Edgar Filing: VAALCO ENERGY INC /DE/

Form 10-K for the Fiscal Year Ended December 31, 2009

Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(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, 2009

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

For the transition period from to

Commission file number: 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified on 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)

(Registrant’s telephone number, including area code): (713) 623-0801

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


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

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

None

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15d of the Act Yes No X

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes No .

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer Accelerated filer X Non-accelerated filer Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act Yes No X

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, as of June 30, 2009 was $245,827,837 based on a closing price of $4.23 on June 30, 2009.

As of February 28, 2010, there were outstanding 56,427,253 shares of common stock, $0.10 par value per share, of the registrant.

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-K.

Index to Financial Statements

VAALCO ENERGY, INC.

TABLE OF CONTENTS


		Page

	Glossary of Oil and Gas Terms	3

PART I

Item 1.	Business	7
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	20
Item 3.	Legal Proceedings	26
Item 4.	[Reserved]	26

PART II

Item 5.	Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities	27
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 8.	Financial Statements and Supplementary Data	37
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	37
Item 9A.	Controls and Procedures	37
Item 9B.	Other Information	40

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	40
Item 11.	Executive Compensation	40
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	40
Item 13.	Certain Relationships, Related Transactions and Director Independence	40
Item 14.	Principal Accountant Fees and Services	40

PART IV

Item 15.	Exhibits and Financial Statement Schedules	41

INDEX TO CONSOLIDATED FINANCIAL INFORMATION		F-1

Index to Financial Statements

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.

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Bcfe—One billion cubic feet of natural gas equivalent.

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

•

BOPD—One barrel of oil per day.

•

MBbl—One thousand Bbls.

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Mcf—One thousand cubic feet of natural gas.

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McfD—One thousand cubic feet of natural gas per day.

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Mcfe—One thousand cubic feet of natural gas equivalent.

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

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MMcf—One million cubic feet of natural gas.

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MBOE—One thousand BOE.

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MMBOE—One million BOE.

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

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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.

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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 used in 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.

Terms used to classify the Company’s reserve quantities

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Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Index to Financial Statements

•

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:

(A)

The area identified by drilling and limited by fluid contacts, if any, and

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

•

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

•

Standardized measure. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (SEC), using prices and costs in effect as of the date of estimation, without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.

Index to Financial Statements

•

Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditures is required for recompletion.

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedule to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

•

Unproved properties. Properties with no proved reserves.

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

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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, 2009, 2008 or 2007 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

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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 minerals 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.

Terms used to describe seismic operations

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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.

Index to Financial Statements

•

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.

Index to Financial Statements

PART I

Item 1.

Business

BACKGROUND

VAALCO Energy, Inc., a Delaware corporation incorporated in 1985, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. VAALCO owns producing properties and conducts exploration activities as operator in Gabon, West Africa, conducts exploration activities as operator in Angola, West Africa and conducts exploration activities as a non-operator in the British North Sea. As used herein, the terms “Company” and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. The Company’s corporate headquarters are located at 4600 Post Oak Place, Suite 309, Houston, Texas 77027 where the telephone number is (713) 623-0801.

VAALCO’s international subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., and VAALCO International Inc. VAALCO Energy (USA), Inc. holds interests in certain properties located in the United States.

RECENT DEVELOPMENTS

The Company’s primary source of revenue is from the Etame Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. VAALCO operates the Etame Marin block on behalf of a consortium of companies. At December 31, 2009, VAALCO owned a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas surrounding the Etame, Avouma, South Tchibala and Ebouri fields. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development.

The Company produces from the Etame, Avouma, South Tchibala and Ebouri fields on the block. Oil production commenced from the Etame field in September 2002, from the Avouma and South Tchibala fields in January 2007, and from the Ebouri field in January 2009. During 2009, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 8.3 million bbls (1.9 million bbls net to the Company).

Beginning in November 2008, drilling began on the first of two exploration wells within the Etame Marin block. The first of these wells, the North Ebouri, encountered substantial oil-filled Gamba sandstone, proving-up significant additional reserves North of the originally mapped Ebouri field development outline. The second well, the North Etame prospect, encountered water bearing sands and was abandoned. Also beginning in November 2008, drilling began on the first of two development wells in the Ebouri field. Both wells were brought onto production in 2009.

Onshore Gabon, the Company has a 100% working interest in the Mutamba Iroru block located near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of approximately 270,000 acres. Two exploration wells were drilled in 2009 and both wells encountered water bearing sands and were abandoned.

Exploration period extensions were successfully negotiated with the government of Gabon on both of the blocks under contract. The Etame Marin block received a four year extension expiring in 2014 and the Mutamba Iroru block received a two year extension expiring in 2011.

In November 2006, the Company signed a production sharing contract for a 40% working interest in Block 5 offshore Angola. The four year contract with an optional three year extension awards the Company exploration rights to approximately 1.4 million acres along the central coast of Angola. The Company has been interpreting seismic data in preparation for the drilling of two exploration wells. The government-assigned working interest partner has been delinquent on paying their share of the costs several times in 2009 and consequently was placed

Index to Financial Statements

in a default position which has impacted the timing for drilling the wells. In early 2010, the Company began the process to acquire the interest of the non-performing partner and is working with the government of Angola regarding a time extension for the drilling of the commitment wells beyond the November 2010 expiration date. While we believe that the government of Angola will grant us an extension, we can provide no assurances. If the government of Angola were to deny a time extension, the Company risks forfeiture of its $10 million funds in escrow if the wells are not drilled by November 2010 plus the Company may be required to impair its leasehold costs and other investments of $11.4 million as of December 31, 2009. If we are successful in obtaining such extension, the Company estimates the drilling will take place in the first half of 2011 on this block in Angola.

In January 2008, the Company signed a farm-in agreement for a 25% working interest in Block 48/25c offshore in the British North Sea. In February 2009, the Company participated in a well drilled on the block in the Southern Gas Basin. A substantial gas column was found but with low permeability and porosity. The well was deemed to be non-commercial by the consortium and was abandoned.

See Note 14 to the Company’s consolidated financial statements for financial information about the Company’s segments.

AVAILABLE INFORMATION

The Company files annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy any document the Company files at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. The Company’s SEC filings are also available to the public at the SEC’s website at www.sec.gov.

You may also obtain copies of the Company’s annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from the Company’s website at www.vaalco.com. No information from the SEC’s or the Company’s website is incorporated by reference herein. The Company has placed on its website copies of its Audit Committee Charter, Code of Business Conduct and Ethics, and Code of Ethics for the Chief Executive Officer and Chief Financial Officer. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, VAALCO Energy Inc., 4600 Post Oak Place, Suite 309, Houston, Texas 77027.

GENERAL

The Company’s current production strategy is to maximize the value of the reserves discovered in Gabon through exploitation of the Etame Marin block (comprised of the Etame, Avouma, South Tchibala and Ebouri fields). The Company also owns a 100% working interest in the 270,000 acre Mutamba Iroru block onshore Gabon and a 40% working interest in the 1.4 million acre Block 5 offshore Angola where, along with the Etame Marin Block, exploration activities take place.

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. 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 two exploration licenses in Gabon, and one exploration license in Angola.

Index to Financial Statements

Domestic

The Company’s domestic strategy is to produce existing reserves. There are no plans to drill new domestic wells at this time. Current domestic properties are located in Brazos County, Texas and offshore Louisiana in the Ship Shoal area.

CUSTOMERS

Substantially all of the Company’s oil and gas is sold at posted or indexed prices under short-term contracts, as is customary in the industry. In Gabon, the Company sold oil under a contract with Total Oil Trading S.A. which ran through calendar year 2009. For the 2010 calendar year, the Company will sell its oil under a contract with Vitol S.A. (“Vitol”). While the loss of Vitol 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 via 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, 2009, the Company had 77 full-time employees and consultant contractors, 44 of whom were located in Gabon and nine of whom were located in Angola. The Company is not subject to any collective bargaining agreements, although most of the national employees in Gabon are members of the NEOP (National Organization of Petroleum Workers) union. The Company 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. In addition, the producing, processing and marketing of oil and gas is affected by a number of factors beyond the control of the Company, the effects of which cannot be accurately predicted.

The Company’s competition for acquisitions, exploration, development and production include the major oil and gas companies in addition to numerous independent oil companies, individual proprietors, investors 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 evaluate and acquire desirable leases 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, Gabon and Great Britain and will be subject to the laws and regulations of Angola when exploration drilling begins. 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. In part because they are developing countries, it is unclear how quickly and to what extent Gabon or Angola will increase their regulation

Index to Financial Statements

of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon or Angola could have a material effect on the Company. Developing countries, in certain instances, have patterned environmental laws after those in the United States which are discussed below. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

Environmental Regulations in the United States

Solid and Hazardous Waste

The Company currently owns or leases, and in the past has 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, although oil and gas wastes generally are exempt from regulation as hazardous waste, it is possible that certain wastes generated by the Company’s oil and gas operations that are currently exempt may in the future be designated as Hazardous Wastes under RCRA or other applicable statutes and, therefore, may be subject to more rigorous and costly disposal requirements.

Superfund

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action.

Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, the Company has generated, and will generate, wastes that may fall within CERCLA’s definition of Hazardous Substance and may have disposed of these wastes at disposal sites owned and operated by others. 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 or to which the Company sent Hazardous Substances, the Company could be liable for costs of investigation and remediation and natural resources damages.

Index to Financial Statements

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 the 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 bbls 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.

Endangered Species Act.

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

Climate Change Legislation

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. The U.S. Congress has considered climate change related legislation to regulate GHG emissions that could affect our operations and our regulatory costs, as well as the value of oil and natural gas generally. A climate change bill passed the United States House of Representatives but the Senate has not passed climate legislation. The House bill would establish

Index to Financial Statements

a “cap-and-trade” program under which overall GHG emissions are limited and allowances to emit GHGs are then allocated and/or sold. Although Congress has not passed comprehensive climate change legislation, expectations are that Congress will continue to consider some type of climate change legislation. There is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In the absence of federal legislative action on climate change, the EPA has initiated a number of rulemakings, the result of which would be the regulation of GHG emissions under the Clean Air Act. Further, the EPA has enacted a mandatory greenhouse gas reporting program which imposes reporting and monitoring requirements on the covered industries; we do not believe our operations to be subject to this program, but there is no guarantee that the EPA will not expand the program to additional industries. Should we be required to report GHG emissions, it could require us to incur costs to monitor, keep records of, and report emissions of GHGs. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These federal and state initiatives may result in regulatory requirements that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations under a cap-and-trade program, or installing pollution control equipment to control emissions under the Clean Air Act. These regulatory initiatives also could adversely affect the marketability of the oil and natural gas the Company produces. The impact of such future programs cannot be predicted, but the Company does not expect its operations to be affected any differently than other similarly situated domestic competitors.

Air Emissions

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

Coastal Coordination

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

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

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.

Index to Financial Statements

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;

•

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, including the economic and financial market crisises;

•

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, including those related to climate change;

•

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.

Index to Financial Statements

Item 1A.

Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this Report. If any of these risks or uncertainties actually occurs, our business, financial condition and results of operations could be materially adversely affected. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. In this section, the terms “VAALCO”, “we”, “us” and “our” refer to VAALCO Energy, Inc. and its subsidiaries, unless the context clearly indicates otherwise.

Almost all of the value of our production and reserves is concentrated in a single block offshore Gabon, and any production problems or reductions in reserve estimates related to this property would adversely impact our business.

The Etame field consisting of four producing wells, the Avouma and South Tchibala fields consisting of one producing well each, and the Ebouri field with two producing wells constituted almost 100% of our total production for the year ended December 31, 2009. In addition, at December 31, 2009, almost 100% of our total net proved reserves were attributable to these fields. 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 our estimated reserves, our results of operations and financial condition could be materially adversely affected.

Our results of operations and financial condition could be adversely affected by changes in currency exchange rates.

Our results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our operating costs in Gabon are denominated in the local currency. A weakening U.S. Dollar will have the effect of increasing operating costs while a strengthening U.S. Dollar will have the effect of reducing operating costs. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has fluctuated widely in response to international political conditions, general economic conditions and other factors beyond our control.

A decrease in oil and gas prices may adversely affect our results of operations and financial condition.

Our revenues, cash flow, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas. Our 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, particularly in 2008 and 2009, and are likely to continue to be volatile in the future. The average price for crude we sold from Gabon in 2009 was $59.54 per barrel compared to $92.87 per barrel in 2008 and $71.16 per barrel in 2007.

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 our 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, the health of international economic and credit markets, and general 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 our ability to market our oil and gas production. Any significant decline in the price of oil or gas would adversely affect our revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of our oil and gas properties and our planned level of capital expenditures.

Index to Financial Statements

If there is a sustained economic downturn or recession in the United States or globally, oil and natural gas prices may fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

We experienced an economic downturn or a recession in the United States and globally. The reduced economic activity associated with the economic downturn or recession may reduce the demand for, and the prices we receive for, our oil and gas production. A sustained reduction in the prices we receive for our oil and gas production will have a material adverse effect on our results of operations.

Unless we are able to replace reserves which we have produced, our cash flows and production will decrease over time.

Our future success depends upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. There can be no assurance that our planned development and exploration projects and acquisition activities will result in significant additional reserves or that we 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, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, political instability, availability of capital, economic/currency imbalances, compliance with governmental requirements, receipt of additional seismic data or the reprocessing of existing data, material changes in oil or gas prices, prolonged periods of historically low oil and gas prices, failure of wells drilled in similar formations or delays in the delivery of equipment and availability of drilling rigs. Our current domestic oil and gas properties are operated by third parties and, as a result, we have 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 us in the future, is required to replace and grow reserves.

We make, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas reserves. Historically, we have financed these expenditures primarily with cash flow from operations, debt, asset sales, and private sales of equity. During 2009, we participated, and in 2010 we expect to continue to participate, in the further exploration and development projects on our international properties. In Gabon and Angola, we are the operator of the blocks and are thus responsible for contracting on behalf of all the remaining parties participating in the project. We rely on the timely payment of cash calls by our partners to pay for the 69.65% share of the Etame budget and 50% of the Angola Block 5 budget for which they are responsible. However, if lower oil and gas prices, operating difficulties or declines in reserves result in our revenues being less than expected or limit our ability to borrow funds, or our partners fail to pay their share of project costs, we may have a limited ability, particularly in the current economic environment, to expend the capital necessary to undertake or complete future drilling programs. We cannot assure that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

We may need access to the capital markets to fund a portion of our growth strategy. The recent unprecedented disruption in the capital markets may adversely affect our growth strategy.

During 2008 and 2009, the U.S. and international financial markets experienced unprecedented volatility and disruption. This disruption in the financial markets made it difficult for companies to successfully issue common stock or debt securities to fund growth. If the effects of disruption in the financial markets continues for a substantial period of time or if a disruption reoccurs, our ability to fund growth may be adversely affected.

Index to Financial Statements

Our drilling activities require us 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 us will be productive or that we will recover all or any portion of our investment. Drilling for oil and 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. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.

Weather, unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our 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 us 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. Our production facilities are also subject to hazards inherent in marine operations, such as capsizing, sinking, grounding, collision and damage from severe weather conditions. The relatively deep offshore drilling conducted by us 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 us is increased due to the low number of producing properties we own.

We maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant unfavorable event not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict whether insurance will continue to be available at a reasonable cost or at all.

Our 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 our reserves.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond our 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 in this document are based on various assumptions required by the SEC, including unescalated prices and costs and capital expenditures subsequent to December 31, 2009, 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 incorporated by reference in this document. In addition, our 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 SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our 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 our net proved reserves are prepared in accordance with current SEC guidelines, and are not intended to reflect the fair market value of our reserves. The SEC amended the definition of proved reserves for all reserve estimated included in filings after January 1, 2010. As a result,

Index to Financial Statements

the estimates of proved reserves filed in reports prior to January 1, 2010 may not be comparable to reports filed after that date, including those in this annual report. In accordance with the rules of the SEC, our reserve estimates are prepared using an average of beginning of month prices received for oil and gas for the preceding twelve months. Future reductions in prices below the average calculated for 2009 would result in the estimated quantities and present values of our reserves being reduced.

A substantial portion of our proved reserves are or will be subject to service contracts, production sharing contracts and other arrangements. The quantity of oil and gas that we 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.

We have less control over our foreign investments than domestic investments, and turmoil in foreign countries may affect our foreign investments.

Our 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, we 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 our ownership of foreign oil and gas properties. In the foreign countries in which we do 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 our proven reserves are located offshore of the Republic of Gabon. As of December 31, 2009, we carried a gross investment of approximately $138.7 million including leasehold and asset retirement obligations on our balance sheet associated with the Etame, Avouma, South Tchibala and Ebouri fields in Gabon. We have operated in Gabon since 1995 and believe we have 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 our operations or cash flows.

A time extension for the drilling of two exploration wells in Angola is necessary to protect certain amounts invested in that country.

Due to financial non-performance of the venture partner assigned by the government of Angola, the plans to drill the two obligatory wells by November 2010 have been delayed. While the government of Angola has verbally expressed willingness to work with Company on this matter, we can provide no assurances that an extension will be granted. Steps taken in early 2010 have been taken, in coordination with the government, to acquire the interest of the non-performing partner and to obtain a time extension for the drilling of the wells. At risk is a $10.0 million escrow account that guarantees the Company’s performance to drill the two wells in 2010 plus leasehold and other capitalized assets of $11.4 million at December 31, 2009.

Index to Financial Statements

Competitive industry conditions may negatively affect our ability to conduct operations.

We operate in the highly competitive areas of oil exploration, development and production. We compete 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 our ability to compete in the marketplace include:

•

our access to the capital necessary to drill wells and acquire properties;

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our ability to acquire and analyze seismic, geological and other information relating to a property;

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our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;

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the location of, and our ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production; and

•

the standards we establish for the minimum projected return on an investment of our capital.

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

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

The laws and regulations of the United States, Gabon, Angola and Great Britain regulate our current business. Our operations could result in liability for personal injuries, property damage, natural resource damages, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. In addition, we could be liable for environmental damages caused by, among others, previous property owners or operators. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change and greenhouse gases and use of fracking fluids. 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 our 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 our operating costs, as well as the oil and gas industry in general. While we believe that we are currently in compliance with environmental laws and regulations applicable to our operations, no assurances can be given that we will be able to continue to comply with such environmental laws and regulations without incurring substantial costs.

If our assumptions underlying accruals for abandonment costs are too low, we could be required to expend greater amounts than expected.

Almost all of our producing properties are located offshore. The costs to abandon offshore wells may be substantial. For financial accounting purposes, we record the fair value of a liability for an asset retirement obligation 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.

Index to Financial Statements

From time to time we may hedge a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

We may reduce our exposure to the volatility of oil and gas prices by hedging a portion of our production. Hedging also prevents us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the hedge agreement. In a typical hedge transaction, we have the right to receive from the hedge counterparty the excess of the maximum fixed price specified in the hedge agreement over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the maximum fixed price, we must pay the counterparty this difference multiplied by the quantity hedged even if we had insufficient production to cover the quantities specified in the hedge agreement. Accordingly, if we have less production than we have hedged when the floating price exceeds the fixed price, we must make payments against which there are no offsetting sales of production. If these payments become too large, the remainder of our business may be adversely affected.

In addition, hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations. This risk of counterparty performance is of particular concern given the disruptions that occurred in the financial markets that lead to sudden changes in a counterparty’s liquidity and hence their ability to perform under the hedging contract.

We rely on our senior management team and the loss of a single member could adversely affect our operations.

We are highly dependent upon our executive officers and key employees. The unexpected loss of the services of any of these individuals could have a detrimental effect on us. We do not maintain key man life insurance on any of our employees.

We rely on a single purchaser of our Gabon production, which could have a material adverse effect on our results of operations.

Effective January 2010, we sell all of our crude oil production in Gabon to Vitol S.A. The loss of Vitol as a purchaser of our Gabon production could force the shut-in of our Gabon production until the purchaser is replaced, and could have a material adverse effect on our results of operations.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

Item 1B.

Unresolved Staff Comments

None.

Index to Financial Statements

Item 2.

Properties

Gabon

Etame Marin

VAALCO has an interest in a 1,186 square mile offshore block in Gabon, the Etame Marin block where it signed a production sharing contract in 1995. The block contains the Etame, Avouma, South Tchibala and Ebouri fields, all of which are on production, and the North Tchibala discovery for which there are no development plans at this time. These fields and discoveries consist of subsalt reservoirs that lie 20 miles offshore in approximately 250 feet of water depth.

VAALCO operates the Etame Marin block on behalf of a consortium of companies. At December 31, 2009, VAALCO owned a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas surrounding the Etame, Avouma, South Tchibala and Ebouri fields. The development areas were subject to a 7.5% back-in by the government of Gabon, which occurred for these fields after their successful development.

The Etame Marin block consortium approved the development of 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 19 square mile exploitation area surrounding the field. The exploitation area has a term of up to 20 years (through 2021).

The Etame field has been developed at an aggregate cost of approximately $124 million ($40.3 million net to the Company). The development included completing subsea wells connected to a contracted floating production, storage and offloading vessel (“FPSO”). There are currently four wells producing in the Etame field.

In April 2005, a development plan for the joint development of the Avouma and South Tchibala fields was approved by the Gabon government. The Company was awarded a 20 square mile exploitation area which has a term of twenty years (until 2025). In 2006, the Company installed a platform in approximately 250 feet of water and drilled two development wells from the platform, one into each field. The two development wells are tied back to the FPSO via a ten mile pipeline. Through December 31, 2009, the cost of developing the Avouma and South Tchibala fields was approximately $121 million ($36.4 million net to the Company).

The Company drilled the Ebouri discovery well to total depth in January 2004. In October 2006, the Gabon government approved the development plan for the Ebouri field and the Company was awarded a nearly 6 square mile exploitation area which has a term of twenty years (until 2026). A platform was installed in July 2008, approximately seven miles from the FPSO, and is tied back to the FPSO via a pipeline as was done for the Avouma and South Tchibala fields. The cost of developing the Ebouri field as of December 31, 2009 totaled approximately $158 million ($51.9 million net to the Company). The first development well began production in January 2009, and the second development well began producing crude oil in April 2009.

The Company has sold a total of 49.0 million gross bbls (11.5 million net bbls) from the fields within the Etame Marin block since startup through December 31, 2009. During 2009, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 8.3 million gross bbls (1.9 million net bbls).

Beginning in November 2008, drilling began on two exploration wells located within the Etame Marin block. The first of these wells, the North Ebouri, encountered substantial oil-filled Gamba sandstone, proving-up significant additional reserves north of the originally mapped field development outline. The second well, the North Etame prospect, encountered water bearing sands and was abandoned.

The Company negotiated an extension of the exploration permit on this block to 2014. The terms of the extension include an additional exploration well, bringing the total required under the permit to two exploration wells, and to acquire additional 3-D seismic data, which is expected to be acquired in 2010.

Index to Financial Statements

Mutamba Iroru

In November 2005, the Company signed a production sharing contract for the Mutamba Iroru block onshore Gabon. The five year contract awarded the Company exploration rights to approximately 270,000 acres along the central coast of Gabon. The Mutamba Iroru block was previously held by Shell Gabon. The Company has a 100% interest in the Mutamba Iroru block. The Company acquired aeromagnetic gravity data in 2008, and together with seismic data acquired from previous operators over the block in 2006 and 2007, drilled two exploration wells in 2009. Both wells encountered water bearing sands and were abandoned.

The Company negotiated an extension of the exploration period until 2011. The terms of the extension obligate the Company to drill an exploration well and acquire 200 linear kilometers of seismic data during the term of the extension period. The obligation to drill an exploration well was met with the drilling of the second exploration well in 2009.

Angola

Block 5

Effective December 1, 2006, the Company acquired a 40% working interest in Block 5 offshore Angola. The four year contract with an optional three year extension awarded the Company exploration rights to approximately 1.4 million acres offshore Angola. The Company has acquired approximately 1,700 square kilometers of seismic data over a portion of Block 5 and has been interpreting the data and developing potential drilling locations. The plans to drill two exploration wells have been delayed due to a non-performing partner. In early 2010, the Company began the process to acquire the interest of the non-performing partner and is working with the government of Angola regarding a time extension for the drilling of the commitment wells beyond the November 2010 expiration date. While we believe that the government of Angola will grant us an extension, we can provide no assurances. Any adverse developments related to the Company’s ability to extend the drilling obligation date could result in an impairment of the Company’s unproved properties and other assets of approximately $11.4 million as well as the loss of the funds the Company has escrowed to secure its drilling obligations of $10 million. If we are successful in obtaining such extension, the Company estimates the drilling will take place in the first half of 2011 on this block in Angola.

Great Britain

In January 2008, the Company signed a farm-in agreement for a 25% working interest in Block 48/25c offshore in the British North Sea. The Company was obligated to pay its share of the drilling of one exploration well on the block and a portion of the farminee’s share of the well. In February 2009 the Company participated in a well drilled on the block in the Southern Gas Basin. A substantial gas column was found but with low permeability and porosity. The well was deemed to be non-commercial by the consortium and was abandoned.

Domestic United States Properties

The Company has interests in four producing wells in Brazos 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 2009, the wells produced approximately 900 bbls of oil and 6 million cubic feet of gas net to the Company. No capital expenditures are anticipated in 2010 for these properties.

Index to Financial Statements

Aggregate Production

Aggregate production data (net to the Company) for all of the Company’s operations for the years 2009, 2008, and 2007 are shown below.

Company Owned Production


	Year Ended December 31,
	2009						2008						2007
	BOE		Bbl		Mcf		BOE		Bbl		Mcf		BOE		Bbl		Mcf
Average daily production
(Oil in BOPD, gas in MCFD)
Etame field, Gabon		2,079		2,079		—		2,593		2,593		—		3,188		3,188		—
Avouma/S.Tchibala field, Gabon		1,948		1,948		—		2,385		2,385		—		1,615		1,615		—
Ebouri field, Gabon		1,275		1,275		—		—		—		—		—		—		—
Other fields		5		2		16		13		6		40		16		6		47

Total average daily production		5,307		5,304		16		4,991		4,984		40		4,819		4,809		47

Average Sales Price ($/unit)	$	59.52	$	59.54	$	4.79	$	92.81	$	92.87	$	7.51	$	71.10	$	71.16	$	6.51
Average Production Cost ($/unit)	$	11.35	$	11.35	$	1.89	$	10.11	$	10.11	$	1.69	$	8.57	$	8.57	$	1.43

RESERVE INFORMATION

In December 2008, the SEC announced that it had approved revisions designed to modernize the reserves reporting requirement of oil and natural gas companies. The most significant amendments to the requirements included the following:

•

economic producibility of reserves and discounted cash flows are now based on a 12 month average commodity price unless contractual arrangements designate the price to be used;

•

probable and possible reserves may be disclosed separately on a voluntary basis;

•

reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time;

•

reserves may be estimated through the use of reliable technology in addition to flow test and production history;

•

the Company is now required to provide disclosures about the qualifications of the chief technical person who oversees the reserves estimation process and a general discussion of its internal controls used to assure the objectivity of the reserves estimate; and

•

the definition of oil and natural gas producing activities has expanded and now focuses on the marketable product rather than the method of extraction.

The Company adopted the new requirements effective December 31, 2009.

The table below sets for the Company’s estimated net proved reserves for the years ended December 31, 2009, 2008 and 2007 as prepared by Netherland Sewell & Associates, Inc. (NSAI) 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 Securities and Exchange Commission since the beginning of the last fiscal year. The reserves are located in Gabon (offshore) and in Texas and Louisiana (onshore and offshore). Reserves estimated by our independent engineers at December 31, 2009, reflect oil and natural gas spot prices based on the average prices during the 12-month period before the ending date of the period covered by this

Index to Financial Statements

report determined as an unweighted, arithmetic average of the first-day-of-the-month price for each month within such period. Reserves estimated by our independent engineers at December 31, 2008 and 2007, reflect oil and natural gas spot prices on the last day of the year.


	As of December 31,
	2009		2008		2007
Crude Oil
Proved Developed Reserves (MBbls)
United States		4		5		8
International		4,791		4,746		4,498

Total Proved Developed Reserves (MBbls)		4,795		4,751		4,506

Proved Undeveloped Reserves (MBbls)
United States		—		—		—
International		2,568		2,671		1,708

Total Proved Undeveloped Reserves (MBbls)		2,568		2,671		1,708

Total Proved Reserves (MBbls)
United States		4		5		8
International		7,359		7,417		6,206

Total Proved Reserves (MBbls)		7,363		7,422		6,214

Natural Gas
Proved Developed Reserves (MMcf)
United States		23		30		61
International		—		—		—

Total Proved Developed Reserves (MMcf)		23		30		61

Proved Undeveloped Reserves (MMcf)
United States		—		—		—
International		—		—		—

Total Proved Undeveloped Reserves (MMcf)		—		—		—

Total Proved Reserves (MMcf)
United States		23		30		61
International		—		—		—

Total Proved Reserves (MMcf)		23		30		61

Standardized measure of proved reserves (in thousands)	$	102,518	$	64,953	$	191,669

Proved Undeveloped Reserves

The Company annually reviews all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, the Company’s PUDs are converted to proved developed reserves within five years of the date they are first booked as PUDs. The Company had 2,568 MBbls of PUDs at December 31, 2009, compared with 2,671 MBbls of PUDs at December 31, 2008. In 2009, the Company converted 1,980 MBbls or 74% of the total year-end 2008 PUDs to proved developed reserves. Approximately $22.3 million was spent in 2009 associated with development of PUDs. Of the total $22.3 million spent in 2009, the Company completed the drilling of an exploration well and two development wells in the Ebouri field offshore Gabon.

Controls Over Reserve Estimates

The Company’s policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with

Index to Financial Statements

the SEC’s regulations and GAAP. Compliance in reserves bookings is the responsibility of the Company’s principal engineer, who is the Company’s Vice President-Production. The Company’s principal engineer has over 20 years of experience in the oil and gas industry, including over 10 years as either a reserve evaluator, trainer or manager and is a qualified reserves estimator (QRE), as defined by the Society of Petroleum Engineers’ standards. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society of Petroleum Engineers for over 20 years.

The Company’s controls over reserve estimates included retaining NSAI as our independent petroleum and geological firm. The Company provided information about the Company’s oil and gas properties, including production profiles, prices and costs, to NSAI and they prepare their own estimates of the reserves attributable to our properties. All of the information regarding reserves in this annual report is derived from the report of NSAI. The report of NSAI is included as an Exhibit to this annual report.

The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. David Nice. Derek Newton has been practicing consulting petroleum engineering at NSAI since 1997. Derek is a Registered Professional Engineer in the State of Texas (License No. 97689) and has over 25 years of practical experience in petroleum engineering, with over 13 years experience in the estimation and evaluation of reserves. He graduated from University College in Cardiff, Wales in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University in Scotland in 1986 with a Master of Science Degree in Petroleum Engineering. David Nice has been practicing consulting petroleum geology at NSAI since 1998. David is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 346) and has over 25 years of practical experience in petroleum geosciences, with over 12 years experience in the estimation and evaluation of reserves. He graduated from University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The Audit Committee of the Board of Directors meets with management, including access to the Company’s principal engineer, to discuss matters and policies related to reserves.

Index to Financial Statements

The following tables set forth the net proved reserves of the Company as of December 31, 2009, 2008 and 2007, and the changes during such periods.


	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2007	5,996		17
Production	(1,756	)	(20	)
Revisions of previous estimates	1,979		64

BALANCE AT DECEMBER 31, 2007	6,214		61
Production	(1,824	)	(15	)
Revisions of previous estimates	1,242		(16	)
Extensions and discoveries	1,790		—

BALANCE AT DECEMBER 31, 2008	7,422		30
Production	(1,936	)	(6	)
Revisions of previous estimates	783		(1	)
Extensions and discoveries	1,094		—

BALANCE AT DECEMBER 31, 2009	7,363		23


	Oil (MBbls)		Gas (MMcf)
PROVED DEVELOPED RESERVES:
Balance at January 1, 2007	4,691		17
Balance at December 31, 2007	4,506		61
Balance at December 31, 2008	4,751		30
Balance at December 31, 2009	4,795		23

The Company does not book proved reserves on discoveries until such time as a development plan has been prepared and approved by 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.

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 oil and 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 gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and 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 for Gabon are recoverable under a service contract and the reserves in place remain the property of the Gabon government.

The SEC amended the definition of proved reserves for all reserve estimates included in filings after January 1, 2010. As a result, the estimates of proved reserves filed in reports prior to January 1, 2010 may not be comparable to reports filed after that date, including those in this annual report.

In accordance with the current guidelines of the Securities and Exchange 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 gas contract prices using a twelve month average price and are held constant throughout the life of the

Index to Financial Statements

properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. In Gabon, the price was $56.64 per bbl. In the United States, the price was $57.65 per bbl of oil and $3.87 per Mcf of gas. See Note 16 to the Company’s consolidated financial statements for certain additional information concerning the proved reserves of the Company.

Drilling History

The Company participated in the drilling of four exploration wells in 2009, one in the British North Sea, one in the Etame Marin block offshore Gabon and two onshore wells in the Mutamba Iroru block onshore Gabon. In 2008, the Company drilled a development well and an exploration well in the Etame Marin block. The Company participated in one exploration well during 2007-2008 in the British North Sea.


	United States						International
	Gross			Net			Gross			Net
Wells Drilled	2009	2008	2007	2009	2008	2007	2009	2008	2007	2009	2008	2007
Exploration Wells
Productive	0.0	0.0	0.0	0.0	0.0	0.0	1.0	0.0	0.0	0.30	0.00	0.00
Dry	0.0	0.0	0.0	0.0	0.0	0.0	4.0	1.0	0.0	2.55	0.25	0.00
In progress⁽¹⁾	0.0	0.0	0.0	0.0	0.0	0.0	0.0	1.0	1.0	0.00	0.30	0.25
Development Wells
Productive	0.0	0.0	0.0	0.0	0.0	0.0	2.0	0.0	0.0	0.60	0.00	0.00
Dry	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.00	0.00	0.00
In progress⁽²⁾	0.0	0.0	0.0	0.0	0.0	0.0	0.0	1.0	0.0	0.00	0.30	0.00

Total Wells	0.0	0.0	0.0	0.0	0.0	0.0	7.0	3.0	1.0	3.45	0.85	0.25

(1)	The 2008 well was drilling in the Etame Marin block at December 31, 2008 and resulted in a successful exploration test in 2009. The 2007 well was drilling in the North Sea, resulted in a dry hole and was suspended in 2008.

(2)	The well was drilling in the Etame Marin block at December 31, 2008 and was completed as a productive development well in 2009.

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, 2009:


	United States		International
	Gross	Net⁽¹⁾	Gross	Net⁽¹⁾
	(Acreage In thousands)
Developed acreage	6.7	0.8	25.0	7.0
Undeveloped acreage	0.0	0.0	2,432.8	1,062.3
Productive gas wells	1	0.1	0	0
Productive oil wells	9	1.4	8	2.2

(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 9,000 square feet), in Port Gentil, Gabon (approximately 10,000 square feet) and in Luanda, Angola (approximately 6,000 thousand 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.

[Reserved]

Index to Financial Statements

PART II

Item 5.

Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

General

The Company’s common stock is traded on the New York Exchange under the symbol EGY. The following table sets forth the range of high and low sales prices of the common stock for the periods indicated.


Period	High		Low
2008:
First Quarter	$	5.41	$	4.19
Second Quarter		8.86		5.02
Third Quarter		8.56		5.69
Fourth Quarter		7.44		3.92

2009:
First Quarter	$	8.32	$	4.92
Second Quarter		5.64		3.55
Third Quarter		5.24		3.84
Fourth Quarter		4.91		4.11

2010:
First Quarter (through February 26, 2010)	$	4.69	$	3.95

On February 26, 2010 the last reported sale price of the common stock on the New York Stock Exchange was $4.27 per share.

As of February 28, 2010 there were approximately 14,000 holders of record of the Company’s common stock.

Dividends

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

Index to Financial Statements

Performance Graph

The following graph compares the yearly percentage change in the Company’s cumulative total shareholder return on its common shares with the cumulative total return of the S&P 500 Index and the S&P/ TSX Capped Energy Index. For this purpose, the yearly percentage change in the Company’s cumulative total shareholder return is calculated by dividing (a) the sum of the dividends paid during the “measurement period,” and the difference between the price for the Company’s shares at the end and the beginning of the measurement period, by (b) the price for the Company’s common shares at the beginning of the measurement period. “Measurement period” means the period beginning at the market close on the last trading day before the beginning of the Company’s fifth preceding fiscal year, through and including the end of the Company’s most recently completed fiscal year. The Corporation first became listed on the New York Stock Exchange on October 12, 2006.

LOGO


	2004		2005		2006		2007		2008		2009
S&P/ TSX Capped Energy	$	100	$	160	$	162	$	175	$	108	$	148
S&P 500 Composite	$	100	$	103	$	117	$	121	$	75	$	92
VAALCO Energy, Inc	$	100	$	109	$	174	$	120	$	192	$	117

Index to Financial Statements

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of December 31, 2009 regarding the number of shares of common stock that may be issued under the Company’s compensation plans. Please refer to Note 4 to the consolidated financial statements for additional plan information on stock based compensation.


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	1,645,000	$	4.25	1,385,000
Equity compensation plans not approved by security holders	2,141,207	$	6.33	588,014

Total	3,786,207	$	5.42	1,973,014

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2009

The following table provides information for the quarter ended December 31, 2009 regarding the number of shares purchased by the Company.


	Number of shares purchased	Average price per share		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
October 2009	0		0	0
November 2009	624,661	$	4.48	624,661
December 2009	0		0	0

Total	624,661	$	4.48	624,661	(See note 1	)

Note 1—On June 24, 2009, the Company announced its intention to purchase up to $10 million of shares of its common stock for the treasury. Purchases may be made in both the open market and through negotiated transactions from time-to-time during the authorized 12 month period. Purchases may be increased, decreased or discontinued at any time without prior notice. The Company has purchased 2,327,779 shares on the open market at an average price of $4.30 per share totaling $10 million since this announcement.

Index to Financial Statements

Item 6.

Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2009 has been derived from the Company’s Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of the Company’s future results.


	Years Ended December 31,
	2009			2008		2007		2006⁽¹⁾		2005
	(In thousands, except per share amounts)
Total revenues	$	115,298		$	169,525	$	125,044	$	98,325	$	84,935
Income (loss) from continuing operations	$	(4,144	)	$	35,733	$	23,532	$	45,759	$	32,898
Net income (loss) attributable to VAALCO Energy Inc.	$	(7,889	)	$	29,722	$	19,103	$	40,343	$	29,182
Basic income (loss) per common share from continuing operations	$	(0.14	)	$	0.51	$	0.32	$	0.69	$	0.56
Diluted income (loss) per common share from continuing operations	$	(0.14	)	$	0.50	$	0.32	$	0.67	$	0.50
Total assets	$	202,999		$	252,030	$	186,558	$	167,942	$	98,162
Total debt	$	0		$	5,000	$	5,000	$	5,000	$	1,500

(1)	With effect from January 1, 2006, the Company adopted FASB Topic—Stock Compensation resulting in expense of $1.1 million in 2006, $2.2 million in 2007, $2.6 million in 2008 and $1.8 million in 2009.

Index to Financial Statements

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results 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 operates the Etame, Avouma, South Tchibala and Ebouri fields on behalf of a consortium of five companies offshore of the Republic of Gabon. Production commenced from the Etame field in 2002 and was subsequently expanded through additional development wells in 2004 and 2005. In 2006, the Company developed the Avouma and South Tchibala fields by setting a platform and tying the field back to the FPSO via a pipeline. Oil production commenced from the Avouma and South Tchibala fields in January 2007. Oil production began in January 2009 from the Ebouri field utilizing a platform that was installed in August 2008 and connected to the FPSO by pipeline.

Impact of the Current Financial and Credit Markets

The U.S. and other international economies experienced a recession, the effects of which could last well into 2010 and beyond. Additionally, the financial and credit markets have experienced unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. The Company’s exposure to the disruptions in the financial markets includes the ability to access the capital markets and investments exposure.

The Company does not currently have a credit facility. If in the future the Company determines that it needs a credit facility and the disruption in the financial markets continues or recurs, replacement of the credit facility may be more expensive.

Current market conditions also elevate concerns with the Company’s cash investments (including funds in escrow), which at December 31, 2009 totaled $97.0 million. The Company has reviewed the creditworthiness of the banks and financial institutions with which the Company maintains investments as well as the securities underlying these investments. With regard to the Company’s cash investments, the Company invests in bankers acceptances and money market instruments primarily with JPMorgan Chase & Co., which the Company believes to be creditworthy.

Beginning January 2010, the Company’s production in Gabon is purchased by Vitol, which the Company believes to be a creditworthy purchaser.

Oil and gas prices are also volatile as evidenced by the significant changes during 2008 and 2009. If experienced, lower commodity prices will reduce the Company’s cash flows from operations.

CRITICAL ACCOUNTING POLICIES

The following describes the critical accounting policies used by the Company 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 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, the Company has chosen to follow the successful

Index to Financial Statements

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. 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 method of accounting, 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 contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field.

Impairment of Unproved Property

The Company evaluates its unproved properties for impairment on a property-by-property basis. The majority of the Company’s unproved property consists of acquisition costs related to its undeveloped acreage in Angola. On at least a quarterly basis, management reviews the unproved property for indicators of impairment based on the Company’s current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration activity by other companies on adjacent blocks. See Item 2—Properties and Note 7 to the Consolidated Financial Statements for further information on the Company’s exploration plans in Angola. Any adverse developments related to the Company’s ability to extend the drilling obligation date could result in an impairment of the Company’s unproved properties and other assets of approximately $11.4 million as well as the loss of the funds the Company has escrowed to secure its drilling obligations of $10 million.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2009 was $23.5 million, as compared to $106.6 million in 2008 and $43.2 million in 2007. The decrease in cash provided by operations was primarily due to a net loss incurred in 2009 versus net income in 2008 and less favorable changes in working capital other than cash. The increase in 2008 compared to 2007 was primarily due to higher net income and more favorable changes in working capital other than cash.

Net cash used in investing activities in 2009 was $49.0 million, compared to net cash used in investing activities for 2008 of $42.4 million and net cash used in investing activities in 2007 of $22.6 million. In 2009, the Company invested $22.3 million primarily for the Ebouri platform and three wells. The Company incurred $33.4 million in dry hole costs and reduced the amount in escrow attributable to a well drilled in the British North Sea by $6.6 million. In 2008, the Company invested $25.7 million primarily for the development of the Ebouri field, FPSO upgrades and onshore Gabon drilling activities. The Company incurred $9.2 million in dry hole costs, and placed $7.4 million in escrow for a well to be drilled in the British North Sea. In 2007, the Company invested $14.5 million in the Etame Marin block operations for the development of the Avouma, South Tchibala and Ebouri fields and drilled a dry well in the North Sea at a cost of $8.1 million.

In 2009, cash used in financing activities was $19.4 million, consisting primarily of purchase of treasury shares of $10.1 million, debt repayment of $5.0 million and distributions to a noncontrolling interest owner of $6.0 million partially offset by proceeds from the issuance of common stock of $1.8 million. In 2008, cash used in financing activities was $15.2 million, consisting of distributions to a noncontrolling interest owner of $6.5 million and

Index to Financial Statements

purchase of treasury shares of $8.9 million. In 2007, cash used in financing activities was $5.2 million, consisting of distributions to a noncontrolling interest owner of $4.0 million and purchase of treasury shares of $2.3 million which was partially offset by proceeds from the issuance of common stock of $1.1 million.

Capital Expenditures

The Company invested $22.3 million in property and equipment additions (including amounts carried in accounts payable and excluding exploration dry hole costs), primarily associated with the drilling of the three wells in the Ebouri field (the appraisal well plus the two development wells drilled from the Ebouri platform) totaling $16.7 million. Additionally, the Company’s share of the leasehold bonus associated with the Etame Marin block exploration period extension totaled $1.4 million. Partially offsetting these additions was a realignment agreement with a joint venture partner that originally did not participate in an appraisal well and one of the development wells in the Ebouri field. Pursuant to the realignment agreement, the joint venture partner paid its proportionate share of capital expenditures for the wells, which reduced the Company’s property and equipment by $5.7 million. During 2008, the Company spent approximately $25.7 million consisting primarily of Ebouri field development costs of $18.2 million, and drilling inventory ($1.4 million). Other expenditures during the year were for FPSO upgrades ($2.0 million), onshore Gabon ($2.2 million) and a well in the British North Sea ($0.8 million). During 2007, the Company spent approximately $14.5 million for the development of the Avouma and South Tchibala fields ($6.0 million) and for the development of the Ebouri field ($8.5 million).

In 2009, the Company incurred $36.5 million in exploration expense including $33.4 million of dry hole costs (British North Sea—$9.6 million, the Etame Marin block offshore Gabon—$3.0 million and the Mutamba Iroru block onshore Gabon—$20.8 million). The Company spent the remaining $3.1 million primarily on seismic processing costs in the Etame Marin block ($0.6 million), Mutamba Iroru block ($0.9 million) and in Angola ($1.4 million). In 2008, the Company spent $14.9 million in exploration expense including $9.2 million of unsuccessful well costs (British North Sea—$6.4 million, offshore Gabon—$0.3 million and onshore Gabon—$2.5 million), $3.5 million to acquire and process seismic in Angola, $1.1 million for aeromagnetic gravity data acquired over the Mutamba Iroru block onshore Gabon and seismic acquisition and processing costs associated with the Etame Marin block of $0.7 million. In 2007, the Company spent $15.3 million to acquire and process seismic in Angola ($4.3 million), to acquire and process seismic in Gabon ($2.6 million), to drill an unsuccessful exploration well in the British North Sea ($8.1 million) and for other seismic costs in the North Sea ($0.3 million).

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. On December 31, 2009, the Company had cash balances of $80.6 million and funds in escrow of $16.4 million. The Company believes that the cash balances combined with cash flow from operations will be sufficient to fund the Company’s 2010 capital expenditure budget, which is expected to range from $25.0 million to $35.0 million to further develop the Etame Marin block and $5.0 million projected for the beginning of the drilling project in Angola. The Company invests cash, not required for immediate operational and capital expenditure needs, in short-term bankers acceptance and money market instruments primarily with JPMorgan Chase & Co. The Company does not invest in asset-backed commercial paper market which has been subject to a liquidity crisis over the last year. As operator of the Etame, Avouma, South Tchibala and Ebouri fields the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from its partners prior to significant funding commitments.

In June 2005, the Company executed a loan agreement for a $30.0 million revolving credit facility secured by the assets of the Company’s Gabon subsidiary. The facility was available to finance the Ebouri field development activities and other Etame Marin block activities. The facility extended until October 2009 at which point it could be extended by mutual agreement, and the loan drawdown amount could be converted to a term loan at the Company’s option. Because of the Company’s limited use of the facility, the IFC elected to not extend the credit facility. The Company elected to not convert the loan balance to a term loan and instead repaid the loan balance of $5.0 million plus interest in mid-October 2009.

Index to Financial Statements

Contractual Obligations

The table below summarizes the Company’s obligations and commitments at December 31, 2009:

Payment Period


(in thousands $)	2010		2011		2012		2013		2014		Thereafter		Total
Operating leases⁽¹⁾	$	14,432	$	8,106	$	8,190	$	4,758	$	4,726	$	3,264	$	43,476

(1)

The Company is Guarantor of a lease for the FPSO utilized in Gabon, which has remaining obligations of $96.3 million. The Company’s share of these payments is included in the table above. The Company can cancel the lease anytime after September 14, 2015, with 12 months prior notice. Approximately 72% of the payment is co-guaranteed by the Company’s partners in Gabon.

In addition to the contractual obligations described above, the Company entered into a sixth exploration period extension during 2009 and is required to spend $5.3 million for its share of two exploration wells and acquire/process 150 sq km of 3-D seismic on the Etame Marin block by July 2014. The Company entered into the second exploration period for the Mutamba Iroru block which requires the Company to acquire/process 200 kilometers of 2-D seismic, without a specified monetary commitment, by May 2011. In addition, the Company is required to spend $10.0 million for its share of two exploration wells on Block 5 in Angola by November 30, 2010; however, the Company has begun the process of acquiring the interest of its non-performing partner and is working with the government of Angola regarding a time extension for the drilling of the commitment wells. While we believe that the government of Angola will grant us an extension, we can provide no assurances. Any adverse developments related to the Company’s ability to extend the drilling obligation date could result in an impairment of the Company’s unproved properties and other assets of approximately $11.4 million as well as the loss of the funds the Company has escrowed to secure its drilling obligations of $10 million. If we are successful in obtaining such extension, the Company estimates the drilling will take place in the first half of 2011 on this block in Angola.

The Company is carrying $10.7 million of asset retirement obligations as of December 31, 2009, representing the present value of these obligations as of that date. The Company does not anticipate incurring expenditures for any material asset retirement obligations over the next five years.

RESULTS OF OPERATIONS

Year Ended December 31, 2009 Compared to Years Ended December 31, 2008 and 2007

Revenues

Total oil and gas sales for 2009 were $115.3 million as compared to $169.5 million and $125.0 million for 2008 and 2007, respectively. In 2009, the Company sold approximately 1,935,000 bbls at an average price of $59.54 per bbl from the Etame Marin block. Revenues from the United States were $0.1 million. In 2008, the Company sold approximately 1,822,000 bbls at an average price of $92.87 per bbl from the Etame Marin block. Revenues from the United States were $0.3 million. In 2007, the Company sold approximately 1,753,000 net bbls at an average price of $71.16 per bbl from the Etame field in Gabon. Revenues from the United States were $0.3 million. Crude oil sales are a function of the number and size of crude oil liftings from the FPSO and thus crude oil sales do not always coincide with oil volumes produced.

Operating Costs and Expenses

Production expense for 2009 was $22.0 million as compared to $18.5 million and $15.1 million for 2008 and 2007, respectively. Production expenses were higher in 2009 primarily due to higher sales volumes, and higher FPSO costs. The Company matches production expenses with crude oil sales. Any production expenses

Index to Financial Statements

associated with unsold crude oil inventory are capitalized. In 2008, operating expenses increased versus 2007 due to increased volumes sold (17 liftings in 2008 versus 14 liftings in 2007) as well as higher boat rental costs, higher FPSO costs, higher helicopter costs and higher fuel costs.

Exploration cost for 2009 was $36.5 million as compared to $14.9 million and $15.3 million for 2008 and 2007, respectively. In 2009, the Company spent $33.4 million on four unsuccessful exploration wells including the North Etame prospect offshore Gabon ($3.0 million), two wells on the Matumba Iroru block onshore Gabon ($20.8 million) and a well on Block 48/25c in the British North Sea ($9.6 million). Additionally, the Company spent $3.1 million primarily associated with seismic processing costs in Block 5 in Angola and the Mutamba Iroru block in Gabon.

In 2008, the Company spent $9.2 million on unsuccessful exploration wells including the remaining costs of a well in the British North Sea ($6.4 million), plus two wells drilled in early 2009 in Gabon and determined to be unsuccessful ($2.8 million). On both of the wells, the costs incurred as of December 31, 2008 were charged to expense. Additionally, the Company spent $3.0 million for acquiring 524 square kilometers of 3-D seismic in Angola in 2008. Also included in exploration expenses in 2008 were aeromagnetic gravity data acquired over the Mutamba Iroru block, seismic acquisition and processing costs associated with the Company’s Etame Marin block and seismic processing costs in Angola. In 2007, amounts were spent to acquire and process seismic in Angola ($4.3 million), to acquire and process seismic in Gabon ($2.6 million), to drill an unsuccessful exploration well in the British North Sea ($8.1 million) and for other seismic costs in the North Sea ($0.3 million).

Depreciation, depletion and amortization expense was $20.8 million for 2009, and was $18.9 million and $18.0 million for 2008 and 2007, respectively. Depletion, depreciation and amortization expense increased in 2009 versus 2008, and 2008 versus 2007 primarily due to higher production volumes in both comparative periods. In 2009, depletion rates for the Ebouri field averaged $19.73 per bbl, Avouma and South Tchibala fields averaged $7.32 per bbl, and the Etame field averaged $4.30 per bbl. For comparison, the average 2008 depletion rate for the Avouma and South Tchibala fields was $16.01 per bbl and the average depletion rate for the Etame field averaged $4.98 per bbl.

General and administrative expense for 2009 was $9.6 million as compared to $10.8 million and $8.0 million for 2008 and 2007, respectively. General and administrative expense decreased in 2009 versus 2008 due in part to prior year non-recurring legal and solicitation costs associated with corporate matters relating to the Company’s annual meeting. Included in the general and administrative expenses for 2009 was an expense for retirement benefits of $1.5 million which was partially offset by a retroactive compensation adjustment of $0.9 million that benefited the Company by charging the adjustment to the Gabon partners. During 2009, the Company incurred $1.8 million of stock based compensation compared to $2.6 million incurred in 2008 and $2.2 incurred in 2007. The increase in general and administrative expense for 2008 versus 2007 was attributable to the non-recurring legal and solicitation costs explained above plus a full year of operating the Company office in Angola ($1.2 million). In each of the three years, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block.

Other operating income for 2009 was $6.5 million. For 2008 and 2007, no amounts were recorded for other operating income. The other operating income recorded in 2009 was attributable to receipt of proceeds from a joint venture partner that originally elected to not participate in two wells drilled in the Ebouri field, offshore Gabon. The partner later elected to participate and paid for their proportionate share of the capital expenditures for the wells. The $6.5 million payment received represents the Company’s share of an agreed risk premium benefiting the joint venture partners that originally participated in those two wells.

Operating Income

Operating income for 2009 was $33.0 million as compared to a $106.5 million and $68.7 million for 2008 and 2007, respectively. The significant decrease in operating income in 2009 versus 2008 is primarily attributable to the lower average crude sales price of $59.54 per bbl, a decrease of $33.33 per bbl or

Index to Financial Statements

36%, and higher exploration costs for unsuccessful exploratory wells. Also, partially contributing to the decrease in operating income were higher operating expenses and depletion expense.

The increase in operating income in 2008 versus 2007 is attributable to the higher average crude sales price of $92.87 per barrel, an increase of $21.71 per bbl, which was partially offset by increased fuel-related operating costs and depletion.

Other Income (Expense)

Interest income for 2009 was $0.7 million as compared to $2.5 million and $3.9 million in 2008 and 2007, respectively. All the 2009, 2008, and 2007 amounts represent interest earned and accrued on cash balances and funds in escrow. Extremely low interest rates in 2009 versus 2008 account for the decrease in interest income.

Interest expense of $0.5 million was recorded in 2009 as compared to $0.2 million and $1.1 million in 2008 and 2007, respectively. Interest in all three years was associated with the financings from the IFC for use on Etame Marin block activities. The increase in interest expense in 2009 compared to 2008 is attributable to a decrease in the amount of loan interest that could be capitalized.

Other expense of $0.5 million recorded in 2009 was primarily associated with foreign exchange losses. Other expense was negligible in 2008, and in 2007, other income of $0.1 million was attributable to foreign exchange gains.

Income Taxes

In 2009, the Company incurred $36.9 million of income taxes compared to $73.0 million incurred in 2008 which were associated with the Etame Marin block production, and which were paid in Gabon. In 2007, the Company incurred $48.1 million of income taxes associated with the Etame field production, which were paid in Gabon. The decreased tax in Gabon in 2009 versus 2008 was due to lower crude oil sales prices in 2008, which was partially offset by higher sales volumes. Also a larger percentage of crude was subject to taxation in 2009 as part of profit oil versus cost oil.

Loss from Discontinued Operations

No amounts were recorded in 2009 or 2008 related to discontinued operations. In 2007, the loss from discontinued operations in the Philippines was $51,000 as the Company achieved the final closeout of the branch offices.

Net Income (Loss)

The net loss for 2009 was $4.1 million as compared to a net income of $35.7 million and net income of $23.5 million in 2008 and 2007, respectively. The decrease in 2009 versus 2008 is attributable primarily to the unsuccessful exploration well costs and lower crude oil sales prices. The net income increase in 2008 versus 2007 is attributable to increased sales volumes and oil prices partially offset by higher costs, primarily fuel-related costs and depletion.

Income attributable to the noncontrolling interest in the Gabon subsidiary was $3.7 million, $6.0 million and $4.4 million in 2009, 2008, and 2007, respectively.

NEW ACCOUNTING PRONOUNCEMENTS

For a discussion of new accounting pronouncements, see Note 3 to the consolidated financial statements.

Index to Financial Statements

OFF BALANCE SHEET ARRANGEMENTS

For a discussion of off balance sheet arrangements associated with the guarantee by the Company of the charter payments for the FPSO located in Gabon, see Note 7 to the consolidated financial statements.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Market Risk

The Company’s major market risk exposure continues to be the prices applicable to its oil and gas production. Sales prices are primarily driven by the prevailing market price. Historically, prices received for oil and gas production have been volatile and unpredictable.

Foreign Exchange Risk

Interest Rate Risk

At December 31, 2009 the Company did not have any debt and thus no exposure to interest rate risk.

Commodity Price Risk

The Company had no derivatives in place as of the date of this report, or in 2009, 2008 or 2007.

Item 8.

Financial Statements and Supplementary Data

The information required here is included in the report as set forth in the “Index to Consolidated Financial Information” on page F-1.

Item 9.

Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.

Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures.

The Company maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by the Company in the reports it file or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosure. 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-K. Based on that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s

Index to Financial Statements

disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-K. There were no changes in the Company’s internal controls over financial reporting that occurred during the Company’s last year that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive and principal financial officers, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework which was completed on March 16, 2010, management concluded that its internal control over financial reporting was effective as of December 31, 2009.

The Company’s internal control over financial reporting as of December 31, 2009 has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audited the Company’s consolidated financial statements as of and for the year ended December 31, 2009, as stated in their report which follows.


By:		/s/ ROBERT L. GERRY, III
		Robert L. Gerry, III,
		Chairman of the Board, Chief Executive Officer and Director


By:		/s/ GREGORY R. HULLINGER
		Gregory R. Hullinger
		Chief Financial Officer

Changes in Internal Control Over Financial Reporting

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) occurred during the fourth quarter of our fiscal year ended December 31, 2009 that has materially affected, or is reasonable likely to materially affect, our internal control over financial reporting.

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Houston, Texas

We have audited the internal control over financial reporting of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2009 of the Company, and our report March 16, 2010 expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph related to the adoption of new accounting guidance in 2009 related to the estimation of oil and gas reserves and the presentation of noncontrolling interest in the consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 16, 2010

Index to Financial Statements

Item 9B.

Other Information

The Company has disclosed all information required to be disclosed in a current report on Form 8-K during the year ended December 31, 2009 in previously filed reports on Form 8-K.

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

Information required by this item will be included in the Company’s proxy statement for its 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference.

Item 11.

Executive Compensation

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this Item 403 of Regulation S-K concerning the security ownership of certain beneficial owners and management will be included in the Company’s proxy statement for its 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference. Please see “Item 5 Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities” information on securities that may be issued under the Company’s stock incentive plans.

Item 13.

Certain Relationships, Related Transactions and Director Independence

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 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference.

Index to Financial Statements

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(a)

1. The following is an index to the financial statements that are filed as part of this Form 10-K.


VAALCO ENERGY, INC. AND SUBSIDIARIES

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets December 31, 2009 and 2008		F-3

Statements of Consolidated Operations Years ended December 31, 2009, 2008 and 2007		F-4

Statements of Consolidated Equity Years ended December 31, 2009, 2008 and 2007		F-5

Statements of Consolidated Cash Flows Years ended December 31, 2009, 2008 and 2007		F-6

Notes to the Consolidated Financial Statements		F-7

(a)

2. Schedules are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto.

(a)

3. Exhibits:

Articles of Incorporation and Bylaws



3.1(a)		Restated Certificate of Incorporation

3.2(a)		Certificate of Amendment to Restated Certificate of Incorporation

3.3(k)		Amended and Restated Bylaws

10.

Material Contracts



10.1(b)		Indemnity Agreement entered into among the Company and certain of its officers and directors listed therein.

10.2(c)		Exploration and Production Sharing contract between the Republic of Gabon and VAALCO Gabon (Etame), Inc. dated July 7, 1995.

10.3(c)		Deed of Assignment and Assumption between VAALCO Gabon (Etame), Inc., VAALCO Energy (Gabon), Inc. and Petrofields Exploration & Development Co., Inc. dated September 28, 1995.

10.4(d)		Letter of Intent for Etame Marin block, Offshore Gabon dated January 22, 1998 between the Company and Western Atlas International, Inc.

10.5(e)		2001 Stock Incentive Plan dated August 16, 2001.

10.6(f)		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.

10.7(g)		2003 Stock Incentive Plan dated December 16, 2003.

Index to Financial Statements



10.8(h)		Exploration and Production Sharing contract between the Republic of Gabon and VAALCO Production (Gabon), Inc., Permit Mutamba Iroru dated November 11, 2005.

10.9(i)		Loan Agreement between VAALCO Gabon (Etame), Inc. and International Finance Corporation dated June 13, 2005.

10.10(j)		2007 Stock Incentive Plan dated May 1, 2007.

10.11(l)		Settlement Agreement, dated as of May 23, 2008 by and among the Company and Nanes Delorme Partners I LP, Nanes Balkany Partners LLC, Nanes Balkany Management LLC, Julien Balkany and Daryl Nanes.

21.

Subsidiaries of the Company



21.1		Subsidiaries of the Registrant

23.

Consents of Experts and Counsel



23.1		Consent of Deloitte & Touche LLP

23.2		Consent of Netherland Sewell & Associates, Inc.

31.

Rule 13a-14(a) Certifications



31.1		Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002

32.

Section 1350 Certifications



32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.

Reserve Report



99.1		Report of Netherland Sewell & Associates, Inc.

(a)	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.

(b)	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.

(c)	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.

Index to Financial Statements

(d)	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.

(e)	Filed as an exhibit to the Company’s Registration Statement Form S-8 filed with the Commission on August 18, 2001, and incorporated by reference herein.

(f)	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.

(g)	Filed as an exhibit to Form10-KSB for the annual period ended December 31, 2004, and hereby incorporated by reference herein.

(h)	Filed as an exhibit to Form 10-K for the annual period ended December 31, 2005, and hereby incorporated by reference herein.

(i)	Filed as an exhibit to the Company’s Report on Form 8-K filed with the Commission on February 21, 2006, and hereby incorporated by reference herein.

(j)	Filed as an exhibit to the Company’s Registration Statement Form S-8 filed with the Commission on July 25, 2007 and hereby incorporated by reference herein.

(k)	Filed as an exhibit to Company’s Report on Form 8-K filed with the Commission on December 12, 2007, and hereby incorporated by reference herein.

(l)	Filed as an exhibit to Company’s Report on Form 8-K filed with the Commission on May 28, 2008, and hereby incorporated by reference herein.

Index to Financial Statements

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/ GREGORY R. HULLINGER
		Gregory R. Hullinger Chief Financial Officer

Dated March 16, 2010

In accordance with the Exchange Act, this report has been signed below on the 16th 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 Operating Officer And Director

By:	/s/ GREGORY R. HULLINGER Gregory R. Hullinger	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

By:	/s/ ROBERT H. ALLEN Robert H. Allen	Director

By:	/s/ LUIGI CAFLISCH Luigi Caflisch	Director

By:	/s/ O. DONALD CHAPOTON O. Donald Chapoton	Director

By:	/s/ WILLIAM S. FARISH William S. Farish	Director

By:	/s/ ARNE R. NIELSEN Arne R. Nielsen	Director

By:	/s/ FREDERICK W. BRAZELTON Frederick W. Brazelton	Director

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL INFORMATION


VAALCO ENERGY, INC. AND SUBSIDIARIES

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets December 31, 2009 and 2008		F-3

Statements of Consolidated Operations Years ended December 31, 2009, 2008 and 2007		F-4

Statements of Consolidated Equity Years ended December 31, 2009, 2008 and 2007		F-5

Statements of Consolidated Cash Flows Years ended December 31, 2009, 2008 and 2007		F-6

Notes to the Consolidated Financial Statements		F-7

F-1

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Houston, Texas

We have audited the accompanying consolidated balance sheets of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related statements of consolidated operations, equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’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 examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of VAALCO Energy, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company adopted new accounting guidance in 2009 related to the estimation of oil and gas reserves and the presentation of noncontrolling interest in the consolidated financial statements.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 16, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 16, 2010

F-2

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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


	December 31, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	80,570		$	125,425
Funds in escrow		5,572			7,445
Receivables:
Trade		8,175			9,513
Accounts with partners		13,558			3,796
Other		5,171			2,074
Crude oil inventory		286			1,381
Materials and supplies		160			425
Prepayments and other		1,217			2,351

Total current assets		114,709			152,410

Property and equipment—successful efforts method:
Wells, platforms and other production facilities		137,122			84,693
Undeveloped acreage		13,252			12,841
Work in progress		1,784			43,288
Equipment and other		3,668			2,844

		155,826			143,666
Accumulated depreciation, depletion and amortization		(80,260	)		(61,379	)

Net property and equipment		75,566			82,287

Other assets:
Deferred tax asset		1,349			1,349
Funds in escrow		10,873			15,637
Other long term assets		502			347

Total Assets	$	202,999		$	252,030

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	33,728		$	57,773
Accounts with partners		—			5,394

Total current liabilities		33,728			63,167

Long term debt		—			5,000
Asset retirement obligations		10,666			10,071
Other liabilities		1,500			—

Total liabilities		45,894			78,238

VAALCO Energy Inc. shareholders’ equity:
Common stock, $0.10 par value, 100,000,000 authorized shares, 61,809,024 and 61,116,324 shares issued with 5,453,942 and 2,860,642 shares in treasury at Dec. 31, 2009 and 2008, respectively		6,157			6,112
Additional paid-in capital		57,550			53,983
Retained earnings		109,249			117,205
Less treasury stock, at cost		(21,515	)		(11,422	)

Total VAALCO Energy Inc. shareholders’ equity		151,441			165,878
Noncontrolling interest		5,664			7,914

Total Equity		157,105			173,792

Total Liabilities and Equity	$	202,999		$	252,030

See notes to consolidated financial statements.

F-3

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

(in thousands of dollars, except per share amounts)


	Year Ended December 31,
	2009			2008			2007
Revenues:
Oil and gas sales	$	115,298		$	169,525		$	125,044

Operating costs and expenses:
Production expense		21,978			18,468			15,080
Exploration expense		36,464			14,872			15,340
Depreciation, depletion and amortization		20,760			18,937			17,952
General and administrative expense		9,580			10,776			7,999
Other operating income		(6,503	)		—			—

Total operating costs and expenses		82,279			63,053			56,371

Operating income		33,019			106,472			68,673
Other income (expense):
Interest income		654			2,520			3,928
Interest expense		(450	)		(240	)		(1,094	)
Other, net		(465	)		(5	)		106

Total other income (expense)		(261	)		2,275			2,940

Income before income taxes		32,758			108,747			71,613
Income tax expense		36,902			73,014			48,081

Income (loss) from continuing operations		(4,144	)		35,733			23,532
Loss from discontinued operations, net of tax		—			—			(51	)

Net income (loss)		(4,144	)		35,733			23,481
Less net income attributable to noncontrolling interest		(3,745	)		(6,011	)		(4,429	)

Net income (loss) attributable to VAALCO Energy, Inc.	$	(7,889	)	$	29,722		$	19,052

Earnings per share—basic:
Income (loss) per share from continuing operations	$	(0.14	)	$	0.51		$	0.32
Loss per share from discontinued operations		—			—			—

Basic net income (loss) per share atributable to VAALCO Energy, Inc.	$	(0.14	)	$	0.51		$	0.32

Earnings per share—diluted:
Income (loss) per share from continuing operations	$	(0.14	)	$	0.50		$	0.32
Loss per share from discontinued operations		—			—			—

Diluted net income (loss) per share attributable to VAALCO Energy, Inc.	$	(0.14	)	$	0.50		$	0.32

Basic weighted shares outstanding		57,407			58,676			59,134

Diluted weighted average shares outstanding		57,407			59,287			60,091

See notes to consolidated financial statements.

F-4

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED EQUITY

(in thousands of dollars)


	VAALCO Energy, Inc. Shareholders										Noncontrolling Interest			Total
	Common Stock		Additional Paid-In Capital		Retained Earnings			Treasury Stock			Noncontrolling Interest			Total
Balance at January 1, 2007	$	6,006	$	48,093	$	68,431		$	(266	)	$	7,963		$	130,227

Proceeds from stock issuance		99		1,023		—			—			—			1,122
Stock based compensation		—		2,178		—			—			—			2,178
Treasury stock purchase		—		—		—			(2,286	)		—			(2,286	)
Net income		—		—		19,052			—			4,429			23,481
Distribution to noncontrolling interest		—		—		—			—			(3,996	)		(3,996	)

Balance at December 31, 2007		6,105		51,294		87,483			(2,552	)		8,396			150,726

Proceeds from stock issuance		7		123		—			—			—			130
Stock based compensation		—		2,566		—			—			—			2,566
Treasury stock purchase		—		—		—			(8,870	)		—			(8,870	)
Net income		—		—		29,722			—			6,011			35,733
Distribution to noncontrolling interest		—		—		—			—			(6,493	)		(6,493	)

Balance at December 31, 2008		6,112		53,983		117,205			(11,422	)		7,914			173,792

Proceeds from stock issuance		45		1,726		—			—			—			1,771
Stock based compensation		—		1,841		—			—			—			1,841
Treasury stock purchase		—		—		—			(10,093	)		—			(10,093	)
Net income (loss)		—		—		(7,889	)		—			3,745			(4,144	)
Redemption of rights agreement		—		—		(67	)		—			—			(67	)
Distribution to noncontrolling interest		—		—		—			—			(5,995	)		(5,995	)

Balance at December 31, 2009	$	6,157	$	57,550	$	109,249		$	(21,515	)	$	5,664		$	157,105

See notes to consolidated financial statements.

F-5

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(in thousands of dollars)


	Year Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(4,144	)	$	35,733		$	23,481
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		20,760			18,937			17,952
Amortization of debt issuance costs		—			125			556
Unrealized foreign exchange gain		(316	)		—			—
Dry hole costs		33,373			9,217			8,053
Stock based compensation		1,841			2,566			2,178
Change in operating assets and liabilities:
Trade receivables		1,338			10,253			(12,158	)
Accounts with partners		(15,156	)		5,427			1,711
Other receivables		(3,159	)		(428	)		(313	)
Crude oil inventory		1,095			(454	)		(367	)
Materials and supplies		265			(86	)		(15	)
Deferred tax asset		—			108			(200	)
Other long term assets		(155	)		(117	)		243
Prepayments and other		1,185			(189	)		910
Accounts payable and other liabilities		(13,434	)		25,686			1,001
Income taxes payable		—			(200	)		200

Net cash provided by operating activities		23,493			106,578			43,232

CASH FLOWS FROM INVESTING ACTIVITIES
Decrease (increase) in funds in escrow, net		6,637			(7,447	)		(28	)
Property and equipment expenditures		(61,340	)		(34,922	)		(22,573	)
Reimbursement of property and equipment expenditures by partner		5,737			—			—

Net cash used in investing activities		(48,966	)		(42,369	)		(22,601	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		1,771			130			1,122
Debt repayment		(5,000	)		—			—
Purchase of treasury shares		(10,093	)		(8,870	)		(2,286	)
Redemption of rights agreement		(66	)		—			—
Distribution to noncontrolling interest		(5,994	)		(6,494	)		(3,996	)

Net cash used in financing activities		(19,382	)		(15,234	)		(5,160	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		(44,855	)		48,975			15,471
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		125,425			76,450			60,979

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	80,570		$	125,425		$	76,450

Supplemental disclosure of cash flow information
Cash paid for Income taxes	$	34,438		$	72,812		$	50,016

Cash paid for Interest	$	599		$	633		$	523

Supplemental disclosure of non cash flow information
Property and equipment additions incurred during the period but not paid at period end	$	4,363		$	8,184		$	(3,783	)

See notes to consolidated financial statements.

F-6

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 and Angola and as a non-operator in the British North Sea. Domestically, the Company has interests in the Texas and Louisiana Gulf Coast area. In Gabon and Angola, VAALCO serves as the operator for groups of companies which own the working interest in the production sharing contract, collectively referred to as a consortium.

VAALCO’s active subsidiaries include VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc., VAALCO Energy (USA), Inc. and VAALCO (UK) North Sea, Limited.

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 noncontrolling interest in the majority-owned operations of the Company’s Gabon subsidiary is reflected as noncontrolling interest. All 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 and cash equivalents.

Funds in Escrow—Escrow cash includes cash that is contractually restricted. Restricted cash and cash equivalents are classified as a current or non-current asset based on their designated purpose. Current amounts at December 31, 2009 represent an escrow account securing the Company’s seismic obligations in Angola which have already been conducted. This escrow amount is expected to be released in 2010. Long term amounts at December 31, 2009 represent amounts to secure the Company’s drilling obligation in Block 5 in Angola ($10.0 million), 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 ($44 thousand).

The current amount at December 31, 2008 represented an escrow securing the Company’s obligation for drilling a well in the British North Sea which was released in 2009. The long term amounts at December 31, 2008 are for the same items as in 2009 except the Angola seismic obligation escrow amount was included as long term in 2008.

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.

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 produced and stored on the FPSO, but unsold. Inventory cost represents the production expenses including 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.

F-7

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Property and Equipment—The Company follows the successful efforts method of accounting for exploration and development costs. Under this method, exploration costs, other than the cost of exploratory wells, are charged to expense as incurred. Exploratory well costs are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved reserves, the associated costs are expensed at that time. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred. All development costs, including developmental dry hole costs, are capitalized.

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing the corresponding cost as part of the carrying amount of the long-lived assets.

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. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors.

Depletion of wells, platforms, other production facilities and leaseholds are provided on a field basis under the unit-of-production method based upon estimates of proved developed reserves. 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

Foreign Exchange Transactions—For financial reporting purposes, the subsidiaries use the United States Dollar as their functional currency. Gains and losses on foreign currency transactions are included in income currently. The Company incurred a loss on foreign currency transactions of $493,000 in 2009, compared to a loss of $42,000 in 2008, and a gain of $105,000 in 2007.

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. and VAALCO Angola (Kwanza), Inc.

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

Stock Based Compensation—The Company measures 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. Grant date fair value is 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 is 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 Company estimates the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur.

Fair Value of Financial Instruments—The Company’s financial instruments consist primarily of cash, funds in escrow, trade receivables, trade payables and debt. The book values of cash, trade receivables, and trade

F-8

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

payables are representative of their respective fair values due to the short-term maturity of these instruments. As of December 31, 2008, the book value of the Company’s debt instruments were considered to approximate the fair value, as the interest rates were adjusted based on rates currently in effect.

Risks and Uncertainties—The Company’s interests are located overseas in certain onshore and offshore areas in Gabon, offshore in Angola and the British North Sea and in Texas and Louisiana.

Substantially all of the Company’s crude oil and natural gas is sold at posted or index prices under short-term contracts, as is customary in the industry.

In Gabon, effective January 1, 2010, the Company sells crude oil under a contract with Vitol S.A. In 2009, Total Oil Trading S.A. and in 2008, Shell Western Supply and Trading Limited were the crude oil buyers in Gabon and accounted for all of the Company’s revenues in Gabon for those years. While the loss of the Company’s 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 types of contracts, one for oil and one for gas. The Company has access to several alternative buyers for oil and gas sales domestically.

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.

Estimates of oil and gas reserves used in the financial statements to estimate depletion expense require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. The Company considers its estimates to be reasonable; however, due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available.

3.	RECENT ACCOUNTING PRONOUNCEMENTS

Generally Accepted Accounting Principles—The Company adopted Accounting Standards Update (“ASU”): No. 2009-01, Topic 105—Generally Accepted Accounting Principles—amendments based on Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles, as of September 30, 2009. Statement of Financial Accounting Standards (“SFAS”) No. 168 replaces SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, and establishes the FASB Accounting Standards Codification™ as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants as a result of this statement. As a result of the Company’s adoption of this ASU, references to the FASB Accounting Standards Codification^TM are included in this report.

Noncontrolling Interests—The Company adopted ASC Topic 810—Noncontrolling Interests in Consolidated Financial Statements—on January 1, 2009. The Topic changes the accounting and reporting for minority interests, which are re-characterized as noncontrolling interests, and classified as a component of equity. The Company retroactively applied the presentation and disclosure requirements of this Topic to all periods presented.

F-9

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Subsequent Events—The Company adopted SFAS No. 165, Subsequent Events (currently included in ASC 855-10), as of June 30, 2009. This statement requires the disclosure of the date through which an entity has evaluated subsequent events and whether that date represents the date the financial statements were issued or were available to be issued. The Company has evaluated subsequent events through March 16, 2010, the date the financial statements were issued. No material subsequent events came to our attention during this period.

Modernization of Oil and Gas Reporting—In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting, to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The FASB aligned ASC Topic 932, Extractive Industries—Oil and Gas, with the SEC rules on this topic through the issuance of ASU 2010-13. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The Company adopted these new rules and interpretations as of December 31, 2009.

Consolidation—In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R) (currently included in ASC Topic 810). This statement amends FASB Interpretation No. (“FIN”) 46(R), Consolidation of Variable Interest Entities, to replace the quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with a qualitative approach. This new approach focuses on identifying which enterprise has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (1) the obligation to absorb losses of the entity or (2) the right to receive benefits from the entity. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and it requires additional disclosures about an enterprise’s involvement in variable interest entities. This statement will be effective for the Company beginning January 1, 2010. The Company is currently assessing the impact that the adoption will have on its disclosures, operating results, financial position and cash flows.

4.	STOCK BASED COMPENSATION

Stock options are granted under the Company’s long-term incentive plan and have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted will become exercisable over a period determined by the Compensation Committee which in the past has been a five year life, with the options vesting over a three year period. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At December 31, 2009 there were 1,973,014 shares subject to options authorized but not granted.

For the years ended December 31, 2009, 2008 and 2007, the Company recognized non-cash compensation expense of $1.8 million, $2.6 million and $2.2 million, respectively. These amounts were recorded as general and administrative expense. Because the Company does not pay significant United States taxes, no amounts were recorded for tax benefits.

F-10

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of the stock option activity for the year ended December 31, 2009 is provided below:


	Number of Shares Underlying Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in millions)
Outstanding—beginning of period	4,763		$	5.33	3.24
Granted	0			0	0
Exercised	(693	)		3.86	0.03
Forfeited	(284	)		7.64	0.66

Outstanding—end of period	3,786		$	5.42	2.65	$	2.7

Vested—end of period	2,843		$	5.81	2.27	$	1.9

Vested and expected to vest—end of period	3,644		$	5.42	2.65	$	2.6

The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. As of December 31, 2009, unrecognized compensation costs totaled $0.5 million. The expense is expected to be recognized over a weighted average period of 1.0 year.

A summary of the values of options granted, exercised and vested for each of the years ending December 31, 2009, 2008 and 2007 is provided below:


	2009		2008		2007
Options granted—(thousands)		0		1,725		—
Weighted average exercise price—($/share)	$	3.86	$	4.25		—
Weighted average grant-date fair value—($/share)	$	0	$	1.88		—
Options exercised (thousands)		693		62		997
Total intrinsic value of options exercised—($thousands)	$	642	$	340	$	3,664

The Company received cash proceeds of $1.8 million, $0.1 million and $1.1 million from options exercised in 2009, 2008 and 2007, respectively.

The valuation of the options granted is based upon a Black Scholes model. The table below summarizes the assumptions used to value the options issued in 2008. There were no options issued in 2009 and 2007.


Year	Options Issued	Weighted Avg. Volatility		Expected Term	Risk Free Interest Rate		Expected Dividend Yield
2008	1,725	70	%	2.5-5 years	3.4	%	0	%

The Company has no set policy for sourcing shares for options grants. Historically the shares issued under options grants have been new shares.

5.	STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

The Company is authorized to issue up to 100 million shares of common stock. Stockholders’ equity consists of common stock and options. Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. Diluted EPS assumes the exercise of all stock options and warrants having exercise prices less than the average market price of the common stock using the treasury

F-11

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

stock method. For purposes of computing EPS in a loss period, potential common shares are excluded from the computation of weighted average common shares outstanding as their effect is antidilutive. For the year ended December 31, 2009, 369,954 potential common shares were excluded. A reconciliation of diluted shares consists of the following:


	Year Ended
Item	December 31, 2009	December 31, 2008	December 31, 2007
Basic weighted average common stock issued and outstanding	57,408,223	58,675,789	59,133,888
Dilutive options	0	611,081	957,034

Total diluted shares	57,408,223	59,286,871	60,090,922

A total of 1,435,572, 1,108,446, and 749,213, shares under option were not included because they were anti-dilutive during the years ended December 31, 2009, 2008 and 2007, respectively.

On June 24, 2009, the Company announced that its Board of Directors authorized the repurchase of up to $10 million of the Company’s common stock over the next 12 months. Under the share buyback program, shares of common stock were purchased on the open market or through privately negotiated transactions from time-to-time. The share buyback program does not obligate the Company to acquire any specific number of shares in any period, and may be modified, suspended, extended or discontinued at any time without prior notice. Total repurchases under this program as of December 31, 2009 were 2,327,779 shares acquired at an average price of $4.30 per share totaling $10.0 million. Under a previous share buyback program, the Company acquired 1,300,300 and 500,000 shares in 2008 and 2007, respectively.

On September 14, 2007, the Board of Directors of the Company adopted a Rights Agreement dated as of September 14, 2007 between the Company and the Registrar and Transfer agent of the Company, as Rights Agent. Ratification of the rights plan required the affirmative vote of at least a majority vote of shares entitled to vote at the June 3, 2009 Annual Meeting. Stockholders did not approve the ratification. The Rights Agreement was redeemed at the rate of 1/10^th of $.01 per share and paid to shareholders at a cost to the Company of approximately $67,000 in 2009.

6.	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,
	2009		2008		2007
U.S. federal:
Current	$	—	$	86	$	(60	)
Deferred		—		—		(200	)
Foreign:
Current		36,902		72,928		48,341
Deferred		—		—		—

Total	$	36,902	$	73,014	$	48,081

F-12

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2009 and 2008 are as follows: (In thousands)


	2009			2008
Deferred Tax Assets:
Basis difference in fixed assets	$	8,857		$	7,422
Foreign tax credit carry forwards		14,754			15,219
Alternative minimum tax credit carryover		1,349			1,349
Foreign net operating losses		20,468			8,695
Asset retirement obligations		3,734			3,525

		49,162			36,210
Valuation allowance		(47,813	)		(34,861	)

Total non-current deferred tax assets	$	1,349		$	1,349

Pretax income (loss) is comprised of the following:


(In thousands)	Year Ended December 31,
	2009			2008		2007
United States	$	(38	)	$	193	$	125
Foreign		32,796			108,554		71,488

	$	32,758		$	108,747	$	71,613

The statutory rate reconciliation is as follows:


(In thousands)	Year Ended December 31,
	2009		2008		2007
Pre-tax income multiplied by 35%	$	11,465	$	38,061	$	25,065
Foreign taxes not offset by U.S. foreign tax credits		25,437		34,952		23,016

Total income tax	$	36,902	$	73,014	$	48,081

At December 31, 2009, the Company was subject to foreign and United States federal taxes, with immaterial allocations made to state and local taxes.

The Company adopted the provisions of ASC Topic 740-10 — Income Taxes on January 1, 2007 related to accounting for uncertainty in income taxes. There was no impact related to the cumulative effect of the change in accounting principle. As of the adoption date, the Company had no unrecognized tax benefits.

The following table summarizes the activity to our unrecognized tax benefits:


(In thousands)	2009		2008		2007
Balances at January 1,	$	13,201	$	13,201	$	0
Increases related to prior year positions		0		0		13,201

Balance at December 31,	$	13,201	$	13,201	$	13,201

F-13

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

If recognized, none of the uncertain tax positions would impact the effective tax rate because they would be offset by valuation allowance.

Our accounting policy is to recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense. The Company has no accruals for the payment of interest and penalties.

Certain tax attributes may be adjusted upon examination even if the attribute did not arise in an open tax year, which could impact the Company’s carryforward items. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:


United States		2006-2009
Gabon		2007-2009

7.	COMMITMENTS AND CONTINGENCIES

In September 2007, the Company entered into an amendment with the owner of the FPSO chartered for the Etame field to extend the contract until September 2015. In connection with the charter of the FPSO, the Company, as operator of the Etame field, guaranteed the charter payments through the same period. The charter continues for two 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 through the end of the charter are as follows: (in thousands)


Year	Full Charter Payment		Company Share
2010	$	17,171	$	4,820
2011	$	16,971	$	4,764
2012	$	16,833	$	4,726
2013	$	16,879	$	4,739
2014	$	16,833	$	4,726
2015	$	11,622	$	3,263

The Company has recorded a liability of $0.6 million at December 31, 2009 representing the guarantee’s fair value.

The Company’s share of charter expense, including a $0.25 per bbl charter fee for production up to 20,000 bopd and a $2.50 per bbl charter fee for those bbls produced in excess of 20,000 bopd was $7.4 million, $6.3 million and $5.7 million for the years ending December 31, 2009, 2008 and 2007, respectively.

In addition to the FPSO, the Company has gross operating lease obligations for rentals as follows: (In thousands)


2010	2011	2012	2013	Thereafter	Total
$9,612	$3,342	$3,464	$19	$0	$16,438

The Company incurred rent expense of $1.2 million, $1.2 million and $0.7 million under operating leases for the years December 31, 2009, 2008 and 2007, respectively.

Under the terms of the Etame Production Sharing Contract, the consortium 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 Marin block production divided by the total Gabon

F-14

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

production times the volume of oil refined by the refinery per year. In 2009, the Company paid $2.8 million for its share of the 2008 obligation. In 2008, the Company paid $1.9 million for its share of the 2007 obligation. In 2007, the Company paid $1.6 million for its share of the 2006 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, 2009 is $1.8 million.

In November 2009, the Company signed the sixth exploration period extension on the Etame Marin block. The three year extension expires in July 2014. The Company committed to the drilling of two exploration wells and acquiring and processing 150 square kilometers of 3D seismic with a $17.5 million minimum financial commitment ($5.3 million net to the Company).

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary contract with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest in the Contract is 40%. Additionally, the Company is required to carry the Angolan National Oil Company, Sonangol P&P, for 10% of the work program. During the first four years of the contract the Company is required to acquire and process 1,000 square kilometers of 3-D seismic, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). During the optional three year extension to the contract, the Company is required to acquire 600 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $27.2 million ($13.6 million net to the Company). The Company acquired the 1,175 square kilometers of 3-D data called for in the first exploration period at a cost of $7.5 million ($3.75 million net to the Company) in January 2007. Subsequently, the Company acquired 524 square kilometers of proprietary 3-D seismic data on the block during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company), and has been interpreting seismic data in preparation for the drilling of the two required exploration wells.

The government-assigned working interest partner was delinquent on paying their share of the costs several times in 2009 and consequently was placed in a default position which has impacted the timing for drilling the wells. In early 2010, the Company began the process to acquire the interest of the non-performing partner and is working with the government of Angola regarding a time extension for the drilling of the commitment wells. While the Company believes the government of Angola will grant such extension, management can provide no assurances. If the government of Angola were to deny a time extension, the Company risks forfeiture of its $10 million funds in escrow if the wells are not drilled by November 2010 plus the Company may be required to impair its leasehold costs and other investments of $11.4 million as of December 31, 2009. Further, the Company has begun the process to obtain a replacement partner or partners. If the Company is granted the time extension, the Company estimates the drilling of the two exploration wells will take place in the first half of 2011 on this block in Angola.

8.	TERMINATION OF IFC CREDIT FACILITY

In June 2005, the Company executed a loan agreement with the International Finance Corporation (“IFC”) for a $30.0 million revolving credit facility secured by the assets of the Company’s Gabon subsidiary. The Company was required to comply with certain covenants including maintaining certain loan to property value ratios and interest coverage ratios.

The facility was available to finance the Ebouri field development activities or other Etame Marin block projects. Under the loan agreements, the IFC held a pledge of the Company’s interest in the Etame Marin block, and a pledge of the shares of VAALCO Gabon (Etame), Inc., the subsidiary which owns the Company’s interest in the Etame Marin block. The IFC also had a security interest in the crude oil sales contract with Total Oil Trading SA (“Total”).

F-15

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The facility extended until October 2009 at which point it could be extended by mutual agreement, and the loan drawdown amount could be converted to a term loan at the Company’s option. Because of the Company’s limited use of the facility, the IFC elected to not extend the unused capacity in the credit facility. The Company elected to not convert the loan balance to a term loan and instead repaid the loan balance of $5.0 million plus interest in mid-October 2009.

9.	PARTNER REALIGNMENT AGREEMENT

On June 3, 2009, a realignment agreement was signed with a joint venture partner that originally did not participate in an exploration well and one of the development wells in the Ebouri field, offshore Gabon. Pursuant to the realignment agreement, the joint venture partner paid its proportionate share of capital expenditures for the wells, which reduced the Company’s capital expenditures by $5.7 million. In addition, the Company benefits from a $15.0 million ($6.5 million net to the Company) risk premium being paid by the partner benefiting the other joint venture partners that originally participated in those two wells. In the quarter ended June 30, 2009, the Company received a $2.0 million payment from the partner and the payment was recorded as other operating income. The remaining proceeds of $4.5 million were received and recognized as other operating income in the third quarter of 2009.

10.

TAX AUDIT

During the second quarter of 2009, the Gabon Ministry of Finance initiated a withholding tax audit for the Company’s Gabon operations for the period 2005 through 2007. The results of the audit were received on September 22, 2009 and the Ministry of Finance has asserted a claim of $9.4 million ($2.7 million net to the Company) plus penalties of $4.7 million ($1.3 million net to the Company). The Company has replied, contesting much of the claim for the underpayment of withholding tax primarily on the basis that withholding tax did not apply for the goods or services involved. However, in preparing its response, the Company identified some invoices which were paid to certain vendors without calculating and paying the appropriate withholding tax to the Republic of Gabon. An estimated liability of $3.3 million net to the Company was recorded in 2009 considering the merits of the audit claim plus an estimate for similar matters in 2008 and 2009. In February 2010, a meeting with the government auditors resulted in approximately a 25% reduction in the claimed amount. The Company has not yet received the revised audit report and claim. The actual amount to settle the audit claim will not be known until a formal reply is received and the matter is resolved, perhaps through negotiations. The actual amount to correct the tax payments for 2008 and 2009 will not be known until clarity of the tax application is known by virtue of resolving the audit.

11.

EMPLOYEE BENEFIT PLANS

The Company sponsored a 401(k) plan, without a Company match feature, for its employees through the end of 2009. A replacement 401(k) plan was put in place in January 2010 which has a Company matching component. Costs incurred in 2009 for administering and ceasing the former 401(k) plan at December 31, 2009 were $151,000. Expenses for 2008 and 2007 were negligible.

The Company also has a retirement and severance policy for its employees. The benefit is a one-time payment based on receiving one month’s pay at current pay rates for each year of employment. A liability has been recorded for this policy in the amount of $1.5 million as of December 31, 2009. Payments to retiring employees totaled $277,000 in 2009. No payments were made in 2008 or 2007.

12.

ASSET RETIREMENT OBLIGATIONS

The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. The Company records asset

F-16

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

retirement obligations for the future abandonment costs of tangible assets such as platforms, wells, pipelines and other facilities. 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)


	2009			2008		2007
Balance January 1,	$	10,071		$	6,731	$	6,029
Accretion Expense		811			540		415
Additions		720			2,678		—
Revisions		(936	)		122		286

Balance December 31,	$	10,666		$	10,071	$	6,731

During the year ended December 31, 2009, the Company increased the asset retirement obligations to recognize the abandonment liability for an additional well on the Ebouri platform. The increases in the ARO liabilities during the year ended December 31, 2008 was due to the addition of the Ebouri platform.

As of December 31, 2009, the Company had $44,000 legally restricted for settling asset retirement obligations in the United States.

13.

DISCONTINUED OPERATIONS

On April 30, 2004, the Company closed the sale to its former partners of all of its assets associated with Service Contract 6 and Service Contract 14 in the Philippines (Matinloc and Nido fields). The Company closed the branches and liquidated the subsidiaries during 2007 and incurred final net costs of $51,000 for that year.

F-17

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

14.

SEGMENT INFORMATION

The Company’s operations are based in Gabon, Angola, the British North Sea and in the United States. Beginning in 2007, and in particular during the fourth quarter of 2007 with our entry into the North Sea, the Company began making significant expenditures in its operations outside of Gabon. Management reviews and evaluates the operation of each geographic segment separately. The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. The accounting policies of the reportable segments are the same as in Note 2 to the Consolidated Financial Statements. Revenues are based on the location of hydrocarbon production. The Company evaluates each segment based on income (loss) from operations. Segment activity for the years ended December 31, 2009, 2008 and 2007 are as follows: (in thousands)


	Gabon		Angola			North Sea			Corporate and Other			Total
2009
Revenues	$	115,214	$	—		$	—		$	84		$	115,298
Depreciation, depletion and amortization		20,702		14			—			44			20,760
Income (loss) from operations		52,625		(3,218	)		(9,819	)		(6,569	)		33,019
Interest income		91		36			—			527			654
Interest expense		450		—			—			—			450
Income taxes		36,902		—			—			—			36,902
Additions to (disposal of) properties and equipment		13,280		1			(794	)		(328	)		12,159
Long lived assets		64,454		10,966			—			146			75,566
Total assets		138,537		12,390			—			52,072			202,999

2008
Revenues	$	169,270	$	—		$	—		$	254		$	169,525
Depreciation, depletion and amortization		19,138		(219	)		—			18			18,937
Income (loss) from operations		131,141		(4,546	)		(6,543	)		(13,580	)		106,472
Interest income		1,244		—			—			1,276			2,520
Interest expense		140		—			56			44			240
Income taxes		72,962		—			—			53			73,014
Additions to properties and equipment		35,784		72			794			40			36,691
Long lived assets		70,386		10,978			794			129			82,287
Total assets		181,958		14,953			794			54,326			252,030

2007
Revenues	$	124,745	$	—		$	—		$	298		$	125,044
Depreciation, depletion and amortization		17,876		—			—			75			17,952
Income (loss) from operations		90,063		(4,775	)		(8,053	)		(8,562	)		68,673
Interest income		2,190		—			—			1,739			3,928
Interest expense		947		—			147			—			1,094
Income taxes		48,341		—			—			(260	)		48,081
Additions to properties and equipment		10,926		24			—			55			11,004

F-18

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

15.

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The following represents our unaudited quarterly results for years ended December 31, 2009 and 2008. The quarterly results were prepared in accordance with generally accepted accounting principles and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. These adjustments are of a normal recurring nature.


(In thousands of dollars except per share information)	1^st Quarter			2^nd Quarter			3^rd Quarter			4^th Quarter
2009
Total revenues	$	21,258		$	32,148		$	29,262		$	32,630
Total operating costs and expenses		31,720			25,573			9,689			15,297
Operating income (loss)		(10,462	)		6,575			19,573			17,333
Net income (loss)		(12,005	)		(39	)		5,078			2,822
Net income attributable to noncontrolling interest		(614	)		(1,642	)		(891	)		(598	)

Net income (loss) attributable to VAALCO Energy, Inc.	$	(12,619	)	$	(1,681	)	$	4,187		$	2,224

Basic income (loss) per share	$	(0.22	)	$	(0.03	)	$	0.07		$	0.04
Diluted income (loss) per share	$	(0.22	)	$	(0.03	)	$	0.07		$	0.04

2008
Total revenues	$	42,158		$	55,354		$	55,543		$	16,470
Total operating costs and expenses		18,027			14,679			13,788			16,559
Operating income (loss)		24,131			40,675			41,755			(89	)
Net income (loss)		2,865			14,980			25,043			(7,155	)
Net income attributable to noncontrolling interest		(1,064	)		(1,953	)		(2,697	)		(297	)

Net income (loss) attributable to VAALCO Energy, Inc.	$	1,801		$	13,027		$	22,346		$	(7,452	)

Basic income (loss) per share	$	0.03		$	0.22		$	0.38		$	(0.13	)
Diluted income (loss) per share	$	0.03		$	0.22		$	0.38		$	(0.13	)

Quarterly income per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year.

F-19

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING PROPERTIES

(Unaudited)

16.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following information is being provided as supplemental information in accordance with certain provisions of ASC Topic 832—Extractive Activities—Oil and Gas. The Company’s reserves are located offshore Gabon and in 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
	2009		2008		2007
Costs incurred during the year:
Exploration—capitalized	$	—	$	—	$	—
Exploration—expensed		—		—		—
Development		—		—		—

Total	$	—	$	—	$	—


(In thousands)	International
	2009		2008		2007
Costs incurred during the year:
Exploration—capitalized	$	2,257	$	5,173	$	—
Exploration—expensed		36,464		14,872		15,340
Development		12,143		20,532		14,520

Total	$	50,864	$	40,577	$	29,860

Exploration expense includes $33.4 million, $9.2 million and $8.1 million for dry hole expense in 2009, 2008 and 2007, respectively.

Capitalized Costs Relating to Oil and Gas Producing Activities:


(In thousands)	December 31, 2009			December 31, 2008			December 31, 2007
Capitalized costs—
Properties not being amortized	$	15,035		$	56,129		$	24,663
Properties being amortized⁽¹⁾		137,122			84,693			80,052

Total capitalized costs		152,157			140,822			104,715
Less accumulated depreciation, depletion, and amortization		(79,839	)		(61,379	)		(42,984	)

Net capitalized costs	$	72,318		$	79,443		$	61,731

(1)	Includes $8.4 million, 5.9 million, and $5.8 million asset retirement cost in 2009, 2008, and 2007, respectively.

F-20

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING PROPERTIES

(Unaudited)

The capitalized costs pertain to the Company’s producing activities in Gabon, leasehold acreage in Gabon and Angola, and U.S. activities.

Results of Operations for Oil and Gas Producing Activities:


(In thousands)	United States									International
	2009			2008			2007			2009			2008			2007
										Gabon			Gabon			Gabon
Crude oil and gas sales	$	84		$	254		$	298		$	115,214		$	169,270		$	124,745
Production & general and administrative expense		(103	)		(76	)		(118	)		(16,018	)		(16,889	)		(14,175	)
Depreciation, depletion and amortization		(11	)		(16	)		(56	)		(20,321	)		(18,921	)		(17,876	)

Income tax		(8	)		(57	)		(43	)		(36,902	)		(73,014	)		(48,038	)

Results from oil and gas producing activities	$	(38	)	$	105		$	81		$	37,485		$	59,450		$	43,307

Proved Reserves

A reserve report as of December 31, 2009 has been prepared by Netherland Sewell & Associates, Inc., independent petroleum engineers. The following tables set forth the net proved reserves of the Company as of December 31, 2009, 2008 and 2007, and the changes during such periods.


	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2007	5,996		17
Production	(1,756	)	(20	)
Revisions of previous estimates	1,979		64

BALANCE AT DECEMBER 31, 2007	6,214		61
Production	(1,824	)	(15	)
Revisions of previous estimates	1,242		(16	)
Extensions and discoveries	1,790		0

BALANCE AT DECEMBER 31, 2008	7,422		30
Production	(1,936	)	(6	)
Revisions of previous estimates	783		(1	)
Extensions and discoveries	1,094		0

BALANCE AT DECEMBER 31, 2009	7,363		23


	Oil (MBbls)		Gas (MMcf)
PROVED DEVELOPED RESERVES:
Balance at January 1, 2007	4,691		17
Balance at December 31, 2007	4,506		61
Balance at December 31, 2008	4,751		30
Balance at December 31, 2009	4,795		23

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.

F-21

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING PROPERTIES

(Unaudited)

Revisions in 2007 were associated with Etame, South Tchibala and Avouma reservoir performance, changes in oil prices, operating costs and taxes. Higher projected oil prices resulted in upward revision in reserves, but were partially offset by higher taxes. Total remaining operating costs for the fields declined due to shorter remaining field life after another year’s production. Revisions in 2008 were primarily associated with better reservoir performance at the Avouma field. Revisions in 2009 were attributable to better reservoir performance at the Etame field. Extensions and discoveries in 2008 and 2009 were the result of successful drilling of step out wells at the Ebouri field that increased the amount of proven acreage for the field.

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.

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 ASC Topic 832 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 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 $14.1 million attributable to future abandonment when the wells become uneconomic to produce.


(In thousands)	United States									International									Total
	December 31,									December 31,									December 31,
	2009			2008			2007			2009			2008			2007			2009			2008			2007
										Gabon			Gabon			Gabon
Future cash inflows	$	316		$	389		$	1,146		$	394,500		$	261,824		$	592,053		$	394,816		$	262,213		$	593,199
Future production costs		(179	)		(197	)		(405	)		(84,154	)		(76,878	)		(68,589	)		(84,333	)		(77,075	)		(68,994	)
Future development costs		—			—			—			(59,054	)		(30,178	)		(41,954	)		(59,054	)		(30,178	)		(41,954	)
Future income tax expense		(27	)		(36	)		(101	)		(130,732	)		(81,932	)		(252,111	)		(130,759	)		(81,968	)		(252,212	)

Future net cash flows		110			156			640			120,560			72,836			229,399			120,670			72,992			230,039
Discount to present value at 10% annual rate		(19	)		(26	)		(157	)		(18,132	)		(8,013	)		(38,213	)		(18,151	)		(8,039	)		(38,370	)

Standardized measure of discounted future net cash flows	$	90		$	130		$	483		$	102,428		$	64,823		$	191,186		$	102,518		$	64,953		$	191,669

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.

F-22

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING PROPERTIES

(Unaudited)

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:


(In thousands)	December 31,
	2009			2008			2007
BALANCE AT BEGINNING OF PERIOD	$	64,953		$	191,669		$	133,602
Sales of oil and gas, net of production costs		(93,321	)		(151,057	)		(108,964	)
Net changes in prices and production costs		148,174			(445,763	)		228,256
Revisions of previous quantity estimates		30,178			79,042			86,014
Additions		42,106			130,431			—
Changes in estimated future development costs		(21,969	)		(10,820	)		(21,815	)
Development costs incurred during the period		22,229			34,305			14,520
Accretion of discount		6,495			19,167			13,360
Net change in income taxes		(66,702	)		138,485			(161,616	)
Change in production rates (timing) and other		(29,625	)		79,494			8,311

BALANCE AT END OF PERIOD	$	102,518		$	64,953		$	191,669

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 oil and 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 gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and 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 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 Securities and Exchange 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 gas contract prices using a twelve month average of beginning of month prices 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 $56.64 per bbl. In the United States, the price was $57.65 per bbl of oil and $3.87 per Mcf of gas.

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 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, 2009,

F-23

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING PROPERTIES

(Unaudited)

there was $83,000 in the cost account 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 bopd. However, when the Cost Account becomes substantially recovered, the Company only recovers ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. The Cost Account has been substantially recovered since the first quarter of 2005. In 2007, the Company cost recovered 418,000 bbls for ongoing operating expenses and capital expenditures out of a theoretical maximum of 1,232,000 bbls which would have been recoverable if the Cost Account was full. In 2008, the Company cost recovered 436,000 barrels out of a theoretical maximum of 1,270,000 barrels which would have been recoverable if the Cost Account was full. In 2009, The Company cost recovered 812,000 barrels out of a theoretical 1,391,000 barrels which would have been recoverable if the Cost Account was full. Also because of the nature of the Cost Account, increases in oil prices result in a lesser number of barrels required to recover costs, therefore at higher oil prices, the Company’s net reserves after taxes would decrease, but at lower prices the Company’s Cost Oil barrels increase.

The Etame Production Sharing Contract allows for the carve-out of a development area, which was performed for the Etame, Avouma and Ebouri fields. The Etame development area has a term of 20 years and will expire in 2021. The Avouma field development area has a term of 20 years and will expire in 2025. The Ebouri field development area has a term of 20 years and will expire in 2026. The balance of the Etame Marin block comprises the exploration area, which expires in July 2014.

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.

The Mutamba Iroru production sharing contract entitles the Company to receive 70% of any future production remaining after deducting the royalty so long as there are amounts remaining in the Cost Account. At December 31, 2009 there was $26.8 million in the Cost Account. 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 63% 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 72% of production at production rate in excess of 20,000 bopd to a high of 85% of production at rates below 7,500 bbl per day. However, when the Cost Account becomes substantially recovered, the Company only recovers ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. The Mutamba Iroru service contract provides for all commercial discoveries to be reclassified into a development area with a term of twenty years. At December 31, 2009, the Company has no proved reserves related to the Mutamba Iroru block.

The Block 5 production sharing contract in Angola entitles the Company to receive 50% of the any future production so long as there are amounts remaining in the Cost Account. There are no royalty payments under the contract. The consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 30% to 90% of the oil remaining after deducting the cost oil. The percentage of “profit oil” paid to the government as tax is a function of the Company’s rate of return for each development area. In addition, the Company will pay 50% of its share of the profit oil as income tax to the government of Angola. The Block 5 production sharing contract provides for a discovery to be reclassified into a development area with a term of twenty years. At December 31, 2009, the Company has no proved reserves related to Block 5 in Angola.

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