Edgar Filing: VAALCO ENERGY INC /DE/

Form 10-K

Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2010

¨	TRANSITION REPORT PURSUANT TO 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, 2010 was $315,992,617 based on a closing price of $5.60 on June 30, 2010.

As of February 28, 2011, there were outstanding 57,017,258 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 10-K, which is incorporated into Part III of this Form 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		15
Item 1B.	Unresolved Staff Comments		21
Item 2.	Properties		21
Item 3.	Legal Proceedings		28
Item 4.	Removed and Reserved		28

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities		29
Item 6.	Selected Financial Data		32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		38
Item 8.	Financial Statements and Supplementary Data		39
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure		39
Item 9A.	Controls and Procedures		39
Item 9B.	Other Information		41

PART III

Item 10.	Directors, Executive Officers and Corporate Governance		41
Item 11.	Executive Compensation		41
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		41
Item 13.	Certain Relationships and Related Transactions and Director Independence		41
Item 14.	Principal Accountant Fees and Services		41

PART IV

Item 15.	Exhibits and Financial Statement Schedules		42

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.

•

Bcfe—One billion cubic feet of natural gas equivalent.

•

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

•

BOPD—One barrel of oil per day.

•

MBbl—One thousand Bbls.

•

Mcf—One thousand cubic feet of natural gas.

•

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

•

Mcfe—One thousand cubic feet of natural gas equivalent.

•

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

•

MMcf—One million cubic feet of natural gas.

•

MBOE—One thousand BOE.

•

MMBOE—One million BOE.

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

•

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

•

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

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

•

Standard measure of proved reserves—The present value, discounted at 10%, of the pre-United States income tax future net cash flows attributable to estimated net proved reserves. The Company calculates this amount by assuming that it will sell the oil and gas production attributable to the proved reserves estimated in its independent engineer’s reserve report for the prices 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

•

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, 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 scheduled 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, as defined in paragraph (a)(2) of this section, 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

•

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, 2010, 2009 or 2008 equal the estimated net proved reserves attributable to a property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated.

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

•

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

•

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 an operator in Angola, West Africa, and has conducted exploration activities as a non-operator in the British North Sea. The Company owns minor interests in production activities as a non-operator in the United States and recently acquired a lease in Texas in the Granite Wash formation. 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 properties located in the United States.

RECENT DEVELOPMENTS

Offshore Gabon

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, 2010, 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, each of which is located on the Etame Marin block. 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 2010, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 7.3 million bbls (1.75 million bbls net to the Company).

Beginning in March 2010, drilling began on the first of four planned wells located within the Etame Marin block. In July 2010, the consortium elected to extend the drilling program by two additional wells. The first of these wells was a development well drilled from the Ebouri platform which began producing oil in May 2010. The second well was a successful workover of the Ebouri 3-H well to replace submersible pumps. The third well was an exploration effort with two sidetracks in the Southeast Etame area which resulted in an oil discovery in the Gamba reservoir. Various completion options for the Southeast Etame discovery are being considered as part of a study on future development plans for the Etame Marin block. The fourth well in the drilling program was a subsea completed development well in the Etame field which began producing oil in December 2010. The fifth well in the drilling program was a development well in the South Tchibala field which began producing oil in November 2010 and the sixth well was an exploration well on the Omangou prospect. The sixth well was water-bearing in the objective reservoir and was subsequently abandoned. The Omangou well counts as one of the two exploration wells required per the terms of the sixth exploration period extension. The sixth exploration period expires in July 2014.

Onshore Gabon

The Company executed a farm-out agreement in August 2010 with Total Gabon on the Mutamba Iroru block located near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of

Index to Financial Statements

approximately 270,000 acres. Under the terms of the agreement, the Company and Total Gabon have committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. In return for Total Gabon funding an agreed portion of the new work commitment, Total Gabon will receive a 50% interest on the permit. In 2010, the exploration permit was successfully extended until May 2012.

Offshore Angola

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 government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position which impacted the timing for drilling the two commitment wells. In early 2010, the Company began working with the government of Angola regarding a time extension for the drilling of the wells beyond the November 2010 expiration date and to obtain a replacement partner. By governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract and a one year time extension was granted. The Company and the government of Angola then agreed on the process for obtaining a replacement partner. The Company opened a data room in Houston which is expected to close in the second quarter of 2011. Information related to interested parties will then be provided to the government of Angola for selection and finalization. If necessary, the government of Angola has expressed willingness to consider a further time extension once the new partner has been selected and a timeline of the drilling plans is completed. While we believe that the government of Angola will grant us another extension if necessary, we can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, and the wells are not drilling by the end of November 2011, the Company risks forfeiture of its $10 million funds in escrow, and the Company may be required to impair its leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

Onshore Domestic

The Company acquired a 640 acre lease in the Granite Wash formation in north Texas in December 2010. The first well on this acreage is expected to be drilled in the second quarter of 2011.

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 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)

Index to Financial Statements

totaling approximately 759,000 acres. The Company also owns a 50% working interest in the approximately 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. A 640 acre lease in the Granite Wash formation in north Texas was acquired in December 2010. The Company has plans to drill on this lease in 2011.

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.

Domestic

The Company’s domestic strategy has been to produce existing reserves from outside operated properties located in Brazos County, Texas, in Pickens County, Alabama, and offshore Louisiana in the Ship Shoal area. As described above, the Company also plans to drill a well on its recently acquired property in the Granite Wash formation in north Texas. Additionally, the Company is evaluating investment opportunities in resource based properties, including shale properties.

CUSTOMERS

Substantially all of the Company’s oil and gas is sold at the well head at posted or indexed prices under short-term contracts, as is customary in the industry. In Gabon, the Company sold oil under a contract with Vitol S.A. which ran through calendar year 2010. For the 2011 calendar year, the Company will sell its oil under a contract with Mercuria Trading NV (“Mercuria”). While the loss of Mercuria 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, 2010, the Company had 89 full-time employees and consultant contractors, 48 of whom were located in Gabon and nine of whom were located in Angola. The Company is not yet 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 and NEOP began negotiating a collective bargaining agreement in the first quarter of 2011. 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

Index to Financial Statements

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 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 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, certain wastes generated by the Company may be subject to RCRA or comparable state statutes. 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

Index to Financial Statements

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 facility. 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 substances that may fall within CERCLA’s definition of Hazardous Substance and may have disposed of these substances 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 regulated substances, the Company could be liable for costs of investigation and remediation and natural resources damages.

Clean Water Act

The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge (including spills and leaks) of pollutants, including produced waters and other oil and natural gas wastes, into state waters and 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. Generally, permits must be obtained to discharge pollutants. 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 other pollutants. The CWA also prohibits the discharge of fill materials to regulated waters, including wetlands, without a permit. 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 pollutants, 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 cleanup and response 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

Index to Financial Statements

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. In light of recent events, it is possible that these requirements may become more stringent. The Company believes that currently it has established adequate proof of financial responsibility for its offshore facilities.

Safe Drinking Water Act and Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid). Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal and state levels that could result in regulation of hydraulic fracturing becoming more stringent and costly. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. In addition, a committee of the U.S. House of Representatives is conducting an investigation of hydraulic fracturing practices. Moreover, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in the Safe Drinking Water Act, and, further, to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that restrict hydraulic fracturing in certain circumstances or that require disclosure of the chemicals in the fracturing fluids. If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where the Company conducts business, the Company could incur substantial compliance costs and such requirements could adversely delay or restrict its ability to conduct fracturing activities on its assets.

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 EPA has been moving forward to regulate GHGs as pollutants under the CAA and has already adopted rules establishing GHG emission limits from motor vehicles beginning with the 2012 model year, thus triggering the requirements for the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, both houses of the United States Congress have considered legislation to reduce emissions of greenhouse gases without any ultimate resolution and many states have already taken legal measures to reduce GHG emissions, including, in a few locations, the consideration of a cap and trade program. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Depending on the regulatory reach of EPA’s rules or new CAA legislation or implementing regulations restricting the emission of GHGs or state programs, the Company could incur significant costs to control its emissions and comply with regulatory requirements. In addition, in October 2009, the EPA adopted a mandatory GHG emissions reporting program which imposes

Index to Financial Statements

reporting and monitoring requirements on various industries and in November 2010, expanded this GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. The Company will incur costs to monitor, keep records of, and report emissions of GHGs. We do not believe that our compliance with applicable monitoring, recordkeeping and reporting requirements under the reporting rule as recently amended will have a material adverse effect on our results of operations or financial position.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how federal and state regulation of GHGs will unfold and how it may impact our industry. Moreover, the federal, regional, state and local regulatory initiatives could adversely affect the marketability of the oil and natural gas that 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. At the Federal level, the Clean Air Act is the primary statute governing 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 (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply 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 CCA 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.

FORWARD-LOOKING STATEMENTS

This Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended

Index to Financial Statements

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, the amount and nature of capital expenditures, 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:

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the volatility of oil and natural gas prices;

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the uncertainty of estimates of oil and natural gas reserves;

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the impact of competition;

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

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

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

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difficulties encountered in delivering oil to commercial markets;

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general economic conditions, including any future economic downturn and the availability of credit;

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changes in customer demand and producers’ supply;

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

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currency exchange rates;

•

actions by the governments and events occurring in the countries in which we operate;

•

actions by our venture partners;

•

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 five producing wells, the Avouma and South Tchibala fields consisting of one well and two wells, respectively, and the Ebouri field with three producing wells constituted almost 100% of our total production for the year ended December 31, 2010. In addition, at December 31, 2010, 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 2010 was $78.38 per barrel compared to $59.54 per barrel in 2009, $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, including recent uprisings and political unrest in the Middle East and Africa, 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 gas prices may fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

In recent years, 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. With the exception of our recently acquired property in the Granite Wash formation in north Texas, our current domestic oil and gas producing 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 2010, we participated, and in 2011 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 you 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 if the situation reoccurs.

Primarily in 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 reoccur, 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, 2010, 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

Index to Financial Statements

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 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 2010 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, 2010, we carried a gross investment excluding amortization of approximately $178.7 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 second time extension for the drilling of two exploration wells in Angola may be necessary to protect certain amounts invested in that country.

Due to financial non-performance of the venture partner assigned by the government of Angola, our plans to drill the two obligatory wells have been delayed. A government decree effective December 1, 2010 removed the former partner from the production sharing agreement and provided us with a one year extension through the end of November 2011. We are working with the government of Angola to secure a replacement partner. After the new partner is selected, another time extension may be required if reasonable time to drill the two commitment wells does not exist. We can give no assurances that another time extension will be granted, if necessary. If the government of Angola were to deny a time extension and the wells are not drilling by the end of November 2011, we risk forfeiture of our $10 million funds in escrow and we may be required to impair our leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

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:

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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

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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. Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and the issuance of orders enjoining operations. 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, resulting in increased operating costs. Additionally, more stringent GHG regulation could impact demand for oil and gas. 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.

The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

During 2010, President Obama signed into law the Dodd—Frank Wall Street Reform and Consumer Protection Act (the “Act”). Among other things, the Act requires the Commodity Futures Trading Commission and the SEC to enact regulations affecting derivative contracts. We cannot predict the content of these regulations or the effect that these regulations will have on hedging activities. Of particular concern, the Act does not explicitly exempt end users (such as us) from the requirements to post margin in connection with hedging activities. If the regulations ultimately adopted require that companies post margin for hedging activities or impose other requirements that are more burdensome than current regulations, hedging would become more expensive.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2012 is the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. The President’s budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. Specifically, the budget proposes to repeal the deduction for percentage depletion with respect to wells, in which case only cost depletion would be available. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

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.

Index to Financial Statements

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

Effective January 2011, we sell all of our crude oil production in Gabon to Mercuria Trading NV. The loss of Mercuria Trading NV 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 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.

Item 2.

Properties

Gabon

Etame Marin

VAALCO has an interest in an approximately 759,000 acre 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, 2010, 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 an approximately 12,000 acre exploitation area surrounding the field. The exploitation area has a term of up to 20 years (through 2021).

Index to Financial Statements

The Etame field has been developed at an aggregate cost of approximately $197.4 million ($53.6 million net to the Company). A successful development well was drilled in 2010 in this field. The development included completing subsea wells connected to a contracted floating production, storage and offloading vessel (“FPSO”). There are currently five 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 an approximately 13,000 acre 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. In 2010, a second development well in the South Tchibala fied was drilled and successfully completed. The three development wells are tied back to the FPSO via a ten mile pipeline. Through December 31, 2010, the cost of developing the Avouma and South Tchibala fields was approximately $146.5 million ($42.8 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 an approximately 3,700 acre 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, 2010 totaled approximately $189.0 million ($59.2 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. A third development well began production in May 2010.

The Company has sold a total of 56.1 million gross bbls (13.3 million net bbls) from the fields within the Etame Marin block since startup through December 31, 2010. During 2010, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 7.3 million gross bbls (1.75 million net bbls).

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 2011. One of the two commitment exploration wells has been met with the drilling of the Omangou prospect, an unsuccessful effort, in 2010.

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 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.

In 2010, in conjunction with executing a farm-out agreement with Total Gabon, the exploration period was extended until May 2012. This extension requires the Company to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. In return for Total Gabon funding an agreed portion of the new work commitment, Total Gabon will receive a 50% interest on the permit. The seismic reprocessing began in the first quarter of 2011 and the exploration well is expected to be drilled in the first half of 2012.

Angola

Block 5

Index to Financial Statements

rights to approximately 1.4 million acres along the central coast of Angola. The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position which impacted the timing for drilling the two commitment wells. In early 2010, the Company began working with the government of Angola regarding a time extension for the drilling of the wells beyond the November 2010 expiration date and to obtain a replacement partner. By governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract and a one year time extension was granted. The Company and the government of Angola then agreed on the process for obtaining a replacement partner. The Company opened a data room in Houston which is expected to close in the second quarter of 2011. Information related to interested parties will then be provided to the government of Angola for selection and finalization. If necessary, the government of Angola has expressed willingness to consider a further time extension once the new partner has been selected and a timeline of the drilling plans is completed. The government of Angola has expressed willingness to consider this further extension once the new partner has been selected and a timeline of the drilling plans is completed. While we believe that the government of Angola will grant us another extension if necessary, we can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, and the wells are not drilling by the end of November 2011, the Company risks forfeiture of its $10 million funds in escrow, and the Company may be required to impair its leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

Domestic United States Properties

The Company has interests in Brazos County, Texas producing from the Buda/Georgetown formations. The Company also owns certain non-operated interests in the Ship Shoal area of the Gulf of Mexico and in Pickens County, Alabama. During 2010, these wells produced approximately 900 bbls of oil and 14 million cubic feet of gas net to the Company. No capital expenditures are anticipated in 2010 for these properties. In December 2010, the Company acquired a 640 acre lease in north Texas in the Granite Wash formation. Capital expenditures are estimated at $9.0 million in 2011 to drill the first well on the lease.

Aggregate Production

Aggregate production data (net to the Company) for all of the Company’s operations for the years 2010, 2009, and 2008 are shown below.

Company Owned Production


	2010						2009						2008
	BOE		Bbl		Mcf		BOE		Bbl		Mcf		BOE		Bbl		Mcf
Average daily production
(Oil in BOPD, gas in MCFD)
Etame field, Gabon		1,755		1,755		—		2,079		2,079		—		2,593		2,593		—
Avouma/S.Tchibala field, Gabon		1,481		1,481		—		1,948		1,948		—		2,385		2,385		—
Ebouri field, Gabon		1,460		1,460		—		1,275		1,275		—		—		—		—
Other fields		9		2		38		5		2		16		13		6		40

Total average daily production		4,705		4,698		38		5,307		5,304		16		4,991		4,984		40


Average sales price ($/unit)	$	78.31	$	78.39	$	4.79	$	59.52	$	59.54	$	4.79	$	92.81	$	92.87	$	7.51
Average production cost ($/unit)	$	12.88	$	12.88	$	2.15	$	11.35	$	11.35	$	1.89	$	10.11	$	10.11	$	1.69

Index to Financial Statements

RESERVE INFORMATION

The table below sets for the Company’s estimated net proved reserves for the years ended December 31, 2010, 2009 and 2008 as prepared by Netherland Sewell & Associates, independent petroleum engineers. There have been no estimates of total proved net oil or gas reserves filed with or included in reports to any federal authority or agency other than the 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, 2010 and 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 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 reflect oil and natural gas spot prices on the last day of the year. As a result, estimates of proved reserves as of December 31, 2010 and 2009 may not be comparable to those as of December 31, 2008.


	As of December 31,
	2010		2009		2008
Crude Oil
Proved developed reserves (MBbls)
United States		4		4		5
International		5,025		4,791		4,746

Total proved developed reserves (MBbls)		5,029		4,795		4,751

Proved undeveloped reserves (MBbls)
United States		—		—		—
International		1,893		2,568		2,671

Total proved undeveloped reserves (MBbls)		1,893		2,568		2,671

Total proved reserves (MBbls)
United States		4		4		5
International		6,918		7,359		7,417

Total proved reserves (MBbls)		6,922		7,363		7,422

Natural Gas
Proved developed reserves (MMcf)
United States		23		23		30
International		—		—		—

Total proved developed reserves (MMcf)		23		23		30

Proved undeveloped reserves (MMcf)
United States		—		—		—
International		—		—		—

Total proved undeveloped reserves (MMcf)		—		—		—

Total proved reserves (MMcf)
United States		23		23		30


Standardized measure of proved reserves (in thousands)	$	124,824	$	102,518	$	64,953

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 1,894 MBbls of PUDs at December 31, 2010, compared with 2,568 MBbls of PUDs at December 31, 2009. In 2010, the Company converted 674 MBbls, or 26% of the total year-end 2009 PUDs, to proved developed reserves (PDP). Approximately $28.8 million was spent in 2010 associated with development of PUDs as the Company completed the drilling of three development wells in the Etame Marin block offshore Gabon.

Index to Financial Statements

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 the SEC’s regulations and GAAP. Compliance in reserves bookings is the responsibility of the Company’s Vice President-Production, who is the Company’s principal engineer. The Company’s principal engineer has over 20 years of experience in the oil and gas industry, including over 10 years as 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 Netherland Sewell & Associates, Inc. (“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, 2010, 2009 and 2008, and the changes during such periods.


	Oil (MBbls)			Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2008		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
Production		(1,715	)		(38	)
Revisions of previous estimates		1,274			38
Extensions and discoveries		0			0

BALANCE AT DECEMBER 31, 2010		6,922			23


	Oil (MBbls)			Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at January 1, 2008		4,506			61
Balance at December 31, 2008		4,751			30
Balance at December 31, 2009		4,795			23
Balance at December 31, 2010		5,029			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.

Index to Financial Statements

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 properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. In Gabon, the price was $78.51 per bbl. In the United States, the price was $74.39 per bbl of oil and $5.09 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

In 2010, the Company drilled two exploration wells and three development wells, all in the Etame Marin block offshore Gabon. 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.


	International
	Gross						Net
Wells Drilled	2010		2009		2008		2010		2009		2008
Exploration Wells
Productive		0.0		1.0		0.0		0.00		0.30		0.00
Dry		1.0		4.0		1.0		0.30		2.55		0.25
In progress⁽¹⁾		1.0		0.0		1.0		0.30		0.00		0.30
Development Wells
Productive		3.0		2.0		0.0		0.90		0.60		0.00
Dry		0.0		0.0		0.0		0.00		0.00		0.00
In progress⁽²⁾		0.0		0.0		1.0		0.00		0.00		0.30

Total Wells		5.0		7.0		3.0		1.50		3.45		0.85

(1)	The 2010 well resulted in a discovery in the Etame Marin block; assessment of development options was still in progress at end of December 2010. The 2008 well was drilling in the Etame Marin block at December 31, 2008 and resulted in a successful exploration test in 2009.

(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, 2010:


	United States				International
	Gross		Net⁽¹⁾		Gross		Net⁽¹⁾
	(Acreage In thousands)
Developed acreage		6.7		0.8		28.7		8.1
Undeveloped acreage		0.6		0.6		2,411.4		912.5
Productive gas wells		6		0.6		0		0
Productive oil wells		3		0.4		11		3.1

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

The leases in which we hold an interest in undeveloped acreage with minimum remaining terms are not material to us.

Index to Financial Statements

Office Space

The Company leases its offices in Houston, Texas (approximately 15,400 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 adequate for the Company’s operations.

Item 3.

Legal Proceedings

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

Item 4.

Removed and 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
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	$	4.99	$	3.93
Second Quarter		6.24		4.31
Third Quarter		6.25		5.07
Fourth Quarter		8.17		5.55

On February 28, 2011 the last reported sale price of the common stock on the New York Stock Exchange was $8.02 per share.

As of February 28, 2011 there were approximately 12,000 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 stockholder 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 stockholder 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


	2005		2006		2007		2008		2009		2010
S&P/ TSX Capped Energy	$	100	$	101	$	109	$	68	$	93	$	101
S&P 500 Composite	$	100	$	114	$	118	$	72	$	89	$	101
VAALCO Energy, Inc	$	100	$	159	$	110	$	175	$	107	$	169

Index to Financial Statements

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of December 31, 2010 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 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		2,524,686	$	4.27		500
Equity compensation plans not approved by security holders		1,740,940	$	7.05		475,896

Total		4,265,626	$	5.40		476,396

Issuer Purchases of Equity Securities for Year Ended December 31, 2010

The Company did not purchase any shares in the year ended December 31, 2010.

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, 2010 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,
	2010		2009			2008		2007		2006
	(In thousands, except per share amounts)
Total revenues	$	134,472	$	115,298		$	169,525	$	125,044	$	98,325
Income (loss)	$	42,387	$	(4,144	)	$	35,733	$	23,532	$	45,759
Net income (loss) attributable to VAALCO Energy, Inc.	$	37,340	$	(7,889	)	$	29,722	$	19,103	$	40,343
Basic income (loss) per common share attributable to VAALCO Energy, Inc.	$	0.66	$	(0.14	)	$	0.51	$	0.32	$	0.69
Diluted income (loss) per common share attributable to VAALCO Energy, Inc.	$	0.65	$	(0.14	)	$	0.50	$	0.32	$	0.67
Total assets	$	238,400	$	202,999		$	252,030	$	186,558	$	167,942
Total debt	$	0	$	0		$	5,000	$	5,000	$	5,000

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.

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 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 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

Index to Financial Statements

Company’s exploration plans in Angola. Any adverse developments related to the Company’s ability to further extend the drilling obligation date, if necessary, could result in an impairment of the Company’s unproved properties and other assets with a carrying value of approximately $13.7 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 2010 was $46.1 million, as compared to $23.5 million in 2009 and $106.6 million in 2008. The increase in cash provided by operating activities was primarily due to net income of $42.4 million in 2010 versus a net loss of $4.1 million in 2009. The decrease in cash provided by operations in 2009 versus 2008 was primarily due to a net loss incurred in 2009 versus net income in 2008 and less favorable changes in operating assets and liabilities.

Net cash used in investing activities in 2010 was $39.9 million, compared to net cash used in investing activities for 2009 of $49.0 million and net cash used in investing activities in 2008 of $42.4 million. In 2010, the Company invested $37.3 million on four wells in the Etame Marin block offshore Gabon. The Company also invested in a Granite Wash formation lease in Texas ($2.2 million) and a second extension of the Mutamba Iroru block onshore Gabon ($1.2 million). In 2009, the Company invested $22.3 million primarily for the Ebouri platform and three wells. Also in 2009, 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. Also in 2008, 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 2010, cash used in financing activities was $5.5 million consisting of distributions to a noncontrolling interest owner of $6.0 million partially offset by proceeds from the issuance of common stock upon the exercise of options of $0.5 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, primarily consisting of distributions to a noncontrolling interest owner of $6.5 million and purchase of treasury shares of $8.9 million.

Capital Expenditures

During 2010, the Company invested $40.0 million in property and equipment additions (including amounts carried in accounts payable and excluding exploration dry hole costs), primarily associated with the drilling of three development wells in the Etame Marin block offshore Gabon totaling $29.3 million. In addition, one successful exploration well was drilled in the Southeast Etame area of the Etame Marin block at a cost of $8.0 million, and the Company invested in a Granite Wash formation lease in Texas ($2.2 million) and a second extension of the Mutamba Iroru block onshore Gabon ($1.2 million). During 2009, the Company invested $22.3 million in property and equipment additions 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 2008 were for FPSO upgrades ($2.0 million), onshore Gabon ($2.2 million) and drilling a well in the British North Sea ($0.8 million).

Index to Financial Statements

In 2010, the Company incurred $6.8 million in exploration expense including $2.6 million on the Omangou unsuccessful exploration well offshore Gabon, $1.4 million for seismic costs in the Etame Marin block offshore Gabon, onshore Gabon exploration expense of $0.7 million, and $0.9 million in Angola primarily for geotechnical studies. 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.

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, 2010, the Company had cash balances of $81.2 million and funds in escrow of $15.8 million. The Company believes that these cash balances combined with cash flow from operations will be sufficient to fund the Company’s 2011 capital expenditure budget, which is expected to range from $35.0 to $60.0 million to further develop the Etame Marin block and for drilling in Angola and the Granite Wash lease in Texas. 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 few years. 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.

Contractual Obligations

The table below summarizes the Company’s net share of obligations and commitments at December 31, 2010:

Payment Period


(in thousands $)	2011		2012		2013		2014		2015		Thereafter		Total
Operating leases⁽¹⁾	$	8,478	$	5,990	$	5,688	$	4,743	$	3,280	$	0	$	28,179

(1)

The Company is guarantor of a lease for the FPSO utilized in Gabon, which has remaining obligations of $79.1 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 FPSO amounts, the schedule includes the Company’s share of its other lease obligations.

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 square kilometers of 3-D seismic on the Etame Marin block by July 2014. One of the two exploration commitment wells was drilled in 2010 on the Omangou prospect at a cost of $8.6 million ($2.6 million net to the Company). The Company also entered into the second exploration period for the Mutamba Iroru block which requires the Company to reprocess 400 kilometers of 2-D seismic and drill one exploration well by May 2012. 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, 2011. The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position which impacted the timing for drilling the two commitment wells. In early 2010, the Company began working with the government of Angola regarding a time extension for the drilling of the wells beyond the November 2010 expiration date and to obtain a replacement partner. By governmental decree dated December 1, 2010, the

Index to Financial Statements

former partner was removed from the production sharing contract and a one year time extension was granted. The Company and the government of Angola then agreed on the process for obtaining a replacement partner. The Company opened a data room in Houston which is expected to close in the second quarter of 2011. Information related to interested parties will then be provided to the government of Angola for selection and finalization. If necessary, the government of Angola has expressed willingness to consider a further time extension once the new partner has been selected and a timeline of the drilling plans is completed. While we believe that the government of Angola will grant us another extension if necessary, we can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, and the wells are not drilling by the end of November 2011, the Company risks forfeiture of its $10 million funds in escrow and the Company may be required to impair its leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

The Company is carrying $13.4 million of asset retirement obligations as of December 31, 2010, 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, 2010 Compared to Years Ended December 31, 2009 and 2008

Revenues

Total oil and gas sales for 2010 were $134.5 million as compared to $115.3 million and $169.5 million for 2009 and 2008, respectively. In 2010, the Company sold approximately 1,714,000 bbls at an average price of $78.38 per bbl from the Etame Marin block with revenues from the United States of $0.1 million. In 2009, the Company sold approximately 1,935,000 bbls at an average price of $59.54 per bbl from the Etame Marin block with revenues from the United States of $0.1 million. In 2008, the Company sold approximately 1,822,000 net bbls at an average price of $92.87 per bbl from the Etame field in Gabon with revenues from the United States of $0.3 million. Crude oil sales from the Etame Marin block 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 2010 was $22.1 million as compared to $22.0 million and $18.5 million for 2009 and 2008, respectively. In the aggregate, production expenses in 2010 were nearly the same as in 2009. In 2010, despite lower sales volumes which reduced production expenses, increased expense resulted from the Ebouri well workover ($1.5 million). Production expenses were higher in 2009 versus 2008 primarily due to higher sales volumes, and higher FPSO costs. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized.

Exploration expense for 2010 was $6.8 million as compared to $36.5 million and $14.9 million for 2009 and 2008, respectively. In 2010, exploration expense is primarily comprised of $2.6 million for the Omangou unsuccessful exploration well offshore Gabon, $1.4 million for seismic costs in the Etame Marin block offshore Gabon, onshore Gabon exploration expense of $0.7 million, and $0.9 million in Angola primarily for geotechnical studies. 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 Mutamba Iroru block onshore Gabon ($20.8 million) and a well on Block 48/25c in the British North Sea ($9.6 million). Additionally, in 2009 the Company also 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

Index to Financial Statements

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.

Depreciation, depletion and amortization expense was $20.0 million for 2010, and was $20.8 million and $18.9 million for 2009 and 2008, respectively. Depletion, depreciation and amortization expense decreased slightly in 2010 versus 2009 due to lower sales volumes partially offset by overall higher depletion rates. The 2010 depletion rates for the Ebouri field averaged $19.95 per bbl, Avouma and South Tchibala fields averaged $7.76 per bbl, and the Etame field averaged $5.26 per bbl. In comparison, the 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. The increase in 2009 versus 2008 was primarily due to higher production volumes.

General and administrative expense for 2010 was $7.4 million as compared to $9.6 million and $10.8 million for 2009 and 2008, respectively. The decrease in general and administrative expense for 2010 versus 2009 was primarily due to $2.1 million of increased overhead reimbursement associated with the extensive drilling program in offshore Gabon and a decrease in retirement benefits of $1.0 million.

General and administrative expense decreased in 2009 versus 2008 due in part to non-recurring legal and solicitation costs associated with corporate matters relating to the Company’s 2008 annual meeting. During 2010, the Company incurred $1.8 million of stock based compensation compared to $1.8 million incurred in 2009 and $2.6 incurred in 2008. 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 2010 and 2008, 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 2010 was $78.1 million as compared to a $33.0 million and $106.5 million for 2009 and 2008, respectively. The significant increase in operating income in 2010 versus 2009 was primarily attributable to the higher average crude sales price of $78.38 per bbl, an increase of $18.84 per bbl, and a year to year decrease in exploration expense totaling $29.7 million. The decrease in exploration expense reflects less dry hole expense incurred in 2010 versus 2009.

The significant decrease in operating income in 2009 versus 2008 was primarily attributable to the lower average crude sales price of $59.54 per bbl, a decrease of $33.33 per bbl compared to the 2008 sales price, and higher exploration costs related to unsuccessful exploratory wells. Also, partially contributing to the decrease in operating income were higher operating expenses and depletion expense.

Other Income (Expense)

Interest income for 2010 was $0.2 million compared to $0.7 million and $2.5 million in 2009 and 2008, respectively. All the 2010, 2009, and 2008 amounts represent interest earned and accrued on cash balances and funds in escrow. Extremely low interest rates in 2010 account for the decrease in interest income.

No interest expense was recorded in 2010. Interest expense of $0.5 million was recorded in 2009 as compared to $0.2 million in 2008. Interest in both 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.

Index to Financial Statements

Other expense for 2010 was $0.6 million compared to $0.5 million in 2009. Other expense was negligible in 2008. The other expense in both 2010 and 2009 was primarily associated with foreign exchange losses.

Income Taxes

In 2010, the Company incurred $35.3 million of income taxes compared to $36.9 million incurred in 2009 which were associated with the Etame Marin block production, and which were incurred in Gabon. In 2008, the Company incurred $73.0 million of income taxes associated with the Etame Marin block production, which were incurred in Gabon. The slightly lower income taxes incurred in 2010 versus 2009 was a function of lower sales quantities largely offset by higher crude oil sales prices. The decreased tax in Gabon in 2009 versus 2008 was due to lower crude oil sales prices in 2009, which was partially offset by higher sales quantities. Also a larger percentage of crude was subject to taxation in 2008 as part of profit oil versus cost oil.

Net Income (Loss)

Net income for 2010 was $42.4 million compared to a net loss in 2009 of $4.1 million. Net income in 2008 was $35.7 million. The increase in net income in 2010 versus 2009 is attributable to the increased crude oil sales prices and lesser unsuccessful exploration well costs incurred in 2010. The decrease in 2009 versus 2008 was attributable primarily to the unsuccessful exploration well costs incurred and lower crude oil sales prices.

Income attributable to the noncontrolling interest in the Gabon subsidiary was $5.0 million, $3.7 million and $6.0 million in 2010, 2009, and 2008, respectively.

NEW ACCOUNTING PRONOUNCEMENTS

For a discussion of new accounting pronouncements, see Note 3 to the consolidated 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, 2010 the Company did not have any debt and thus no exposure to interest rate risk on debt. Interest earned on cash investments is immaterial.

Commodity Price Risk

The Company had no derivatives in place as of the date of this report, or throughout 2010, 2009 or 2008.

Index to Financial Statements

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 Securities Exchange Act of 1934, as amended (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 Exchange Act) 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 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 quarter 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 14, 2011, management concluded that its internal control over financial reporting was effective as of December 31, 2010.

The Company’s internal control over financial reporting as of December 31, 2010 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, 2010, as stated in their report which follows.

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, 2010 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, 2010, 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, 2010, 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, 2010 of the Company, and our report dated March 14, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 14, 2011

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, 2010 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 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, 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 under 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 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, and which is incorporated herein by reference. Please see “Item 5—Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities” for information on securities that may be issued under the Company’s stock incentive plans.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Item 14.

Principal Accountant Fees and Services

The information required by this item is incorporated by reference from the Company’s definitive proxy statement for its 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, 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, 2010 and 2009			F-3

Statements of Consolidated Operations Years ended December 31, 2010, 2009 and 2008			F-4

Statements of Consolidated Equity Years ended December 31, 2010, 2009 and 2008			F-5

Statements of Consolidated Cash Flows Years ended December 31, 2010, 2009 and 2008			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



	31.2			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.

(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.

Index to Financial Statements

(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 14, 2011

In accordance with the Exchange Act, this report has been signed below on the 14th 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/ JOHN J. MYERS, JR. John J. Myers, Jr.	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, 2010 and 2009			F-3

Statements of Consolidated Operations Years ended December 31, 2010, 2009 and 2008			F-4

Statements of Consolidated Equity Years ended December 31, 2010, 2009 and 2008			F-5

Statements of Consolidated Cash Flows Years ended December 31, 2010, 2009 and 2008			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, 2010 and 2009, and the related statements of consolidated operations, equity, and cash flows for each of the three years in the period ended December 31, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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.

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, 2010, 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 14, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 14, 2011

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, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	81,234		$	80,570
Funds in escrow		14,932			5,572
Receivables:
Trade		14,068			8,175
Accounts with partners		16,180			13,558
Other		10,412			5,171
Crude oil inventory		548			286
Materials and supplies		501			160
Prepayments and other		1,482			1,217

Total current assets		139,357			114,709

Property and equipment—successful efforts method:
Wells, platforms and other production facilities		168,139			137,122
Undeveloped acreage		16,692			13,252
Work in progress		8,812			1,784
Equipment and other		2,634			3,668

		196,277			155,826
Accumulated depreciation, depletion and amortization		(99,457	)		(80,260	)

Net property and equipment		96,820			75,566

Other assets:
Deferred tax asset		1,349			1,349
Funds in escrow		874			10,873
Other long term assets		—			502

Total Assets	$	238,400		$	202,999

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	26,702		$	33,728

Total current liabilities		26,702			33,728


Asset retirement obligations		13,425			10,666
Other liabilities		2,030			1,500

Total liabilities		42,157			45,894

Commitments and contingencies (Note 7)

VAALCO Energy Inc. shareholders’ equity:
Common stock, $0.10 par value, 100,000,000 authorized shares, 62,822,805 and 61,809,024 shares issued with 6,005,547 and 5,453,942 shares in treasury at December 31, 2010 and 2009, respectively		6,282			6,157
Additional paid-in capital		64,314			57,550
Retained earnings		146,594			109,249
Less treasury stock, at cost		(25,665	)		(21,515	)

Total VAALCO Energy Inc. shareholders’ equity		191,525			151,441
Noncontrolling interest		4,718			5,664

Total Equity		196,243			157,105

Total Liabilities and Equity	$	238,400		$	202,999

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,
	2010			2009			2008
Revenues:
Oil and gas sales	$	134,472		$	115,298		$	169,525

Operating costs and expenses:
Production expense		22,112			21,978			18,468
Exploration expense		6,813			36,464			14,872
Depreciation, depletion and amortization		20,021			20,760			18,937
General and administrative expense		7,403			9,580			10,776
Other operating income		—			(6,503	)		—

Total operating costs and expenses		56,349			82,279			63,053

Operating income		78,123			33,019			106,472
Other income (expense):
Interest income		151			654			2,520
Interest expense		—			(450	)		(240	)
Other, net		(627	)		(465	)		(5	)

Total other income (expense)		(476	)		(261	)		2,275

Income before income taxes		77,647			32,758			108,747
Income tax expense		35,260			36,902			73,014

Net income (loss)		42,387			(4,144	)		35,733
Less net income attributable to noncontrolling interest		(5,047	)		(3,745	)		(6,011	)

Net income (loss) attributable to VAALCO Energy, Inc.	$	37,340		$	(7,889	)	$	29,722

Basic net income (loss) per share attributable to
VAALCO Energy, Inc.	$	0.66		$	(0.14	)	$	0.51

Diluted net income (loss) per share attributable to
VAALCO Energy, Inc.	$	0.65		$	(0.14	)	$	0.50

Basic weighted average shares outstanding		56,466			57,407			58,676

Diluted weighted average shares outstanding		57,038			57,407			59,287

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, 2008	$	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

Proceeds from stock issuance		125		4,614		—			(4,150	)		—			589
Stock based compensation		—		2,150		—			—			—			2,150
Net income		—		—		37,340			—			5,047			42,387
Redemption of rights agreement		—		—		5			—			—			5
Distribution to noncontrolling interest		—		—		—			—			(5,993	)		(5,993	)

Balance at December 31, 2010	$	6,282	$	64,314	$	146,594		($	25,665)		$	4,718		$	196,243

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,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	42,387		$	(4,144	)	$	35,733
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		20,021			20,760			18,937
Amortization of debt issuance costs		—			—			125
Unrealized foreign exchange gain		(595	)		(316	)		—
Dry hole costs		2,609			33,373			9,217
Stock based compensation		1,895			1,841			2,566
Change in operating assets and liabilities:
Trade receivables		(5,893	)		1,338			10,253
Accounts with partners		(2,622	)		(15,156	)		5,427
Other receivables		(4,557	)		(3,159	)		(428	)
Crude oil inventory		(262	)		1,095			(454	)
Materials and supplies		(341	)		265			(86	)
Deferred tax asset		—			—			108
Other long term assets		502			(155	)		(117	)
Prepayments and other		(301	)		1,185			(189	)
Accounts payable and other liabilities		(7,328	)		(13,434	)		25,686
Income taxes payable		—			—			(200	)

Net cash provided by operating activities		45,515			23,493			106,578

CASH FLOWS FROM INVESTING ACTIVITIES
Decrease (increase) in funds in escrow, net		639			6,637			(7,447	)
Property and equipment expenditures		(40,012	)		(61,340	)		(34,922	)
Reimbursement of property and equipment expenditures by partner		—			5,737			—

Net cash used in investing activities		(39,373	)		(48,966	)		(42,369	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		510			1,771			130
Debt repayment		—			(5,000	)		—
Purchase of treasury shares		—			(10,093	)		(8,870	)
Redemption of rights agreement		5			(66	)		—
Distribution to noncontrolling interest		(5,993	)		(5,994	)		(6,494	)

Net cash used in financing activities		(5,478	)		(19,382	)		(15,234	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		664			(44,855	)		48,975
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		80,570			125,425			76,450

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	81,234		$	80,570		$	125,425

Supplemental disclosure of cash flow information
Cash paid for Income taxes	$	35,777		$	34,438		$	72,812

Cash paid for Interest	$	—		$	599		$	633

Supplemental disclosure of non cash flow information
Property and equipment additions incurred during the period but not paid at period end	$	5,478		$	4,363		$	8,184

Receivable from employees for stock option exercise	$	651		$	—		$	—

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 has conducted exploration activities 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 non-controlling 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, 2010 represent an escrow account securing the Company’s drilling obligation in Block 5 in Angola ($10.0 million) and bank guarantees for customs clearance in Gabon ($4.9 million). Long term amounts at December 31, 2010 include the Company’s charter payment escrow for the Floating Production Storage and Offloading tanker (“FPSO”) in Gabon ($0.8 million) and for the abandonment of certain Gulf of Mexico properties ($44,000).

Current amounts at December 31, 2009 represented an escrow account securing the Company’s seismic obligations in Angola which was released in 2010. Long term amounts at December 31, 2009 represented amounts to secure the Company’s drilling obligation in Block 5 in Angola ($10.0 million), an escrow to secure charter payments for the FPSO in Gabon ($0.8 million) and for the abandonment of certain Gulf of Mexico properties ($44,000).

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 losses on foreign currency transactions of $632,000, $493,000 and $42,000 in 2010, 2009 and 2008, respectively.

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 and trade payables. The book values of cash, funds in escrow, trade receivables, and trade payables are representative of their respective fair values due to the short-term maturity of these instruments.

F-8

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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, 2011, the Company sells crude oil under a contract with Mercuria Trading NV. In 2010, Vitol S.A., and in 2009, Total Oil Trading S.A., 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.

Subsequent Events—The Company has evaluated subsequent events through the date the financial statements were issued.

3.	RECENT ACCOUNTING PRONOUNCEMENTS

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—Effective January 1, 2010, the Company adopted Accounting Standards Update No. 2009-17, Consolidations (Topic 810)—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities. 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

F-9

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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. The adoption of this standard did not have an impact on the Company’s consolidated results of operations or financial condition, as the Company does not have any variable interests in variable interest entities.

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. A portion of the stock options granted in March 2010 were vested immediately with the others 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, 2010 there were 476,396 shares subject to options authorized but not granted.

For the years ended December 31, 2010, 2009 and 2008, the Company recognized non-cash compensation expense of $1.8 million, $1.8 million and $2.6 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.

A summary of the stock option activity for the year ended December 31, 2010 is provided below:


	Number of Shares Underlying Options (in thousands)			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value (in millions)
Outstanding—beginning of period		3,786		$	5.42		2.65
Granted		1,565			4.28		4.17
Exercised		(1,014	)		3.79		1.48
Forfeited		(72	)		4.83		2.49

Outstanding—end of period		4,265			5.40		2.64	$	3.9

Vested—end of period		3,058		$	5.85		2.24	$	2.4

Vested and expected to vest—end of period		4,193		$	5.40		2.64	$	3.9

During the year ended December 31, 2010, 672,300 options were exercised on a cashless basis, resulting in 120,695 shares being issued to employees and 551,605 shares being added to treasury stock.

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, 2010, unrecognized compensation costs totaled $0.8 million. The expense is expected to be recognized over a weighted average period of 1.1 years.

F-10

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of the values of options granted and exercised for each of the years ending December 31, 2010, 2009 and 2008 is provided below:


	2010		2009		2008
Options granted—(thousands)		1,565		—		1,725
Weighted average exercise price—($/share)	$	4.28		—	$	4.25
Weighted average grant-date fair value—($/share)	$	1.61		—	$	1.88
Options exercised (thousands)		1,014		693		62
Total intrinsic value of options exercised—($thousands)	$	2,413	$	642	$	340

The Company received cash proceeds of $0.5 million, $1.8 million and $0.1 million from options exercised in 2010, 2009 and 2008, 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 2010 and 2008. There were no options issued in 2009.


Year	Options Issued		Weighted Avg. Volatility			Expected Term		Risk Free Interest Rate			Expected Dividend Yield
2010		1,565		58	%		2.5 years		2.6	%		0	%
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. 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 having exercise prices less than the average market price of the common stock using the treasury 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, 2010		December 31, 2009		December 31, 2008
Basic weighted average common stock issued and outstanding		56,465,800		57,408,223		58,675,789
Dilutive options		572,253		—		611,081

Total diluted shares		57,038,053		57,408,223		59,286.871

A total of 1,420,940, 1,435,572, and 1,108,446, shares under option were not included because they were anti-dilutive during the years ended December 31, 2010, 2009 and 2008, respectively.

In the year ended December 31, 2010, the Company did not repurchase any shares of the Company’s common stock. Under previous share buyback programs, the Company acquired 2,327,779 and 1,300,300 shares in 2009 and 2008, respectively.

F-11

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 stockholders at a cost to the Company of approximately $67,000 in 2009. In 2010, the Company received $5,000 for its share of the redemption held as treasury stock.

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,
	2010		2009		2008
U.S. federal:
Current	$	—	$	—	$	86
Deferred		—		—		—
Foreign:
Current		35,260		36,902		72,928
Deferred		—		—		—

Total	$	35,260	$	36,902	$	73,014

The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2010 and 2009 are as follows: (In thousands)


	2010			2009
Deferred Tax Assets:
Basis difference in fixed assets	$	17,875		$	8,857
Foreign tax credit carry forwards		37,950			14,754
Alternative minimum tax credit carryover		1,349			1,349
Foreign net operating losses		21,842			20,468
Unrealized foreign exchange gain		(209	)		—
Asset retirement obligations		4,699			3,734

		83,506			49,162
Valuation allowance		(82,157	)		(47,813	)

Total deferred tax asset	$	1,349		$	1,349

The Company’s unused foreign tax credit will start to expire between the years 2013 and 2020. The alternative minimum tax credits do not expire, and foreign net operating losses (“NOL”) are not subject to expiry dates. The NOL for the company’s UK subsidiary can be carried forward indefinitely, while the NOLs for the company’s Gabon and Angola subsidiaries are included in the respective subsidiaries’ cost oil accounts, which will be offset against future taxable revenues.

F-12

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Pre-tax income (loss) is comprised of the following:


(In thousands)	Year Ended December 31,
	2010			2009			2008
United States	$	(4,129	)	$	(6,029	)	$	(15,831	)
Foreign		81,776			38,787			124,578

Total pre-tax income	$	77,647		$	32,758		$	108,747

The statutory rate reconciliation is as follows:


(In thousands)	Year Ended December 31,
	2010		2009		2008
Pre-tax income multiplied by 35%	$	27,176	$	11,465	$	38,062
Foreign taxes not offset by U.S. foreign tax credits		8,084		25,437		34,952

Total income tax	$	35,260	$	36,902	$	73,014

At December 31, 2010, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.

The following table summarizes the activity to the Company’s unrecognized tax benefits:


(In thousands)	2010		2009		2008
Balances at January 1,	$	13,201	$	13,201	$	13,201
Increases related to prior year positions		—		—		—

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

If recognized, none of the uncertain tax positions would impact the effective 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.

The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:


United States			2006-2010
Gabon			2007-2010

7.	COMMITMENTS AND CONTINGENCIES

FPSO Charter

In October 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

F-13

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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
2011	$	16,971	$	4,764
2012		16,879		4,739
2013		16,833		4,726
2014		16,833		4,726
2015		11,621		3,263

Total	$	79,136	$	22,218

The Company has recorded a liability of $0.5 million at December 31, 2010 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 $7.8 million, $7.4 million and $6.3 million for the years ending December 31, 2010, 2009 and 2008, respectively.

Other Lease Obligations

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


Year	Gross Obligation		Company Share
2011	$	11,659	$	3,714
2012		3,576		1,251
2013		3,308		962
2014		17		17
2015		17		17

Total	$	18,577	$	5,960

The Company incurred rent expense of $6.0 million, $5.3 million and $6.3 million under operating leases for the years December 31, 2010, 2009 and 2008, respectively.

Gabon Obligation

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 “Gabon Obligation”). The volume required to be furnished is the amount of the Etame Marin block production divided by the total Gabon production times the volume of oil refined by the refinery per year. In 2010, the Company paid $1.3 million for its share of the 2009 obligation. 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. The Company accrues an amount for the Gabon 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, 2010 is $1.7 million.

Offshore Gabon

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

F-14

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

commitment ($5.3 million net to the Company). One exploration well commitment was met in late 2010 with the drilling of the Omangou well, an unsuccessful effort at a cost of $2.6 million.

Onshore Gabon

In October 2010, the Company signed a second exploration period extension on the Mutamba Iroru block which expires in May 2012. The Company is obligated to reprocess 400 square kilometers of 2D seismic and drill one exploration well. An agreement with Total Gabon (“Total”) was completed in August 2010 which established a joint operation on the block beginning when the one year extension was finalized with the Republic of Gabon. Accordingly, Total acquired a 50% working interest in the block effective November 1, 2010. The terms of the agreement provide for Total paying a disproportionate share of the seismic reprocessing costs and the exploration well drilling costs. The Company expects the joint operation with Total to result in seismic reprocessing in 2011 followed by the drilling of an exploratory well in 2012.

Angola

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 paying their share of the costs several times in 2009 and consequently was placed in a default position which impacted the timing for drilling the two commitment wells. In early 2010, the Company began working with the government of Angola regarding a time extension for the drilling of the wells beyond the November 2010 expiration date and to obtain a replacement partner. By governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract and a one year time extension was granted. The Company and the government of Angola then agreed on the process for obtaining a replacement partner. The Company opened a data room in Houston which is expected to close in the second quarter of 2011. Information related to interested parties will then be provided to the government of Angola for selection and finalization. If necessary, the government of Angola has expressed willingness to consider a further time extension once the new partner has been selected and a timeline of the drilling plans is completed. While we believe that the government of Angola will grant us another extension if necessary, we can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, and the wells are not drilling by the end of November 2011, the Company risks forfeiture of its $10 million funds in escrow and the Company may be required to impair its leasehold costs and other investments with a carrying amount of $13.7 million as of December 31, 2010.

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

F-15

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

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 an offer to 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 appraisal 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 benefited 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 which the Company received and recognized as other operating income in 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 in September 2009 and the Ministry of Finance 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 contested portions of the claim for the underpayment of withholding tax primarily on the basis that withholding tax did not apply for certain types of services. 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 to accrue for this potential liability for the audited period as well as 2008 and 2009. In April 2010, a negotiated settlement with the government of Gabon was agreed upon for the time period 2005 – 2009. The settlement resulted in a payment of $9.1 million ($2.6 million net to the Company) in June 2010.

11.

CAPITALIZATION OF EXPLORATORY WELL COSTS

ASC Topic 932—Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense.

F-16

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In the second and third quarters of 2010, the Company drilled the Southeast Etame No. 1 well with two sidetracks in the Etame Marin block offshore Gabon. The well discovered a five meter sand of oil. Additional evaluation of the well and sidetrack information is in progress and the Company has a project underway to evaluate development options for this well in conjunction with other potential initiatives in the Etame Marin block. The Company has capitalized $8.0 million for this well in accordance with the criteria contained in ASC Topic 932.

12.

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 2010 for administering the plan including the match feature were approximately $150,000. Costs incurred in 2009 for administering and ceasing the former 401(k) plan at December 31, 2009 were $151,000.

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 $2.0 million and $1.5 million as of December 31, 2010 and 2009, respectively. No payments to retiring employees were made in 2010 or 2008. Payments totaled $277,000 in 2009.

13.

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 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)


	2010			2009			2008
Balance January 1,	$	10,666		$	10,071		$	6,731
Accretion Expense		825			811			540
Additions		2,016			720			2,678
Revisions		(82	)		(936	)		122

Balance December 31,	$	13,425		$	10,666		$	10,071

During the year ended December 31, 2010, the Company increased the asset retirement obligations to recognize the abandonment liability for three new development wells (Ebouri 4-H, Etame 7-H, and S. Tchibala 2-H). The increase in the asset retirement obligation liabilities during the year ended December 31, 2009 was due to an additional well on the Ebouri platform. The increase in the asset retirement obligation liabilities during the year 2008 was due to the addition of the Ebouri platform.

As of December 31, 2010, the Company had $44,000 legally restricted for settling asset retirement obligations in the United States.

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. 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. 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, 2010, 2009 and 2008 are as follows: (in thousands)


2010	Gabon		Angola			North Sea			Corporate and Other			Total
Revenues	$	134,346	$	—		$	—		$	126		$	134,472
Depreciation, depletion and amortization		19,946		16			—			59			20,021
Operating income (loss)		85,594		(2,846	)		(425	)		(4,200	)		78,123
Interest income		85		—			—			66			151
Income taxes		35,260		—			—			—			35,260
Additions to properties and equipment		38,082		27			—			2,343			40,452
Long lived assets		83,412		10,977			—			2,431			96,820
Total assets		181,642		14,081			—			42,677			238,400

2009
Revenues	$	115,214	$	—		$	—		$	84		$	115,298
Depreciation, depletion and amortization		20,702		14			—			44			20,760
Operating income (loss)		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
Operating income (loss)		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

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, 2010 and 2009. 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
2010
Total revenues	$	30,006		$	33,675		$	32,604		$	38,187
Total operating costs and expenses		12,127			13,582			11,001			19,639
Operating income		17,879			20,093			21,603			18,548
Net income		6,924			11,414			13,933			10,116
Net income attributable to noncontrolling interest		(956	)		(1,378	)		(1,482	)		(1,231	)

Net income attributable to VAALCO Energy, Inc.	$	5,968		$	10,036		$	12,451		$	8,885

Basic net income per share attributable to VAALCO Energy, Inc.	$	0.11		$	0.18		$	0.22		$	0.16
Diluted net income per share attributable to VAALCO Energy, Inc.	$	0.11		$	0.18		$	0.22		$	0.15

(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 net income (loss) per share attributable to VAALCO Energy, Inc.	$	(0.22	)	$	(0.03	)	$	0.07		$	0.04
Diluted net income (loss) per share attributable to VAALCO Energy, Inc.	$	(0.22	)	$	(0.03	)	$	0.07		$	0.04

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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 of Gabon and Texas. The following tables set forth costs incurred, capitalized costs, and results of operations relating to oil and natural gas producing activities for each of the periods. (See Footnote)

Costs Incurred in Oil and Gas Property

Acquisition, Exploration and Development Activities


(In thousands)	United States
	2010		2009		2008
Costs incurred during the year:
Exploration—capitalized	$	—	$	—	$	—
Exploration—expensed		392		47		290
Development		—		—		—

Total	$	392	$	47	$	290


(In thousands)	International
	2010		2009		2008
Costs incurred during the year:
Exploration—capitalized	$	8,020	$	2,257	$	5,173
Exploration—expensed		6,421		36,417		14,582
Development		31,127		12,143		20,532

Total	$	45,960	$	50,817	$	40,287

Exploration expense includes $2.6 million, $33.4 million and $9.2 million for dry hole expense in 2010, 2009 and 2008, respectively.

Capitalized Costs Relating to Oil and Gas Producing Activities:


(In thousands)	December 31, 2010			December 31, 2009			December 31, 2008
Capitalized costs—
Properties not being amortized	$	25,504		$	15,036		$	56,129
Properties being amortized⁽¹⁾		170,457			140,555			86,945

Total capitalized costs		195,961			155,591			143,074
Less accumulated depreciation, depletion, and amortization		(99,277	)		(80,127	)		(60,890	)

Net capitalized costs	$	96,684		$	75,464		$	82,184

(1)	Includes $10.3 million, $8.4 million, and $5.9 million asset retirement cost in 2010, 2009, and 2008, respectively.

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

F-20

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Results of Operations for Oil and Gas Producing Activities:


(In thousands)	United States									International
	2010			2009			2008			2010			2009			2008
										Gabon			Gabon			Gabon
Crude oil and gas sales	$	126		$	84		$	254		$	134,346		$	115,214		$	169,270
Production, G&A and other expense		(495	)		(103	)		(76	)		(28,614	)		(20,506	)		(17,885	)
Depreciation, depletion and amortization		(11	)		(11	)		(16	)		(19,946	)		(20,321	)		(18,921	)
Income tax		(7	)		(8	)		(57	)		(35,260	)		(36,902	)		(73,014	)

Results from oil and gas producing activities	$	(387	)	$	(38	)	$	105		$	50,526		$	37,485		$	59,450

Proved Reserves

A reserve report as of December 31, 2010, 2009, and 2008 have been prepared by Netherland Sewell & Associates, independent petroleum engineers. The following tables set forth the net proved reserves of the Company as of December 31, 2010, 2009 and 2008, and the changes during such periods.


	Oil (MBbls)			Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2008		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
Production		(1,715	)		(38	)
Revisions of previous estimates		1,274			38
Extensions and discoveries		0			0

BALANCE AT DECEMBER 31, 2010		6,922			23


	Oil (MBbls)			Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at January 1, 2008		4,506			61
Balance at December 31, 2008		4,751			30
Balance at December 31, 2009		4,795			23
Balance at December 31, 2010		5,029			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.

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

F-21

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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. Revisions in 2010 were primarily associated with better reservoir performance in several of the Etame Marin block fields.

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 $21.6 million attributable to future abandonment when the wells become uneconomic to produce.


(In thousands)	United States									International									Total
	December 31,									December 31,									December 31,
	2010			2009			2008			2010			2009			2008			2010			2009			2008
										Gabon			Gabon			Gabon
Future cash inflows	$	407		$	316		$	389		$	517,051		$	394,500		$	261,824		$	517,458		$	394,816		$	262,213
Future production costs		(203	)		(179	)		(197	)		(140,470	)		(84,154	)		(76,878	)		(140,673	)		(84,333	)		(77,075	)
Future development costs		—			—			—			(71,190	)		(59,054	)		(30,178	)		(71,190	)		(59,054	)		(30,178	)
Future income tax expense		(34	)		(27	)		(36	)		(159,811	)		(130,732	)		(81,932	)		(159,845	)		(130,759	)		(81,968	)

Future net cash flows		170			110			156			145,580			120,560			72,836			145,750			120,670			72,992
Discount to present value at 10% annual rate		(41	)		(19	)		(26	)		(20,885	)		(18,132	)		(8,013	)		(20,926	)		(18,151	)		(8,039	)

Standardized measure of discounted future net cash flows	$	129		$	90		$	130		$	124,695		$	102,428		$	64,823		$	124,824		$	102,518		$	64,953

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

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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,
	2010			2009			2008
BALANCE AT BEGINNING OF PERIOD	$	102,518		$	64,953		$	191,669
Sales of oil and gas, net of production costs		(112,360	)		(93,321	)		151,057	)
Net changes in prices and production costs		139,810			148,174			(445,763	)
Revisions of previous quantity estimates		71,600			30,178			79,042
Additions		0			42,106			130,431
Changes in estimated future development costs		(5,337	)		(21,969	)		(10,820	)
Development costs incurred during the period		37,531			22,229			34,305
Accretion of discount		10,252			6,495			19,167
Net change in income taxes		(31,482	)		(66,702	)		138,485
Change in production rates (timing) and other		(87,708	)		(29,625	)		79,494

BALANCE AT END OF PERIOD	$	124,824		$	102,518		$	64,953

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 $78.51 per bbl. In the United States, the price was $74.39 per bbl of oil and $5.09 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 Hydrocarbures 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, 2010,

F-23

Index to Financial Statements

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

there was $6.9 million 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 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. In 2010, the Company cost recovered 838,000 barrels out of a theoretical 1,200,000 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, 2010 there was $27.5 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, 2010, 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, 2010, the Company has no proved reserves related to Block 5 in Angola.

F-24