The following information is being provided as supplemental information in accordance with certain provisions of ASC Topic 932 – Extractive Activities- Oil and Gas. The Company’s reserves are located offshore of Gabon and in Texas. The following tables set forth costs incurred, capitalized costs, and results of operations relating to oil and natural gas producing activities for each of the periods. (See Footnote 1 – “ORGANIZATION”)

Costs Incurred in Oil and Gas Property

Acquisition, Exploration and Development Activities

Exploration expense includes $13.3 million, $23.9 million and $37.3 million for dry hole expense in 2014, 2013 and 2012, respectively. The dry hole expense for 2014 was attributable to one unsuccessful exploration well spudded in the fourth quarter of 2013 and determined to be a dry hole in the first quarter of 2014 in Gabon for $11.7 million and $1.6 million in leasehold costs related to the expiration of the exploration license offshore Gabon.

In November 2012, the Company completed the acquisition of a 31% working interest in Block P located offshore in Equatorial Guinea at a cost of $10.0 million.

Capitalized Costs Relating to Oil and Gas Producing Activities:

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

Results of Operations for Oil and Gas Producing Activities:

Proved Reserves

Reserve reports as of December 31, 2014, 2013, and 2012 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. The following tables set forth the net proved reserves of the Company as of December 31, 2014, 2013 and 2012, and the changes during such periods.

The Company’s proved developed reserves are located offshore Gabon and in Alabama, Texas and waters of the Gulf of Mexico.  Revisions in 2014 were primarily due to better reservoir performance at the Avouma/South Tchibala field (1,500 MBbls) and a combination of better reservoir performance from existing wells at Etame, and revisions to proved undeveloped reserves at Etame (1,100 MBbls).  Ebouri proved undeveloped reserves were revised downward (300 MBbls) due to higher costs of developing the reserves rendering them uneconomic.   Revisions in 2013 were primarily due to better reservoir performance at the Etame field (800 MBbls).  In 2012, the revisions were due to improved reservoir performance at the Avouma/South Tchibala field (1,200 MBbls) and improved reservoir performance at Etame (1,000 MBbls). In 2014, the extensions and discoveries were associated with the booking of the Southeast Etame/North Tchibala reserves.  Extensions and discovery reserve additions in 2013 were due to the drilling of the Avouma 3H well which extended the reservoir boundary further to the north at the Avouma field.  In 2012, the extensions and discoveries were associated with the booking of the Southeast Etame/North Tchibala reserves following approval of the development plans for these fields and final investment decision to install the platforms necessary to develop these 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 932 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.

In accordance with the guidelines of the SEC, 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. The future cash flows are also based on 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 $52.8 million ($14.8 million net to the Company) attributable to future abandonment when the wells become uneconomic to produce.

International income taxes represent amounts payable to the Government of Gabon on profit oil as final payment of corporate income taxes, and domestic income taxes (including other expenses treated as taxes), and domestic income taxes represent amounts payable for severance and ad-valorem taxes in Texas.

Changes in Standardized Measure of Discounted Future Net Cash Flows:

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

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 weighted average price was $98.88 per Bbl. In the United States, the weighted average price was $86.49 per Bbl of oil and $5.19 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 fixed royalty rate of 13%.

The consortium maintains a Cost Account, which entitles it to receive 70% of the production remaining after deducting the 13% royalty so long as there are amounts remaining in the Cost Account. At December 31, 2014, there was $36.8 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.  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 2012, the Company cost recovered 367,000 barrels out of a theoretical 1,197,000 barrels which would have been recoverable if the Cost Account was full.  In 2013, the Company cost recovered 929,400 barrels out of a theoretical 1,079,300 barrels which would have been recoverable if the Cost Account was full. In 2014, the Company cost recovered 907,400 barrels out of a theoretical 935,800 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/South Tchibala, and Ebouri fields. The Etame development area has a term of 20 years and will expire in 2021 which coincidentally matches the economic life of the Etame reserves under the current reserve report prepared by our independent reserves engineering firm. The Avouma/South Tchibala 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 expired 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, 2014 there was $36.4 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. 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, 2014, 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. The Block 5 production sharing contract provides for a discovery to be reclassified into a development area with a term of 20 years. At December 31, 2014, the Company has no proved reserves related to Block 5 in Angola.

The Block P production sharing contract in Equatorial Guinea entitles the Company to receive up to 70% of any future production after royalty deduction so long as there are amounts remaining in the Cost Account. Royalty rates are 10-16% depending on production rates. The consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 10% to 60% of the oil remaining after deducting the royalty and cost oil. The percentage of “profit oil” paid to the government as tax is a function of cumulative production. In addition, Equatorial Guinea imposes a 25% income tax on net profits. The Block P production sharing contract provides for a discovery to be reclassified into a development area with a term of 25 years. At December 31, 2014, the Company has no proved reserves related to Block P in Equatorial Guinea.