	1,447		—
Sale of reserves in place	(351	)	—
BALANCE AT DECEMBER 31, 2004	8,734		54
	Oil (MBbls)		Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at December 31, 2003	6,492		140
Balance at December 31, 2004	4,738		54

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

The Company maintains a policy of not booking proved reserves on discoveries until such time as a development plan has been prepared for the discovery. Additionally, the development plan is required to have the approval of the Company’s partners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves.

In 2004 the Company made two discoveries offshore Gabon, the Ebouri and the Avouma discoveries. The Avouma discovery was an extension of a previous discovery known as the South Tchibala discovery. The Company has prepared a detailed development plan for the South Tchibala/Avouma discovery, which has been submitted to and approved by the Company’s partners in the discovery. The Company has received approval from the Government of Gabon to declare the discovery commercial. Accordingly, the Company has booked as additions to proven reserves 1,447,000 barrels representing a portion of the reserves for the South Tchibala/Avouma field offshore Gabon in 2004.

For the Ebouri discovery, because of the decision to participate in a seismic shoot over Ebouri and other areas in the northern part of the Etame Block, the Company did not request any approvals for the development of the Ebouri discovery from its partners or the government, pending the results of the seismic. Therefore, the Company has not booked any reserves for the Ebouri discovery at December 31, 2004. The Company also has not booked any reserves associated with the North Tchibala discovery on the Etame block.

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. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved

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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 for Gabon are recoverable under a service contract and the reserves in place remain the property of the Gabon 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. In Gabon, the price was $40.28 per barrel representing a $0.19 discount to the spot price of Dated Brent Crude at December 31, 2004. In the Texas the price was $42.76 per barrel of oil and $5.69 per Mcf of gas. See Financial Statements and Supplementary Data for certain additional information concerning the proved reserves of the Company.

Drilling History

The Company participated in two exploration wells and one development well during 2004 in Gabon. No exploration wells or development wells were drilled in 2003.

	United States				International
	Gross		Net		Gross		Net
Wells Drilled	2004	2003	2004	2003	2004	2003	2004	2003
Exploration Wells
Productive	0.0	0.0	0.0	0.00	2.0	0.0	0.61	0.0
Dry	0.0	0.0	0.0	0.00	0.0	0.0	0.00	0.0
Production Wells
Productive	0.0	0.0	0.0	0.0	1.0	0.0	0.28	0.0
Dry	0.0	0.0	0.0	0.0	0.0	0.0	0.00	0.0
Total Wells	0.0	0.0	0.0	0.00	3.0	0.0	0.89	0.0

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, 2004:

	United States		International
	Gross	Net (1)	Gross	Net (1)
	(In thousands except wells)
Developed acreage	13.9	1.4	12.2	3.4
Undeveloped acreage	0.0	0.0	746.8	226.7
Productive gas wells	2	0.4	0	0
Productive oil wells	11	1.8	4	1.1

(1) Net acreage and net productive wells are based upon the Company’s working interest in the properties.

Office Space

The Company leases its offices in Houston, Texas (approximately 8,000 square feet) and in Port Gentil, Gabon (approximately 6,000 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 American Stock Exchange. 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, 2004 there were approximately 181 holders of record of the Company’s Common Stock.

Period	High		Low
2003:
First Quarter	$	1.50	$	1.00
Second Quarter		1.35		0.96
Third Quarter		1.21		0.95
Fourth Quarter		1.40		1.02
2004:
First Quarter	$	2.25	$	1.55
Second Quarter		2.01		1.79
Third Quarter		5.51		1.88
Fourth Quarter		5.39		3.83
2005:
First Quarter (through March 1, 2005)	$	5.09	$	3.63

On March 1, 2005 the last reported sale price of the Common Stock on the American Stock Exchange was $4.92 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 Phase 1 development of the field occurred in 2002 and consisted of completing three wells producing into an FPSO. Phase 2 development commenced in 2004 with two wells planned, one of which has already been drilled and completed. The second well of the Phase 2 development will be drilled during the middle of 2005. After completion of the first Phase 2 well, the Etame field produced at approximately 19,000 to 20,000 BOPD.

The Company’s results of operations are also affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of operating costs in Gabon are denominated in local currencies. An

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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 and 2004.

A substantial portion of the Company’s oil production is located offshore of Gabon. In Gabon, the Company produces into a 1.1 million barrel FPSO and sells cargos to Shell Western Supply and Trading, Limited at spot market prices.

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 S-X 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 is 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.

OIL AND GAS EXPLORATION COSTS

FASB Statement No. 19—The Company uses the “successful efforts” method of accounting for its oil and gas exploration and development costs. All expenditures related to exploration, with the exception of costs of drilling exploratory wells are charged to expense as incurred. The costs of exploratory wells are capitalized on the balance sheet pending determination of whether commercially producible oil and gas reserves have been discovered. If the determination is made that a well did not encounter potentially economic oil and gas quantities, the well costs are charged to expense. These determinations are re-evaluated quarterly.

For capitalized exploration drilling costs, if it is determined that a development plan is feasible, and the development plan is approved by the Gabon government, costs associated with the exploratory wells will be transferred along with the costs spent on the development to “wells, platforms and other production facilities” at

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the time of first production. The costs will subsequently be amortized on a unit of production based method over the life of the reserves as they are produced. In the event it were determined that the discoveries are not commercial, the costs of the exploratory wells would be expensed.

At September 30, 2004, the Company had $6.5 million being carried on the balance sheet as work in progress associated with exploratory wells for the Company’s share of the costs of the Ebouri No. 1 well and the Avouma No. 1 well. Both of these wells resulted in discoveries of oil and gas.

For offshore exploratory discoveries, it is not unusual to have exploratory well costs remain suspended while additional appraisal and engineering work on the potential oil and gas field is performed and regulatory and government approvals are sought. In Gabon, the government must approve the commerciality of the reserves, assign a development area and approve a formal development plan prior to a field being developed. In February 2005, the Company received approval to declare the reserves commercial from the Gabon government. The Company subsequently filed its request for the assignment of a development area. The Company has prepared a development plan which the Etame consortium has approved. The plan will be submitted to the government upon the assignment of the development area. For Ebouri the Company acquired new seismic over the discovery in January 2005 and intends to file for a development area and submit a development plan after the seismic is processes later in 2005.

A discussion is currently ongoing within the oil industry regarding capitalization of costs of drilling exploratory wells. This issue was raised to the Emerging Issues Task Force (EITF). Paragraph 19 of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment, and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed. Questions have arisen in practice about the application of this guidance due to changes in oil- and gas-exploration processes and lifecycles. The issue is whether there are circumstances that would permit the continued capitalization of exploratory well costs if reserves cannot be classified as proved within one year following the completion of drilling other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. The issue was discussed at the September 29–30, 2004 EITF meeting, and the Task Force requested that the FASB consider an amendment to its Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, to address this issue.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2004 was $19.8 million, as compared to $22.7 million in 2003. Net funds provided by operations in 2004 included net income of $23.0 million, non-cash depreciation, depletion and amortization of $4.8 million and working capital decreases net of taxes payable of $8.4 million, primarily associated with Gabon operations. Current liabilities of discontinued operations include income taxes payable of $1.8 million associated with branch profit remittance taxes on discontinued operations in the Philippines. A non-cash add back of $3.1 million was associated with minority interests in Gabon.

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 2004, and non-cash add back of $1.3 million of minority interest expense.

Net cash used in investing activities for 2004 was $15.7 million, as compared to net cash used in investing activities of $1.9 million in 2003. In 2004, the Company invested $9.7 million to fund its share of the Phase 2

21

development of the Etame Block, and $4.6 million to drill the Ebouri and Avouma exploration wells. The Ebouri and Avouma wells were subsequently suspended as discovery wells in 2004. An additional amount of $1.2 million was used for discontinued operations transaction expense in 2004. In 2003, the Company added to its investment in Gabon by participating in the Ebouri exploration well, which was classified as work in progress at year end 2003 and finished drilling in 2004.

In 2004, net cash used by financing activities was $2.5 million, consisting of $3.3 million in debt repayment and $0.6 million in distributions to a minority interest holder, offset by $0.3 million proceeds from the issuance of common stock and $1.0 million release of funds in escrow. 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 release to the Company of $7.9 million of funds in escrow.

Capital Expenditures

During 2004 the Company spent $9.7 million on activities associated with the Etame Phase 2 development program, and $4.6 million on the Ebouri and Avouma exploration wells. 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 2005, the Company anticipates participating in additional exploration and development opportunities on the Etame Block, which will be funded by cash on hand and cash flow from operations. Total Phase 2 development and exploration capital expenditures for 2005 are budgeted to be approximately $5.7 million net to the Company. An exploration well is planned which is budgeted for $2.4 million net to the Company. The Company also anticipates commencing the development of Avouma and has budgeted $5.2 million net to the Company for these activities.

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, 2004 the Company had cash balances of $27.5 million. The Company believes that this cash balance combined with cash flow from operations will be sufficient to fund the Company’s 2005 capital expenditure budget of approximately $13.3 million, required debt repayments of $2.3 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, 2004 the Company repaid $3.25 million of the loan as called for under the facility repayment schedule.

On September 8, 2002, the company commenced production from the Etame field offshore Gabon. Through 2004 total field production sold was 12.4 million bbls (3.0 million bbls net to the Company).

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. While the loss of Shell Western Trading and Supply, Limited 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 2004, the Company had net production of 2,900 bbls of oil and 22 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.

22

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, 2004 (in thousands):

Payment Period

$thousands	2005	2006	2007	Thereafter
Long term debt	2,250	1,250	250	—
Interest on long term debt	1181	51	4	—
Operating leases	19,6912	1,964	191	12

1. Interest is based on rates and principal payments in effect at 12/31/2004

2. The Company is Guarantor of a lease for an FPSO utilized in Gabon, which represents $16,781,000 of the 2005 obligations. The Company can cancel the lease anytime with 12 month prior notice. Approximately 72% of the payment is co-guaranteed by the Company’s partners in Gabon.

RESULTS OF OPERATIONS

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

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

Revenues

Total oil and gas sales for 2004 were $56.5 million as compared to $35.5 million for 2003. In 2004, the Company sold 1,467,000 net barrels at an average price of $38.36 per barrel from the Etame field in Gabon. Revenues from Texas in 2004 were approximately $0.25 million. Revenues in 2003 were predominately from production from the Etame field, where the Company sold 1,227,000 net bbls at an average price of $28.54 per barrel. Revenues from Texas in 2003 were approximately $0.4 million. The increased oil volumes from Etame in 2004 versus 2003 were due to the addition of the Etame 5H Phase 2 development well completed in August 2004.

Operating Costs and Expenses

Production expenses for 2004 were $10.0 million as compared to $9.0 million for 2003. In 2004 operating expenses increase for the Etame field due to the devaluation of the dollar versus the Euro. Personnel costs for manning the FPSO are Euro based.

Exploration costs for 2004 were $0.3 million as compared to $2.1 million for 2003. 2004 exploration expenditure were associated with seismic processing and interpretation activities in Gabon. Exploration costs in 2003 included 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.

Depreciation, depletion and amortization of properties for 2004 and 2003 were $4.7 million and $5.8 million respectively. Depletion in 2004 was lower at the Etame field due to the increase in reserves booked at year end 2003. Depletion in 2003 included Etame production accounting for $5.6 million of the year’s total. The balance was associated with the Texas wells, ($0.2 million).

General and administrative expenses for 2004 were $1.3 million as compared to $2.0 million for 2003. Expenses were lower in 2004 than in 2003 as the Company received reimbursement for general and administrative expenses associated with the Phase 2 development project and the Ebouri and Avouma exploration wells.

23

Operating Income

Operating income for 2004 was $40.3 million as compared to a $16.6 million income for 2003. Higher oil sales volumes and prices in Gabon were primary reason for the increase.

Other Income (Expense)

Interest income for 2004 was $0.3 million compared to $0.1 million in 2003. Both the 2004 and 2003 amounts represent interest earned and accrued on cash balances and funds in escrow.

Interest expense of $0.5 million was recorded in 2004 associated with the financings for the development of the Etame field as compared to $2.6 million in 2003. 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 2004, the Company incurred $12.0 million of foreign income taxes associated with the Etame field production, which were paid in Gabon. This compared to $5.5 million paid in Gabon in 2003.

Minority Interest

A provision for minority interest in the Gabon subsidiary was made for $3.1 million and $1.3 million in 2004 and 2003 respectively.

Loss from Discontinued Operations

Loss from discontinued operations associated with the sale of the Company’s former Philippines assets was $2.1 million in 2004, consisting of $1.8 million in branch profit remittance income taxes and $0.3 million in general and administrative and interest costs associated with closing down the branch offices. Loss from discontinued operations was $35,000 in 2003.

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 for 2004 was $22.9 million as compared to a net income of $8.9 million in 2003. The impact of higher oil sales volumes in Gabon from the addition of the Etame 5H development well and higher oil and gas prices was responsible for the increase in net income in 2004.

NEW ACCOUNTING PRONOUNCEMENTS

Share based payment—In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change to prior guidance for share-based payments for transactions with non employees.

SFAS No. 123(R) eliminates the intrinsic value measurement objective in APB Opinion 25 and generally requires the Company to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The standard requires grant date fair value to be estimated using either an option-pricing model which is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The standard also requires the Company to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur.

24

The Company is required to apply SFAS No. 123(R) to all awards granted, modified or settled in our first reporting period under U.S. GAAP after June 15, 2005. The Company is also required to use either the “modified prospective method” or the “modified retrospective method.” Under the modified prospective method, the Company must recognize compensation cost for all awards granted after the Company adopts the standard and for the unvested portion of previously granted awards that are outstanding on that date.

Under the modified retrospective method, the Company must restate our previously issued financial statements to recognize the amounts the Company previously calculated and reported on a pro forma basis, as if the prior standard had been adopted. See Note 2 – Stock Based Compensation.

Under both methods, the Company is permitted to use either a straight line or an accelerated method to amortize the cost as an expense for awards with graded vesting. The standard permits and encourages early adoption.

The Company has commenced the analysis of the impact of SFAS 123(R), but has not yet decided: (1) whether the Company will elect to adopt early, (2) if the Company elects to adopt early, then at what date the Company would do so, (3) whether the Company will use the modified prospective method or elect to use the modified retrospective method, and (4) whether the Company will elect to use straight line amortization or an accelerated method. Additionally, the Company cannot predict with reasonable certainty the number of options that will be unvested and outstanding upon adoption.

Accordingly, the Company cannot currently quantify with precision the effect that this standard would have on our financial position or results of operations in the future, except that the Company probably will recognize a greater expense for any awards that the Company may grant in the future than the Company would using the current guidance. If the Company were to adopt SFAS No. 123(R) using the modified retrospective method, our net income would have been $959 less than reported in the year ended December 31, 2004.

SFAS 151, Inventory Costs—In November 2004, the FASB issued SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, which amends Chapter 4 of ARB No. 43 that deals with inventory pricing. The Statement clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs, and spoilage. Under previous guidance, paragraph 5 of ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. This Statement eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. This Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, although earlier application is permitted for fiscal years beginning after the date of issuance of this Statement. Retroactive application is not permitted. Management is analyzing the requirements of this new Statement and believes that its adoption will not have any significant impact on the Company’s financial position, results of operations or cash flows.

SFAS 153, Exchange of Non-Monetary Assets—In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB No. 29. This Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This Statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date this Statement is issued. Retroactive application is not permitted. Management is analyzing the requirements of this new Statement and believes that its adoption will not have any significant impact on the Company’s financial position, results of operations or cash flows.

FASB Statement No. 19—A discussion is currently ongoing within the oil industry regarding capitalization of costs of drilling exploratory wells. This issue was raised to the Emerging Issues Task Force (EITF). Paragraph 19 of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, requires

25

costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment, and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed. Questions have arisen in practice about the application of this guidance due to changes in oil- and gas-exploration processes and lifecycles. The issue is whether there are circumstances that would permit the continued capitalization of exploratory well costs if reserves cannot be classified as proved within one year following the completion of drilling other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. The issue was discussed at the September 29–30, 2004 EITF meeting, and the Task Force requested that the FASB consider an amendment to its Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, to address this issue.

Item 7. Financial Statements and Supplementary Data

26

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated balance sheets of VAALCO Energy, Inc. and its subsidiaries (“VAALCO”) as of December 31, 2004 and 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, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2004 and 2003, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2004 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 4, 2005

27

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

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

	December 31, 2004			December 31, 2003
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	27,574		$	22,995
Funds in escrow		1,152			2,144
Receivables:
Trade		5,258			58
Accounts with partners		3,138			—
Other		209			449
Crude oil inventory		724			586
Materials and supplies		314			271
Prepayments and other		1,160			533
Current assets of discontinued operations		78			491
Total current assets		39,607			27,527
PROPERTY AND EQUIPMENT-SUCCESSFUL EFFORTS METHOD:
Wells, platforms and other production facilities		32,960			23,393
Work in progress		6,508			1,905
Equipment and other		847			593
		40,315			25,891
Accumulated depreciation, depletion and amortization		(13,966	)		(9,282	)
Net property and equipment		26,349			16,609
OTHER ASSETS:
Deferred tax asset		1,290			920
Funds in escrow		807			801
Long term assets of discontinued operations		—			14
Other long-term assets		319			496
TOTAL	$	68,372		$	46,367
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	9,280		$	6,019
Accounts with partners		—			3,015
Current portion of long term debt		2,250			4,000
Current liabilities of discontinued operations		1,927			1,364
Income taxes payable		140			45
Total current liabilities		13,597			14,443
LONG TERM LIABILITIES OF DISCONTINUED OPERATIONS		—			1,538
LONG TERM DEBT		1,500			3,000
ASSET RETIREMENT OBLIGATIONS		1,330			1,165
Total liabilities		16,427			20,146
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES		4,137			1,667
STOCKHOLDERS’ EQUITY:
Convertible preferred stock, $25 par value, 500,000 shares authorized; 6667 and 10,000 shares issued and outstanding at December 31, 2004 and December 31, 2003, respectively		167			250
Common stock, $0.10 par value, 100,000,000 authorized shares 33,244,244 and 21,531,829 shares issued with 418,294 and 151,769 in treasury at December 31, 2004 and December 31, 2003, respectively		3,324			2,153
Additional paid-in capital		45,612			46,358
Accumulated deficit		(1,094	)		(24,032	)
Less treasury stock, at cost		(201	)		(175	)
Total stockholders’ equity		47,808			24,554
TOTAL	$	68,372		$	46,367

See notes to consolidated financial statements.

28

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

(in thousands of dollars, except per share amounts)

	Years ended December 31,
	2004			2003
REVENUES:
Oil and gas sales	$	56,502		$	35,481
OPERATING COSTS AND EXPENSES:
Production expenses		9,958			8,969
Exploration expense		267			2,096
Depreciation, depletion and amortization		4,749			5,785
General and administrative expenses		1,260			2,007
Total operating costs and expenses		16,234			18,857
OPERATING INCOME		40,268			16,624
OTHER INCOME (EXPENSE):
Interest income		265			80
Interest expense		(485	)		(2,630	)
Other, net		22			—
Total other expense		(198	)		(2,550	)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES, MINORITY INTEREST AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		40,070			14,074
Income tax expense		11,972			5,514
INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTEREST AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		28,098			8,560
Minority interest in earnings of subsidiaries		(3,069	)		(1,306	)
Income from continuing operations		25,029			7,254
Discontinued operations: (Note 10)
Loss from discontinued operations before income taxes (including loss on disposal of $125 in 2004)		(327	)		(244	)
Income taxes		(1,764	)		209
Loss on discontinued operations		(2,091	)		(35	)
Cumulative effect of accounting change		—			1,717
NET INCOME	$	22,938		$	8,936
BASIC INCOME PER COMMON SHARE FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	$	0.94		$	0.34
LOSS FROM DISCONTINUED OPERATIONS		(0.08	)		—
CUMULATIVE EFFECT OF ACCOUNTING CHANGE		—			0.08
BASIC INCOME PER COMMON SHARE	$	0.86		$	0.42
DILUTED INCOME PER COMMON SHARE FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	$	0.43		$	0.13
LOSS FROM DISCONTINUED OPERATIONS		(0.04	)		—
CUMULATIVE EFFECT OF ACCOUNTING CHANGE		—			0.03
DILUTED INCOME COMMON PER SHARE	$	0.39		$	0.16
BASIC WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		26,604			21,237
DILUTED WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		58,157			55,355

See notes to consolidated financial statements.

29

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2004 AND 2003

(in thousands of dollars, except share data)

	Preferred Stock					Common Stock			Additional Paid-in Capital			Subscription Receivable			Accumulated Deficit			Treasury Stock			Total Stockholders’ Equity
	Shares		Amount			Shares	Amount
Balance at January 1, 2003	10,000		$	250		20,836,350	$	2,084	$	46,413		$	(569	)	$	(32,968	)	$	(12	)	$	15,198
Proceeds from stock issuance	—			—		695,479		69		514			—			—			—			583
Cancellation of subscription Receivable	—			—		—		—		(569	)		569			—			—			—
Purchase of treasury shares	—			—		—		—		—			—			—			(163	)		(163	)
Net Income	—			—		—		—		—			—			8,936			—			8,936
Balance at December 31, 2003	10,000		$	250		21,531,829	$	2,153	$	46,358		$	—		$	(24,032	)	$	(175	)	$	24,554
Conversion of Preferred Shares	(3333	)		(83	)	9,165,750		916		(833	)		—			—			—			—
Proceeds from stock issuance	—			—		2,546,665		255		87			—			—			—			342
Purchase of treasury shares	—			—		—		—		—			—			—			(26	)		(26	)
Net Income	—			—		—		—		—			—			22,938			—			22,938
Balance at December 31, 2004	6,667		$	167		33,244,244	$	3,324	$	45,612		$	—		$	(1,094	)	$	(201	)	$	47,808

See notes to consolidated financial statements.

30

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(in thousands of dollars)

	Year Ended December 31,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	22,938		$	8,936
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		4,749			5,876
Non cash compensation expense		—			443
Amortization of debt discount		—			1,624
Cumulative effect of accounting change		—			(1,717	)
Loss on sale of assets		191
Exploration expense		267			2,096
Minority interest in earnings of subsidiaries		3,070			1,306
Change in assets and liabilities that provided (used) cash:
Funds in escrow		(6	)		(4	)
Trade receivables		(4,786	)		3,213
Other receivables		241			1,198
Materials and supplies		(364	)		184
Crude Oil Inventory		(138	)		(568	)
Prepayments and other		(632	)		(160	)
Accounts payable and accrued liabilities		2,059			(3,081	)
Accounts with partners		(6,251	)		3,779
Income taxes payable		1,859			—
Provision for deferred income taxes		(410	)		(497	)
Net cash provided by operating activities		22,787			22,628
CASH FLOWS FROM INVESTING ACTIVITIES:
Discontinued operations transaction expense		(1,187	)		—
Exploration expense		(267	)		(327	)
Additions to property and equipment		(14,324	)		(1,877	)
Other—net		113			286
Net cash used in investing activities		(15,665	)		(1,918	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock		342			141
Distribution to minority interest		(600	)		(320	)
Funds in escrow		992			7,903
Debt repayment		(3,250	)		(13,000	)
Purchase of treasury shares		(27	)		(163	)
Net used in financing activities		(2,543	)		(5,439	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		4,579			15,271
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		22,995			7,724
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	27,574		$	22,995
SUPPLEMENTAL DISCLOSURE OF CASH FLOWS INFORMATION:
Interest Paid	$	325		$	1,140
Income Taxes Paid	$	12,247		$	5,545

See notes to consolidated financial statements.

31

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2004 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 Gabon. Domestically, the Company has interests in the Texas Gulf Coast area. In Gabon VAALCO serves as the operator for a group of companies which own the working interest in the production sharing contract, collectively referred to as a consortium.

VAALCO’s subsidiaries include VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Energy (USA), Inc., Alcorn (Philippines) Inc., Alcorn (Production) Philippines Inc., Altisima Energy, 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’s 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 interest and the current portion of the IFC loan ($1.1 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. Inventory 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.

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

32

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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:

Office and miscellaneous equipment	3-5 years
Leasehold improvements	8-12 years

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 2004 and $53 in 2003.

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 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 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

33

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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):

Years Ended December 31,	2004		2003
Net income as reported		22,938	$	8,936
Deduct: Total stock based employee compensation expense		959		572
Proforma net income	$	21,979	$	8,364
Basic earnings per share
As reported		0.86	$	0.42
Pro forma		0.83	$	0.39
Diluted earnings per share
As reported		0.39	$	0.16
Pro forma		0.38	$	0.15

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 volatility ranging from 38% to 62%, risk-free interest rate of 5.5%, expected life of options of 3 to 10 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, funds in escrow, 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 in Gabon and in Texas.

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 99% of total revenues in 2004 and 2003 respectively. While the loss of this 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.

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.

34

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 2003 have been reclassified to conform to the 2003 presentation.

3. NEW ACCOUNTING PRONOUNCEMENTS

Share based payment—In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change to prior guidance for share-based payments for transactions with non employees.

SFAS No. 123(R) eliminates the intrinsic value measurement objective in APB Opinion 25 and generally requires the Company to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The standard requires grant date fair value to be estimated using either an option-pricing model which is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The standard also requires the Company to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur.

The Company is required to apply SFAS No. 123(R) to all awards granted, modified or settled in our first reporting period under U.S. GAAP after June 15, 2005. The Company is also required to use either the “modified prospective method” or the “modified retrospective method.” Under the modified prospective method, the Company must recognize compensation cost for all awards granted after the Company adopts the standard and for the unvested portion of previously granted awards that are outstanding on that date.

Under the modified retrospective method, the Company would restate our previously issued financial statements to recognize the amounts the Company previously calculated and reported on a pro forma basis, as if the prior standard had been adopted. See Note 2 – Stock Based Compensation.

Under both methods, the Company is permitted to use either a straight line or an accelerated method to amortize the cost as an expense for awards with graded vesting. The standard permits and encourages early adoption.

The Company has commenced the analysis of the impact of SFAS 123(R), but has not yet decided: (1) whether the Company will elect to adopt early, (2) if the Company elects to adopt early, then at what date the Company would do so, (3) whether the Company will use the modified prospective method or elect to use the modified retrospective method, and (4) whether the Company will elect to use straight line amortization or an accelerated method. Additionally, the Company cannot predict with reasonable certainty the number of options that will be unvested and outstanding upon adoption.

Accordingly, the Company cannot currently quantify with precision the effect that this standard would have on our financial position or results of operations in the future, except that the Company probably will recognize a greater expense for any awards that the Company may grant in the future than the Company would using the current guidance. If the Company were to adopt SFAS No. 123(R) using the modified retrospective method, our net income would have been $959 less than reported in the year ended December 31, 2004.

35

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

SFAS 151, Inventory Costs—In November 2004, the FASB issued SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, which amends Chapter 4 of ARB No. 43 that deals with inventory pricing. The Statement clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs, and spoilage. Under previous guidance, paragraph 5 of ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. This Statement eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. This Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, although earlier application is permitted for fiscal years beginning after the date of issuance of this Statement. Retroactive application is not permitted. Management is analyzing the requirements of this new Statement and believes that its adoption will not have any significant impact on the Company’s financial position, results of operations or cash flows.

SFAS 153, Exchange of Non-Monetary Assets—In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB No. 29. This Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This Statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date this Statement is issued. Retroactive application is not permitted. Management is analyzing the requirements of this new Statement and believes that its adoption will not have any significant impact on the Company’s financial position, results of operations or cash flows.

FASB Statement No. 19—The Company uses the “successful efforts” method of accounting for its oil and gas exploration and development costs. All expenditures related to exploration, with the exception of costs of drilling exploratory wells are charged to expense as incurred. The costs of exploratory wells are capitalized on the balance sheet pending determination of whether commercially producible oil and gas reserves have been discovered. If the determination is made that a well did not encounter potentially economic oil and gas quantities, the well costs are charged to expense. These determinations are re-evaluated quarterly.

For capitalized exploration drilling costs, if it is determined that a development plan is feasible, and the development plan is approved by the Gabon government, costs associated with the exploratory wells will be transferred along with the costs spent on the development to “wells, platforms and other production facilities” at the time of first production. The costs will subsequently be amortized on a unit of production based method over the life of the reserves as they are produced. In the event it were determined that the discoveries are not commercial, the costs of the exploratory wells would be expensed.

At December 31, 2004, the Company had $6.5 million being carried on the balance sheet as work in progress associated with exploratory wells for the Company’s share of the costs of the Ebouri No. 1 well and the Avouma No. 1 well. Both of these wells resulted in discoveries of oil and gas.

For offshore exploratory discoveries, it is not unusual to have exploratory well costs remain suspended while additional appraisal and engineering work on the potential oil and gas field is performed and regulatory and government approvals are sought. In Gabon, the government must approve a development area and a formal development plan prior to a field being developed. The Company has received approval in 2005 for a development area on Avouma and is preparing the development plan. For Ebouri the Company acquired new seismic over the discovery in January 2005 and intends to file for a development area and submit a development plan after the seismic is processed later in 2005.

36

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A discussion is currently ongoing within the oil industry regarding capitalization of costs of drilling exploratory wells. This issue was raised to the Emerging Issues Task Force (EITF). Paragraph 19 of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment, and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed. Questions have arisen in practice about the application of this guidance due to changes in oil- and gas-exploration processes and lifecycles. The issue is whether there are circumstances that would permit the continued capitalization of exploratory well costs if reserves cannot be classified as proved within one year following the completion of drilling other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. The issue was discussed at the September 29–30, 2004 EITF meeting, and the Task Force requested that the FASB consider an amendment to its Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, to address this issue.

The table below provides additional information with respect to the Company’s capitalized exploration drilling costs.

	2004			2003
Beginning balance at January 1	$	1,905		$	1,509
Additions to capitalized exploratory drilling costs		4,603			1,905
Capitalized exploratory drilling costs reclassified to property and equipment		—			—
Capitalized exploratory drilling costs expensed		—			(1,509	)
Ending balance at December 31	$	6,508		$	1,905
Number of wells requiring major capital expenditures where additional drilling efforts are not underway or firmly planned for the near future		1	(1)		—
Amount capitalized for wells requiring major capital expenditures where additional drilling efforts are not underway or firmly planned	$	2,597			—

1) Ebouri No. 1 well, see discussion above.

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 in the table below is a summary of the number of shares on an as converted basis assuming cash exercise of all warrants and options as of December 31, 2004 and 2003. Certain options and warrants have cashless exercise features that would alter the number of shares issued if this feature were utilized.

	2004	2003
Common shares issued and outstanding 1	32,825,950	21,380,060
Preferred shares convertible to common stock	18,334,250	27,500,000
Options	4,019,335	4,541,000
Warrants	5,500,000	7,500,000
Total shares on an as converted, as exercised basis	60,679,535	60,921,060

1. Net of treasury shares

37

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 2003.

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 in 2003.

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 2003 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 2003 and 2004, the technical representatives exercised 50,000 and 370,000 options, respectively.

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 a loan for the development of the Etame field. 12,000,000 of the warrants were surrendered back to the Company upon the project completion of the Etame field in 2003. During 2004, 2,000,000 of the warrants were exercised and the remaining 5,500,000 warrants are issued and outstanding as to December 31, 2004.

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, 2004.

On December 16, 2003 the board of directors awarded 3,646,000 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 eighteen months from the date of vesting, and vested one third upon issuance, one third on the first anniversary of the issuance date and one third will vest upon the second anniversary date of the issuance. A total of 176,665 of the options were exercised in 2004.

38

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On December 2, 2004 the board of directors awarded 100,000 options to a newly appointed director to purchase common stock at $4.26 per share. The options have a term of ten years and vest on June 2, 2005.

On January 12, 2005 the board of directors awarded 1,396,500 options to a group of officers, employees, consultants and directors to purchase common stock at $3.85 per share. The options have a term of five 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.

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

	Vested Warrants Exercisable		Vested Options Exercisable		Total Shares Under Option		Weighted Average Option Exercise Price
Balance, January 1, 2003	19,500,000		2,825,000		2,825,000		0.66
Issued	—		1,365,328		3,771,000		1.16
Exercised	—		(695,479	)	(695,479	)	0.61
Redeemed in cashless exercise	—		(584,521	)	(584,521	)	0.65
Forfeited	(12,000,000	)	(850,000	)	(850,000	)	0.77
Balance, December 31, 2003	7,500,000		2,060,328		4,466,000		0.56
Vested/Issued	—		1,190,332		100,000		4.26
Exercised	(2,000,000	)	(546,665	)	(546,665	)	0.58
Balance, December 31, 2004	5,500,000		2,703,995		4,019,335		0.78

The following table summarizes information about stock options and warrants outstanding as of December 31, 2004:

Range of Exercise Price	Number Outstanding At 12/31/04	Weighted- Average Remaining Contractual Life	Weighted- Average Exercise Price		Number Exercisable At 12/31/03	Exercisable Weighted- Average Exercise Price
$ 0.30 to 1.00	5,825,000	2.45 years	$	0.49	5,825,000	$	0.49
1.01 to 2.00	3,594,335	2.23 years		1.16	2,378,995		1.15
2.01 to 5.00	100,000	9.92 years		4.26	—		—
$ 0.30 to 5.00	9,519,335	2.44 years	$	0.78	8,203,995	$	0.68

The Company follows SFAS No. 128 – “Earnings per Share,” which establishes the requirements for presenting earnings per share (“EPS”). SFAS No. 128 requires the presentations of “basic” and “diluted” EPS on the face of the income statement.

39

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following schedule is presented as a reconciliation of the numerators and denominators of basic and diluted earnings per share computations.

(In thousands except per share amounts)	For the Year Ended December 31, 2004
	Per-Share Amount			Net Income (Numerator)			Shares (Denominator)
Basic EPS
Net income from continuing operations attributable to common shareholders	$	0.94		$	25,029		26,604
Net loss from discontinued operations attributable to common shareholders		(0.08	)		(2,091	)	26,604
Net income attributable To common Shareholders		0.86			22,938		26,604
Effect of Dilutive Securities
Preferred stock, common stock options and warrants		(0.47	)		—		31,553
Diluted EPS
Net income attributable to common shareholders	$	0.39		$	22,938		58,157
	For the Year Ended December 31, 2003
	Per-Share Amount			Net Income (Numerator)			Shares (Denominator)
Basic EPS
Net income from continuing operations attributable to common shareholders	$	0.34		$	7,254		21,237
Net loss from discontinued operations attributable to common shareholders		0.00			(35	)	21,237
Cumulative effect of change in accounting principle attributable to common shareholders		0.08			1,717		21,237
Net income attributable To common Shareholders		0.42			8,936		21,237
Effect of Dilutive Securities
Common stock options and warrants		(0.26	)		—		34,118
Diluted EPS
Net income attributable to common shareholders	$	0.16		$	8,936		55,355

Diluted Shares consist of the following:

Item	Year Ended December 31, 2004	Year Ended December 31, 2003
Basic weighted average Common Stock issued and outstanding	26,604,299	21,236,658
Preferred Stock convertible to Common Stock	22,942,168	27,500,000
Dilutive Warrants	5,831,837	5,888,504
Dilutive Options	2,779,075	730,352
Total Diluted Shares	58,157,379	55,355,514

40

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. INCOME TAXES

The Company and its domestic subsidiaries file a consolidated United States income tax return. Certain subsidiaries’ operations are also subject to foreign income taxes.

Provision for income taxes consists of the following:

(In thousands)	Year Ended December 31,
	2004			2003
U.S. federal:
Current	$	370		$	285
Deferred		(370	)		(285	)
Foreign:
Current		11,972			5,514
Deferred		—			—
Total	$	11,972		$	5,514

The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2004 are as follows:

Deferred Tax Assets:
Reserves not currently deductible		260
Foreign tax credit carryforwards		617
Alternative minimum tax credit carryover		1,290
Asset retirement obligations		465
		2,632
Valuation allowance		(1,342	)
Total deferred tax asset	$	1,290

Pretax income (loss) is comprised of the following:

(In thousands)	Year Ended December 31,
	2004		2003
United States	$	131	$	(4,228	)
Foreign		39,939		18,302
	$	40,070	$	14,074

The statutory rate reconciliation is as follows:

(In thousands)	Year Ended December 31,
	2004			2003
Pre-tax income (loss) multiplied by 35%	$	14,024		$	4,926
Foreign taxes not offset by U.S. foreign tax credits		98			588
U.S. net operating losses benefited		(2,150	)		—
Total income tax	$	11,972		$	5,514

41

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At December 31, 2004, the Company was subject to foreign and federal taxes only, with no allocations made to state and local taxes.

6. RELATED-PARTY TRANSACTIONS

During the year ended December 31, 2003, the Company incurred interest costs on a loan from the 1818 Fund associated with the Phase 1 development of the Etame field of $311.

7. COMMITMENTS AND CONTINGENCIES

In connection with the charter of the FPSO at Etame, the Company as operator of the Etame field guaranteed the charter payments through September 2004. The charter continues for four years beyond that period unless one year’s prior notice is given to the owner of the FPSO. The Company obtained several guarantees from its partners for their share of the charter payment. The Company’s share of the charter payment is 28.1%. The Company believes the need for performance under the charter guarantee is remote. The estimated obligations for the annual charter payment and the Company’s share of the charter payments for the next twelve months are as follows:

$ thousands	Full Charter Payment		Company Share
	$	16,781	$	4,711

The Company’s share of charter expense, including a $0.25 per barrel charter fee was $4,502 and $5,384 for the years ending December 31, 2004 and 2003 respectively.

The Company has operating lease obligations for rentals as follows:

$thousands	2005	2006	2007	2008
	2,841	1,964	191	12

The Company incurred rent expense of $989 and $874 under operating leases during the years ending December 31, 2004 and 2003 respectively.

In July of 2001, the consortium elected to renew the Etame block for an additional five-year term, consisting of a three-year and a two-year follow-on term. The consortium elected to enter the two year follow-on term extending the Etame block until July 2006. A $5.0 million exploration expenditure commitment ($1.5 million net to the Company) is required during the two-year extension.

Under the terms of the Etame Production Sharing Contract, the Contractor is required to provide to the local government refinery a volume of crude at a 25% discount to market price (the “Domestic Obligation”). The volume required to be furnished is the amount of the Etame production divided by the total Gabon production times the volume of oil refined by the refinery per year. In 2004 the Company paid $747 for its share of the 2002 and 2003 Domestic Obligation. The Company accrues an amount for the Domestic Obligation based on management’s best estimate of the volume of crude required, because the refinery does not publish its throughput figures. The amount accrued at December 31, 2004 is $554.

The Company believes it is substantially in compliance with all environmental regulations.

8. LONG TERM DEBT

To fund its share of the 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. The credit facility bears interest at LIBOR plus 4.25% and contains standard covenants for secured loans, including

42

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

debt coverage ratios based on World Bank price forecasts. During the year ended December 31, 2004 the Company has repaid $6.25 million of the loan as called for under the facility repayment schedule. The remaining $3.75 million is due as follows, 2005—$2.25 million, 2006—$1.25 million, 2007—$0.25 million.

In connection with the loan, the IFC holds a pledge of the Company’s interest in the Etame Block, and pledge of the shares of VAALCO Gabon (Etame), Inc. the subsidiary which owns the Company’s interest in the Etame Block. The IFC also has a security interest in the crude oil sales contract with Shell Western Supply and Trading, Limited.

9. ASSET RETIREMENT OBLIGATIONS

In August 2001, the FASB 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 on January 1, 2003. The statement requires the systematic, accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS No. 143 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows (in thousands):

	2004			2003
Balance January 1,	$	1,165		$	3,294
Impact of accounting change		—			(574	)
Accretion Expense		65			168
Additions		294			—
Revisions		(194	)		(225	)
Discontinued Operations		—			(1,498	)
Balance December 31,	$	1,330		$	1,165

During the year ended December 31, 2004 the Company increased the ARO liabilities by $165 to reflect the fair value of the ARO at December 31, 2004. The increase was due to increased liability associated with addition of the Etame 5H well at the Etame field partially offset by revisions to abandonment timing. During the year ending December 31, 2003, the Company decreased ARO liabilities by $57 to reflect the fair value of the ARO at December 31, 2003. The decrease was due to reduced liability associated with the Etame field due to the present value impact of the extended field life associated with increased reserves.

Pursuant to the January 1, 2003 adoption of SFAS No. 143 the Company:

• recognized a gain during the first quarter of 2003 of $1.7 million for the cumulative effect of accounting change. Of this amount, discontinued operations in the Philippines contributed a $1.9 million gain offset by $0.2 million in losses in Gabon and the United States.

43

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• increased assets by $1.3 million to add the net asset retirement costs to the carrying costs of the Company’s oil and gas properties;

• reduced the accrued liability for future abandonment costs by $0.6 million to reflect the present value of the asset retirement obligation (“ARO”) liability. The discontinued operations in the Philippines accounted for a $1.9 million liability reduction, offset by $1.3 million increase in the United States and Gabon;

• increased accumulated depletion by $0.1 million to record prior period depletion of the ARO asset.

Adopting SFAS No. 143 had no impact on our reported cash flows.

As of December 31, 2004, the Company had $38 legally restricted for settling asset retirement obligations.

10. DISCONTINUED OPERATIONS

On April 30, 2004, the Company closed the sale of all of its assets associated with Service Contract 6 and Service Contract 14 in the Philippines. Terms of the sale included the assumption by the partners of the Company’s entire share of any abandonment, environmental or other liabilities associated with the Service Contracts. The Company has reclassified earnings to break out the results of discontinued operations for prior periods in its financial statements. The Company realized a loss on the sale of the assets of $125,000 after paying transaction costs of $1,253,000 which was recorded in 2004 as follows:

(thousands of dollars)
Future asset retirement obligations assumed by buyer	$	1,498
Book value of assets transferred to buyer
Materials and supplies		(321	)
Prepaid expenses		(2	)
Notes receivable		1
Property and equipment		(4	)
Deposits and other assets		(12	)
Accounts due partners		(98	)
Payments required under the purchase and sale agreement
Payment to contingency fund		(198	)
Payment to operating account		(136	)
Severance benefits		(747	)
Other closing costs		(106	)
Loss on asset sale	$	(125	)

44

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Year ended December 31,
	2004			2003
Loss from discontinued operations
Revenues from oil sales	$	40		$	502
Operating costs and expenses:
Production expenses		71			373
Exploration expenses		—			—
Depreciation, depletion and amortization		—			91
General and administrative expenses		37			260
Total operating costs and expenses		108			724
Other revenues (expenses):
Interest income		6			17
Interest expense		(136	)
Other expenses (net)		(4	)		(39	)
Loss from discontinued operations before income taxes		(202	)		(244	)
Loss on asset sale		(125	)
Income tax expense (credit)		1,764			(209	)
Loss from discontinued operations	$	(2,091	)	$	(35	)

A summary of account balances for discontinued operations is presented as follows below in thousands:

	Year Ended December 31, 2004		Year Ended December 31, 2003
Current Assets
Other receivables	$	78	$	119
Materials and supplies		—		322
Prepayments and other		—		50
Total current assets	$	78	$	491
Property and equipment,- net		—		4
Other long-term assets		—		10
Total other assets	$	—	$	14
Current liabilities
Accounts payable	$	27	$	251
Accounts with partners		—		1,113
Interest payable		136		—
Income tax payable		1,764		—
Total current liabilities	$	1,927	$	1,364
Deferred tax liability		—		40
Asset retirement obligations		—		1,498
Total long term liabilities	$	—	$	1,538

The Company entered into the agreement dated February 29, 2004 with all of its partners in the Philippines, whereby it gave them the option to acquire all of its interests in Service Contract 6 and Service Contract 14 (Matinloc and Nido fields). Terms of the sale included the assumption by the partners of the Company’s entire

45

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

share of any abandonment, environmental or other liabilities whatsoever, associated with the Service Contracts. The Company gave its share of $1.5 million of funds held by the operator for working capital and abandonment liabilities (approximately $0.5 million) to the new operator. During the fourth quarter of 2004, the Company recorded a charge of $1.8 million for branch profit remittance taxes and interest based on the preliminary results of an audit by the Philippines Bureau of Internal Revenues (BIR). The BIR, the equivalent of the IRS in the United States, is assessing the taxes in association with the closing of the branch offices in the Philippines.

46

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

(in thousands of dollars unless otherwise indicated)

11. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

The following information is being provided as supplemental information in accordance with certain provisions of SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”. The Company’s reserves are located offshore of Gabon and Texas. The following tables set forth costs incurred, capitalized costs, and results of operations relating to oil and natural gas producing activities for each of the periods. (See Footnote 1—“ORGANIZATION”)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

(In thousands)	United States				Gabon
	2004		2003		2004		2003
Costs incurred during the year:
Exploration—capitalized	$	—	$	—	$	5,182	$	1,326
Exploration—expensed		—		—		267		327
Development		—		38		9,142		513
Asset retirement costs		1		20		65		988
Total	$	1	$	58	$	14,656	$	3,154

No costs were incurred for acquisitions, exploration and development activities associated with the discontinued operation in the Philippines in 2004 and 2003. No amounts of exploration costs were for dry hole expense in 2004 or 2003.

Capitalized Costs Relating to Oil and Gas Producing Activities:

	Year Ended December 31, 2004			Year Ended December 31, 2003
Capitalized costs—
Properties not being amortized	$	6,508		1,905
Properties being amortized(1)		33,222		23,393
Total capitalized costs		39,730		25,298
Less accumulated depreciation, depletion, and amortization		(13,940	)	(9,273	)
Net capitalized costs	$	25,790		16,025

(1) Includes $1,130 and $1,233 of asset retirement cost in 2004 and 2003 respectively.

The capitalized costs pertain to the Company’s producing activities in the Etame Block and U.S. activities.

47

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

Results of Operations for Oil and Gas Producing Activities:

	United States						International
	2004			2003			2004			2003
							Gabon			Gabon			Philippines
Crude oil and gas sales	$	245		$	480		$	56,257		$	35,001		502
Production expense		(69	)		(158	)		(9,889	)		(8,811	)	(373	)
Exploration expense		—			—			(267	)		(2,096	)	—
Depreciation, depletion and Amortization		(38	)		(147	)		(4,600	)		(5,638	)	(91	)
Income (loss) before taxes		138			175			41,501			18,456		38
Income tax (provision)		—			—			(11,972	)		(5,514	)	209
Results from oil and gas producing activities	$	138		$	175		$	29,529		$	12,942		247

Proved Reserves

A reserve report as of December 31, 2004 has been opined on by Netherland Sewell & Associates, independent petroleum engineers. The following tables set forth the net proved reserves of VAALCO Energy, Inc. as of December 31, 2004 and 2003, and the changes therein during the periods then ended.

	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2003	5,453		77
Production	(1,266	)	(51	)
Revisions	4,824		114
BALANCE AT DECEMBER 31, 2003	9,011		140
Production	(1,469	)	(22	)
Revisions	96		(64	)
Additions	1,447		—
Sale of reserves in place	(351	)	—
BALANCE AT DECEMBER 31, 2004	8,734		54
	Oil (MBbls)		Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at December 31, 2003 Balance at December 31, 2004	6,492 4,738		140 54

The Company’s proved developed reserves are located offshore Gabon and in Texas. The reserves in Gabon include the minority interest share of reserves held by the 9.99% owner of VAALCO International, Inc., which owns VAALCO Gabon (Etame), Inc. Proved oil reserves associated with discontinued operations in the Philippines were 351 thousand barrels in 2003 and were sold in 2004. There were no gas reserves in the Philippines.

The revisions in 2003 were predominately associated with better than expected reservoir performance from the Etame field offshore Gabon. Revisions in 2004 were associated with the Etame field and the Texas properties performance.

48

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

The Company maintains a policy of not booking proved reserves on discoveries until such time as a development plan has been prepared for the discovery. Additionally, the development plan is required to have the approval of the Company’s partners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves.

In 2004 the Company made two discoveries offshore Gabon, the Ebouri and the Avouma discoveries. The Avouma discovery was an extension of a previous discovery known as the South Tchibala discovery. The Company has prepared a detailed development plan for the South Tchibala/Avouma discovery, which has been submitted to and approved by the Company’s partners in the discovery. The Company has received approval from the Government of Gabon to declare the discovery commercial. Accordingly, the Company has booked as additions to proven reserves 1,447,000 barrels representing a portion of the reserves for the South Tchibala/Avouma field offshore Gabon in 2004.

For the Ebouri discovery, because of the decision to participate in a seismic shoot over Ebouri and other areas in the northern part of the Etame Block, the Company did not request any approvals for the development of the Ebouri discovery from its partners or the government, pending the results of the seismic. Therefore, the Company has not booked any reserves for the Ebouri discovery at December 31, 2004. The Company also has not booked any reserves associated with the North Tchibala discovery on the Etame block. The Company anticipates generating a development plan for these reserves in 2005.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves

The information that follows has been developed pursuant to procedures prescribed by SFAS No. 69 and utilizes reserve and production data estimated by independent petroleum consultants. The information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating VAALCO Energy, Inc. or its performance.

The future cash flows are based on sales prices and costs in existence at the dates of the projections, excluding Gabon royalties, and the interests of the Philippine government and the other consortium members. Future production costs do not include overhead charges allowed under joint operating agreements or headquarters general and administrative overhead expenses. Future development costs include $2,108 attributable to future abandonment when the wells become uneconomic to produce. The standardized measure of discounted cash flows does not include the costs of abandoning the Company’s non-producing properties.

	United States						International								Total
	December 31,						December 31,								December 31,
	2004			2003			2004			2003					2004			2003
							Gabon			Gabon			Philippines
Future cash inflows	$	977		$	1,292		$	350,234		$	259,909		4,978		$	351,211		$	266,179
Future production costs		(344	)		(482	)		(98,143	)		(56,752	)	(1,999	)		(98,487	)		(59,233	)
Future development costs		—			—			(27,554	)		(14,037	)	(1,378	)		(27,554	)		(15,415	)
Future income tax expense		(86	)		(126	)		(58,520	)		(49,522	)	—			(58,606	)		(49,648	)
Future net cash flows		547			684			166,017			139,598		1,601			166,564			141,833
Discount to present value at 10% annual rate		(127	)		(136	)		(43,116	)		(39,956	)	(181	)		(43,243	)		(40,273	)
Standardized measure of discounted future net cash flows	$	420		$	548		$	122,901		$	99,642		1,420		$	123,321		$	101,610

49

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

Income taxes represent amounts payable to the Government of Gabon on profit oil as final payment of corporate income taxes and for severance taxes in Texas.

Changes in Standardized Measure of Discounted Future Net Cash Flows:

The following table sets forth the changes in standardized measure of discounted future net cash flows as follows:

	December 31,
	2004			2003
BALANCE AT BEGINNING OF PERIOD	$	101,610		$	66,427
Sales of oil and gas, net of production costs		(46,544	)		(26,538	)
Net changes in prices and production costs		48,242			3,995
Revisions of previous quantity estimates		1,437			53,370
Additions		33,887			—
Sale of reserves in place		(1,451	)		—
Changes in estimated future development costs		(11,154	)		1,966
Development costs incurred during the period		9,721			552
Accretion of discount		10,019			6,507
Net change in income taxes		(9,064	)		(7,170	)
Change in production rates (timing) and other		(13,413	)		2,438
Discontinued Operations		31			63
BALANCE AT END OF PERIOD	$	123,321		$	101,610

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. 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 Gabon.

In accordance with the guidelines of the U.S. Securities and Exchange Commission, the Company’s estimates of future net cash flows 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, 2004 in Gabon was $40.28 per Bbl oil, representing a $0.19 discount to the spot price of Dated Brent Crude at December 31, 2004.

Under the Production Sharing Contract in Gabon, the Gabonese government is the owner of all oil and gas mineral rights. The right to produce the oil and gas is stewarded by the Directorate Generale de Hydrocarbeures

50

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

and the Production Sharing contract was awarded by a decree from the State. Pursuant to the service contract, the Gabon government receives a variable royalty depending on production rate. The consortium maintains a Cost Account, which entitles it to receive 70% of the production remaining after deducting the royalty so long as there are amounts remaining in the cost account. At December 31, 2003 there was $32.8 million in the cost account ($11.3 million net to the Company). As payment of corporate income taxes the consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil. The percentage of “profit oil” paid to the government as tax is a function of production rates. So long as amounts remain in the Cost Account, the net share that the consortium receives from production can range from a low of 67.7% of production at production rate in excess of 25,000 BOPD to a high of 82.5% of production at rates below 5,000 barrel per day. Also because of the nature of the Cost Account, decreases in oil prices result in a greater number of barrels required to recover costs, therefore at lower oil prices, the Company’s net reserves would increase.

The Etame Production Sharing Contract allows for the carve-out of a development area, which was performed for the Etame field. The Etame development area has a term of 20 years and will expire in 2021. The balance of the Etame Block comprises the exploration area, which expires in July 2006

Under the service contract, it is not anticipated that the Gabonese government will take physical delivery of its allocated production. Instead, the Company is authorized to sell the Gabonese government’s share of production and remit the proceeds to the Gabonese government.

51

Item 8. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 8A. Controls and Procedures

The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Annual Report on Form 10-KSB. Based on that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-KSB. There were no changes in the Company’s internal controls over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect the Company’s internal control over financial reporting.

PART III

Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act

Information required by this item will be included in the Company’s proxy statement for its 2004 annual meeting, which will be filed with the Commission within 120 days of December 31, 2004, and which is incorporated herein by reference.

Item 10. Executive Compensation

Information required by this item will be included in the Company’s proxy statement for its 2004 annual meeting, which will be filed with the Commission within 120 days of December 31, 2004, and which is incorporated herein by reference.

Item 11. Security Ownership of Certain Beneficial Owners and Management

Information required by this Item 403 of Regulation S-B concerning the security ownership of certain beneficial owners and management will be included in the Company’s proxy statement for its 2005 annual meeting, which will be filed with the Commission within 120 days of December 31, 2004, and which is incorporated herein by reference.

The following table provides information as of December 31, 2004 regarding the number of shares of Common Stock that may be issued under the Company’s compensation plans.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column)
Equity compensation plans approved by security holders	641,667	$	1.18	2,975,000
Equity compensation plans not approved by security holders(1)	3,377,668	$	1.16	N/A
Total	4,019,335	$	1.16	2,975,000

(1) Excludes 5,500,000 warrants issued in connection with 1818 Fund loan with an exercise price of $0.50 per share.

52

Item 12. Certain Relationships and Related Transactions

Information required by this item will be included in the Company’s proxy statement for its 2004 annual meeting, which will be filed with the Commission within 120 days of December 31, 2004, and which is incorporated herein by reference.

Item 13. Exhibits and Reports on Form 8-K

2. Plan of acquisition, reorganization, arrangement, liquidation or succession

2.1	(a)	Stock Acquisition Agreement and Plan of Reorganization dated February 17, 1998 by and among the Company and the 1818 Fund II, L.P.
2.2	(c)	First Amendment to Stock Acquisition Agreement and Plan of Reorganization, dated April 21, 1998
2.3	(h)	Stock Purchase Agreement between Western Atlas International, Inc., as Seller, and VAALCO Gabon (Etame), Inc. as Purchaser, dated January 4, 2001.
2.4	(h)	Stock Purchase Agreement between VAALCO Energy, Inc., as Seller and PanAfrican Energy Corporation Ltd., as Purchaser, dated January 15, 2001
2.5	(h)	Share Sale and Purchase Agreement By and Between VAALCO Gabon (Etame), Inc., and Sasol Petroleum International (Pty) Ltd. dated February 5, 2001.

3. Articles of Incorporation and Bylaws

3.1	(b)	Restated Certificate of Incorporation
3.2	(b)	Certificate of Amendment to Restated Certificate of Incorporation
3.3	(b)	Bylaws
3.4	(b)	Amendment to Bylaws
3.5	(c)	Designation of Convertible Preferred Stock, Series A

10. Material Contracts

10.1	(d)	Indemnity Agreement entered into among the Company and certain of its officers and directors listed therein.
10.2	(e)	Exploration and Production Sharing contract between the Republic of Gabon and VAALCO Gabon (Equata), Inc. dated July 7, 1995.
10.3	(e)	Exploration and Production Sharing contract between the Republic of Gabon and VAALCO Gabon (Etame), Inc. dated July 7, 1995.
10.4	(e)	Deed of Assignment and Assumption between VAALCO Gabon (Etame), Inc., VAALCO Energy (Gabon), Inc. and Petrofields Exploration & Development Co., Inc. dated September 28, 1995.
10.5	(f)	Letter of Intent for Etame Block, Offshore Gabon dated January 22, 1998 between the Company and Western Atlas International, Inc.
10.6	(g)	Registration Rights Agreement, dated July 28, 1997, by and among the Company, Jefferies & Company, Inc. and the investors listed therein.

53

10.7(c)	Registration Rights Agreement among the Company and 1818 Fund II, L.P., dated April 21, 1998
10.8(c)	Registration Rights Agreement dated April 21, 1998 by and among the Company, Jefferies & Company, Inc. and the investors listed therein.
10.9(h)	Conveyance of Production Payment from Western Atlas Afrique, Ltd. to Western Atlas International, Inc. dated December 29, 2000.
10.10(i)	2001 Stock Incentive Plan dated August 16, 2001
10.11(j)	Loan Agreement between VAALCO Gabon (Etame), Inc. and International Finance Corporation dated April 19, 2002.
10.12(j)	Subordinated Credit Agreement dated as of June 10, 2002, between VAALCO Energy, Inc. and 1818 Fund II, L.P.
10.13(j)	Guarantee Agreement between VAALCO Energy, Inc. and International Finance Corporation dated May 28, 2002.
10.14(j)	Trustee and Paying Agent Agreement by and between VAALCO Gabon (Etame), Inc., J.P. Morgan Trustee and Depositary Company Limited and JPMorgan Chase Bank, London Branch, dated June 26, 2002.
10.15(k)	Stock Purchase Agreement dated as of August 23, 2002, by and between the Company, VAALCO International, Inc. and Nissho Iwai Corporation.
10.16(k)	Stockholders’ Agreement dated August 23, 2002, by and among the Company, VAALCO International, Inc. and Nissho Iwai Corporation.
10.17(k)	Subscription Agreement between the Company and VAALCO International, Inc. dated August 23, 2002.
10.18(k)	Amended and Restated Registration Rights Agreement by and among the Company, Nissho Iwai Corporation and 1818 Fund II, L.P. dated as of August 23, 2002.
10.19(k)	Amended and Restated Subordinated Credit Agreement by and between the Company and 1818 Fund II, L.P. dated as of August 23, 2002.
10.20(k)	Second Amendment to Loan Agreement between VAALCO Gabon (Etame), Inc. and International Finance Corporation dated August 23, 2002.
10.21(l)	2003 Stock Incentive Plan dated December 16, 2003
21.1(m)	Subsidiaries of the Registrant
23.1(m)	Consent of Deloitte & Touche LLP

Additional exhibits

31.1	(m)	Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002
31.2	(m)	Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002
32.1	(m)	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act Of 2002.
32.2	(m)	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act Of 2002.

(a) Filed as an exhibit to the Company’s report on Form 8-K filed with the Commission on March 4, 1998 (file no. 000-20928) and hereby incorporated by reference herein.

54

(b) Filed as an exhibit to the Company’s Registration Statement on Form S-3 filed with the Commission on July 15, 1998 and hereby incorporated by reference herein.

(c) Filed as an exhibit to the Company’s Report on Form 8-K filed with the Commission on May 6, 1998 and hereby incorporated by reference herein.

(d) Filed as an exhibit to the Company’s Form 10 (File No. 0-20928) filed on December 3, 1992, as amended by Amendment No. 1 on Form 8 on January 7, 1993, and by Amendment No. 2 on Form 8 on January 25, 1993, and hereby incorporated by reference herein.

(e) Filed as an exhibit to the Company’s Form 10-QSB for the quarterly period ended September 30, 1995, and hereby incorporated by reference herein.

(f) Filed as an exhibit to the Company’s Form 10-KSB for the annual period ended December 31, 1996, and hereby incorporated by reference herein.

(g) Filed as an exhibit to the Company’s Form 10-QSB for the quarterly period ended June 30, 1997, and hereby incorporated by reference herein.

(h) Filed as an exhibit to the Company’s Form 10-KSB for the annual period ended December 31, 2000, and hereby incorporated by reference herein.

(i) Filed as an exhibit to the Company’s Registration Statement Form S-8 filed with the Commission on August 18, 2001.

(j) Filed as an exhibit to the Company’s Form 10-QSB for the quarterly period ended June 30, 2002, and hereby incorporated by reference herein.

(k) Filed as an exhibit to the Company’s Form 10-QSB for the quarterly period ended September 30, 2002, and hereby incorporated by reference herein.

(l) Filed as an exhibit to the Company’s Registration Statement Form S-8 filed with the Commission on April 13, 2004.

(m) Filed as an exhibit to this Form 10-KSB

(b) Reports on Form 8-K.

None

Item 14. Principal Accountant Fees and Services

The information required by Item 14 is incorporated by reference from the Company’s definitive proxy statement for its 2004 annual meeting, which will be filed with the Commission within 120 days of December 31, 2004, and which is incorporated herein by reference.

55

Glossary of Oil and Gas Terms

Terms used to describe quantities of oil and natural gas

• Bbl—One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.

• Bcf—One billion cubic feet of natural gas.

• Bcfe—One billion cubic feet of natural gas equivalent.

• BOE—One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil.

• BOPDE—One barrel of oil per day

• MBbl—One thousand Bbls.

• Mcf—One thousand cubic feet of natural gas.

• Mcfe—One thousand cubic feet of natural gas equivalent.

• MMBbl—One million Bbls of oil or other liquid hydrocarbons.

• MMcf—One million cubic feet of natural gas.

• MBOE—One thousand BOE.

• MMBOE—One million BOE.

Terms used to describe the Company’s interests in wells and acreage

• Gross oil and gas wells or acres—The Company’s gross wells or gross acres represent the total number of wells or acres in which the Company owns a working interest.

• Net oil and gas wells or acres—Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that the Company owns in such wells or acres represented by the underlying properties.

Terms used to assign a present value to the Company’s reserves

• Standard measure of proved reserves—The present value, discounted at 10%, of the pre-United States income tax future net cash flows attributable to estimated net proved reserves. The Company calculates this amount by assuming that it will sell the oil and gas production attributable to the proved reserves estimated in its independent engineer’s reserve report for the prices it received for the production on the date of the report, unless it had a contract to sell the production for a different price. The Company also assumes that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. The assumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes using rates in effect on the date of the report are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of the Company’s proved reserves.

• Pre-tax discounted present value—The discounted present value of proved reserves is identical to the standardized measure, except that estimated future income taxes are not deducted in calculating future net cash flows. The Company discloses the discounted present value without deducting estimated income taxes to provide what it believes is a better basis for comparison of its reserves to the producers who may have different tax rates.

Terms used to classify the Company’s reserve quantities

• Proved reserves—The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions.

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The SEC definition of proved oil and gas reserves, per Article 4-10(a) (2) of Regulation S-X, is as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(b) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

• Proved developed reserves—Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

• Proved undeveloped reserves—Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

Terms which describe the productive life of a property or group of properties

• Reserve life—A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve life for the years ended December 31, 2004, 2003 or 2002 equal the estimated net proved reserves attributable to a property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated.

Terms used to describe the legal ownership of the Company’s oil and gas properties

• Royalty interest—A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

• Working interest—A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property.

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Terms used to describe seismic operations

• Seismic data—Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations.

• 2-D seismic data—2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data.

• 3-D seismic data—3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated.

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VAALCO ENERGY, INC. (Registrant)
By	/S/    W. RUSSELL SCHEIRMAN
	W. Russell Scheirman, President, Chief Financial Officer and Director

Dated March 7, 2005

In accordance with the Exchange Act, this report has been signed below on the 7th day of March, by the following persons on behalf of the registrant and in the capacities indicated.

	Signature	Title
By:	/s/ ROBERT L. GERRY, III Robert L. Gerry, III.	Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
By:	/s/ W. RUSSELL SCHEIRMAN W. Russell Scheirman	President, Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)
By:	/s/ Robert H. Allen Robert H. Allen	Director
By:	/s/ Will S. Farish Will S. Farish	Director
By:	/s/ Walter W. Grist Walter W. Grist	Director
By:	/s/ T. Michael Long T. Michael Long	Director
By:	/s/ Arne R. Nielsen Arne R. Nielsen	Director
By:	/s/ Lawrence C. Tucker Lawrence C. Tucker	Director

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