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Correspondence Letter

 VAALCO Energy, Inc.

 4600 Post Oak Place, Suite 309

 Houston, Texas 77027

Tel: (713) 623-0801

 Fax: (713) 623-0982

 January 22, 2013

United States Securities and Exchange Commission

Attn: Mr. H. Roger Schwall, Assistant Director

 Washington, D. C. 20549

 Subject: Letter Dated December 17, 2012

Re:
VAALCO Energy, Inc.

 Form 10-K
for Fiscal year Ended December 31, 2011

 Filed: March 12, 2012

File No. 001-32167

 Dear
Mr. Schwall,

 We acknowledge receipt of your letter referenced above and have obtained through our counsel, Haynes and Boone, LLP, a time
extension for our reply regarding your inquiries.

 As requested in your letter, we acknowledge that:

•

 VAALCO Energy, Inc. is responsible for the adequacy and accuracy of the disclosure in the filing;

•

 Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the
filing; and

•

 VAALCO Energy, Inc. may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities
laws of the United States.

 Our responses to your comments follow:

 Form 10-K for Fiscal Year Ended December 31, 2011

 Properties, page 27

 Proved Undeveloped Reserves, page 31

 Comment 1: We note on page 31 you state “the Company had 2,194 MBbls and 1,069 MMcf of PUDs at December 31, 2011, compared with 1,894 MBbls of PUDs at December 31, 2010.” It
does not appear that you provide an explanation for the changes in your proved undeveloped reserves here or elsewhere in the filing on Form 10-K. Furthermore, other than noting “the Company did not convert any PUD’s to proved developed
reserves in 2011,” it is not clear whether you made any investments or other progress during the year to convert your proved undeveloped reserves to developed reserves. Please expand your disclosure to provide more specific detail regarding
your proved undeveloped reserves as required under Items 1203(b) and 1203(c) of Regulation S-K.

 Response: Comparing the PUD’s reported at December 31, 2011 and
December 31, 2010, there was an increase of 300 MBbls and 1,069 MMcf. The entire 1,069 MMcf PUD reported for the first time at December 31, 2011 was attributable to the Hefley 90-02 well located in Texas. The Company began drilling this
well in November 2011 giving rise to the 1,069 MMcf gas PUD as well as an oil PUD of 17 MBbls at year end 2011. The well was completed in February 2012 and commercial production was established in March 2012. These PUDs will be shown in 2012 as
having been converted to proved developed reserves.

 The remaining PUDs at December 31, 2011 (net of the Hefley 90-02
well) total to 2,177 MBbls and are attributable to four planned wells located in the Etame Marin block, offshore Gabon – the Ebouri 5H and 6H wells and the Etame 8H and 9H wells. The increase (net of the Hefley 90-02 well) primarily pertains to
the first inclusion of the Ebouri 6H well in the calculation of PUDs as of December 31, 2011. Investment in and progress on all four wells occurred in 2011. As the Company disclosed in its filing on Form 10-K, it began platform modifications to
the Ebouri platform in 2010 to add three additional wells slots to accommodate the drilling of additional wells, including the Ebouri 5H and 6H wells. The Company initiated the Etame field expansion project in 2009 to allow for further development
of the Etame field. The project continues to progress with engineering and procurement of equipment that will allow for drilling the Etame 8H and 9H wells and additional wells in the field.

In future filings on Form 10-K, the Company will continue to provide updates on its investments and other progress during the year to
convert proved undeveloped reserves to proved developed reserves. When there are material gross changes in our PUD reserves, we will include a table or narrative that explains the material changes from the beginning of the year PUD reserve balance
to the final year-end balance, including material extensions, discoveries and other additions during the year and material revisions for changes due to price, performance and for other reasons.

Comment 2: We note on page 31 you state “generally, the Company’s PUDs are converted to proved developed reserves within five years of the
date they are first booked as PUDs.” You also state “the Company did not convert any PUD’s to proved developed reserves in 2011.” For purposes of determining the five year period, Item 1203(d) of Regulation S-K identifies
the initial disclosure and date thereof as the starting reference date. With a view toward disclosure, please tell us if any of the proved undeveloped reserves you disclose as of December 31, 2011 will take more than five years since initial
disclosure to develop.

 Response: The table below lists the PUDs, the year of initial disclosure and comments
regarding the length of time, and in particular if it will take more than five years since initial disclosure to develop. We have considered data learned in 2012 to provide a current view as to the time to develop, as is consistent with our annual
review of PUDs and our validation of the technical and economic merits of each project.

 PUDs

 Well/Location

 Initial Disclosure

 Time to Develop

 17 MBbls &

1,069 MMcf

 Hefley 90-02,

Texas

2011

Converted to developed reserves in 2012

 388 MBls

 Ebouri 5H –

Gabon

2009

 At the time of filing the 2011 Form 10-K, the drilling of the well was scheduled for drilling in 2013.

 2012 Update: In 2012, Hydrogen sulfide (H2S) was discovered in the field
vicinity. It was decided for operational purposes to delay drilling this well to coincide with the installation upgrade of the processing facilities to accommodate H2S. For disclosure in the 2012 Form 10-K, PUDs including time to develop will be
evaluated under Item 1203(d) of Regulation S-K and the disclosure will be updated accordingly.

 388 MBls

 Ebouri 6H –

Gabon

2011

 At the time of filing the 2011 Form 10-K, the drilling of the well was scheduled for drilling in 2013.

 2012 Update: In 2012, H2S was discovered in the field vicinity. It was
decided for operational purposes to delay drilling this well to coincide with the installation upgrade of the processing facilities to accommodate H2S. For disclosure in the 2012 Form 10-K, PUDs including time to develop will be evaluated under Item
1203(d) of Regulation S-K and the disclosure will be updated accordingly.

 721 MBls

 Etame 8H –

Gabon

2009

 At the time of filing the 2011 Form 10-K, the projected timetable for drilling this well was 2014.

 2012 Update: The project continues to progress with engineering and
procurement of platform equipment. The projected timetable for drilling this well remains 2014.

 680 MBls

 Etame 9H –

Gabon

2010

 At the time of filing the 2011 Form 10-K, the projected timetable for drilling this well was 2014.

 2012 Update: The project continues to progress with engineering and
procurement of platform equipment. The projected timetable for drilling this well remains 2014.

 In our future filings on Form 10-K, we will provide disclosure on the progress and proposed timing to
convert our PUDs to proved developed reserves and if any of those PUDs will take over five years to convert.

 Exhibit 99.1

Comment 3: We note the statement on page 1 of the report relating to the properties located in Gabon and on page 1 of the report relating to
the properties located in the U.S. that “the estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future
income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Industries – Oil and Gas.” The report further states that the “definitions are presented immediately following this letter.” We note the
information relating to the definitions used in the preparation of the report is not included as part of Exhibit 99.1. Please confirm that the referenced information will be presented in reports filed with your future Exchange Act filings.

 Response: The non-inclusion of the definitions used in the preparation of the
report was an oversight on our part. For completeness, we have attached to this letter the omitted definitions information. Attachment 1 contains the definitions of oil and gas reserves pertaining to the properties located in Gabon and Attachment 2
contains the definitions of oil and gas reserves pertaining to the properties located in the U.S.

 We confirm that the referenced information
will be presented in reports filed with our future Exchange Act filings.

 Please let us know if we have not adequately responded to the
comments or if you have further comments. My direct phone number is: 713 212-1034.

Sincerely,

/s/ Gregory R. Hullinger

 Gregory R. Hullinger,

 Chief
Financial Officer

 Attachments

 1. Definitions of Oil and Gas Reserves (pertaining to properties in Gabon)

 2.
Definitions of Oil and Gas Reserves (pertaining to properties in U.S.)

 ATTACHMENT 1

 DEFINITIONS OF OIL AND GAS RESERVES

 Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X
Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932,
Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

 (1) Acquisition of
properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is
purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

 (2) Analogous
reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development
than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares
the following characteristics with the reservoir of interest:

(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)
Same environment of deposition;

(iii)
Similar geological structure; and

(iv)
Same drive mechanism.

 Instruction to
paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

 (3)
Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric
pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

 (4) Condensate.
Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from
the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

 (6) 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.

 Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open
and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which
are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves
are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure
compared to the cost of drilling a new well.

 (7) Development costs. Costs incurred to obtain access to proved reserves and to
provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development
activities, are costs incurred to:

(i)
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing
ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

 DEFINITIONS OF OIL AND GAS RESERVES

 Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii)
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing,
tubing, pumping equipment, and the wellhead assembly.

(iii)
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage
tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)
Provide improved recovery systems.

 (8)
Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing
field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

 (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that
exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

 (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative
production as of that date.

 (12) Exploration costs. Costs incurred in identifying areas that ma