VAALCO ENERGY INC /DE/ - Quarter Report: 2011 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2011

For the transition period from             to             

Commission file number 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)

(713) 623-0801

(Registrant’s telephone number, including area code)

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

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 for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨.

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.

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

As of October 31, 2011, there were outstanding 57,118,925 shares of common stock, $0.10 par value per share, of the registrant.

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CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

See notes to unaudited condensed consolidated financial statements.

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CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(unaudited)

(in thousands of dollars, except per share amounts)

See notes to unaudited condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(in thousands of dollars)

See notes to unaudited condensed consolidated financial statements.

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CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(in thousands of dollars)

See notes to unaudited condensed consolidated financial statements.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The condensed consolidated financial statements of VAALCO Energy, Inc. and subsidiaries (collectively, “VAALCO” or the “Company”), included herein are unaudited, and include all adjustments consisting of normal recurring accruals which the Company deems necessary for a fair presentation of its financial position, results of operations and cash flows for the interim period. Such results are not necessarily indicative of results to be expected for the full year. These financial statements should be read in conjunction with the financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2010, which also contains a summary of the significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the quarterly report included herein. The Company follows the successful efforts method of accounting for oil and gas exploration and development costs.

VAALCO 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 of consortiums internationally in Gabon and Angola and as a non-operator in the British North Sea. In Gabon and Angola, VAALCO serves as the operator for a group of companies which own working interests in production sharing contracts. Domestically, the Company has interests onshore in Montana, Texas, and Alabama and in the offshore Texas and Louisiana Gulf Coast area.

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

The Company has evaluated subsequent events through November 7, 2011, the date the financial statements were issued.

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.

Diluted shares consist of the following:

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Options to purchase 2,490,004 and 2,490,004 shares were excluded in the three months and nine months ended September 30, 2011, respectively, because they would have been anti-dilutive. Options to purchase 1,420,940 and 1,427,606 shares were excluded in the three months and nine months ended September 30, 2010, respectively, because they would have been anti-dilutive.

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 2011 and 2010 were vested immediately with the others vesting over a two year period. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At September 30, 2011, there were 31,896 shares subject to options authorized but not granted.

For the three months and nine months ended September 30, 2011, the Company recognized non-cash compensation expense of $0.3 million and $1.9 million, respectively, related to stock options. For the three months and nine months ended September 30, 2010, the Company recognized non-cash compensation expense of $0.2 million and $1.6 million, respectively. These amounts were recorded as general and administrative expense. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for tax benefits related to excess stock based compensation deductions.

A summary of the option activity for the nine months ended September 30, 2011 is provided below:

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2011, unrecognized compensation costs totaled $1.3 million. The expense is expected to be recognized over a weighted average period of 1.3 years. Stock options vested during the nine months ended September 30, 2011 totaled 1.3 million options.

Offshore Gabon

In November 2009, the Company negotiated and signed the sixth exploration period extension on the Etame Marin block. The three year extension expires in July 2014. The Company committed to the drilling of two exploration wells and acquiring and processing 150 square kilometers of 3D seismic with a $17.5 million minimum financial commitment ($5.3 million net to the Company). The Company began seismic operations for a short period in November 2010 and resumed seismic activity in October 2011, which upon completion will satisfy the seismic obligation. One of the two required exploratory wells was drilled in the fourth quarter of 2010 with the drilling of the Omangou well, an unsuccessful effort at a cost of $2.6 million, net to the Company.

Onshore Gabon

In October 2010, the Company signed a second exploration period extension for 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 seismic reprocessing began in the first quarter of 2011 and the exploration well is expected to be drilled in the first half of 2012 before the expiration of the exploration period.

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 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 was 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). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company).

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner. In the second quarter of 2011, the government informed the Company it was in negotiations with a potential replacement partner. The negotiations with a potential replacement partner continue, and options to amend the two-well commitment are also being discussed with the Angolan government. Because of the uncertainty surrounding the outcome of the discussions with the Angolan government, in the third quarter of 2011, the Company recorded a full allowance of $4.1 million against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest.

The Company applied for a second time extension in June 2011 as suitable rigs would not be available until after the expiration of the first extension period. The Company has been provided assurances that the extension will be approved; however, the Company can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, the Company may risk forfeiture of its $10.0 million funds in escrow associated with the two-well drilling obligation and may be required to impair its leasehold costs and other investments totaling $11.0 million as of September 30, 2011.

United States

In September 2011, the Company acquired a 65% working interest in approximately 22,000 net acres covering the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana. The Company is obligated to pay for 100% of the costs to drill three wells by the end of 2012, estimated at $15.0 million, including one well by June 1, 2012.

ASC Topic 932 - Extractive Industries provides that an exploration 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, which 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 towards 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.

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. The Company and its partners are evaluating 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 in ASC Topic 932.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. Revenues are based on the location of hydrocarbon production. The Company evaluates each segment based on income (loss) from operations. Segment activity for the three months and nine months ended September 30, 2011 and 2010 are as follows: (in thousands)

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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 (“Exchange Act”). All statements other than statements of historical fact included in this report (and the exhibits hereto), including without limitation, statements regarding the Company’s financial position and estimated quantities and net present values of reserves, and statements preceded by, followed by or that otherwise include the word “believes,” “expects,” “anticipates,” “intends,” “projects,” “target,” “goal,” “objective,” “should,” “estimates,” “predicts,” “budget,” “plans,” “forecast,” “may,” “will” or similar expressions or variations of such expressions are forward looking statements. The Company can give no assurances that the assumptions upon which such statements are based will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations (“Cautionary Statements”) include the volatility of oil and natural gas prices; the uncertainty of estimates of oil and natural gas reserves; the impact of competition; the availability and cost of seismic, drilling and other equipment; operating hazards inherent in the exploration for and production of oil and natural gas; future production costs and quantities; difficulties encountered during the exploration for and production of oil and natural gas; difficulties encountered in delivering oil to commercial markets; potential downgrade of U.S. debt; general economic conditions, including any future economic downturn and the availability of credit; changes in customer demand and producers’ supply; the uncertainty of the Company’s ability to attract capital; currency exchange rates, actions by the governments and events occurring in the countries in which the Company operates; actions by the Company’s 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; labor strikes in the Republic of Gabon; weather conditions and statements set forth in the “Risk Factors” section included in Part II, Item 1A of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010. All subsequent written and oral forward looking statements attributable to the Company or persons acting on its behalf are expressly qualified by the Cautionary Statements.

INTRODUCTION

The Company operates oil production sharing contracts in Gabon and Angola. In the United States the Company operates properties in the Granite Wash formation in Texas and the Middle Bakken formation in Montana. In July 2011, the Company acquired a second lease consisting of 364 acres in North Texas in the Granite Wash formation. Additionally, in September 2011, the Company acquired a 65% working interest in approximately 22,000 net acres covering the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana.

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Additionally, the Company has minor interests in Brazos County, Texas producing from the Buda and Georgetown formations. The Company also owns certain minor non-operated interests in the Ship Shoal area of the Gulf of Mexico and in Pickens County, Alabama.

The Company’s primary source of revenue is from the Etame Marin Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. 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 the first nine months of 2011, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 6.1 million bbls (1.3 million bbls net to the Company). 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 the acquisition and processing of 150 square kilometers of 3D seismic with a $17.5 million minimum financial commitment ($5.3 million net to the Company). The Company began seismic operations for a short period in November 2010 and resumed seismic activity in October 2011, which upon completion will satisfy the seismic obligation. One of the two required exploration wells was drilled in the fourth quarter of 2010 with the drilling of the Omangou well, an unsuccessful effort at a cost of $2.6 million net to the Company.

In October 2010, the Company signed a second exploration period extension on the Mutamba Iroru block onshore in the Republic of Gabon which expires in May 2012. The Company is obligated to reprocess 400 square kilometers of 2-D 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 seismic reprocessing began in the first quarter of 2011, and the exploration well is expected to be drilled in the first half of 2012 before the expiration of the exploration period.

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 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 was 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). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company).

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. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment

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wells. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner. In the second quarter of 2011, the government informed the Company it was in negotiations with a potential replacement partner. The negotiations with a potential replacement partner continue, and options to amend the two-well commitment are also being discussed with the Angolan government. Because of the uncertainty surrounding the outcome of the discussions with the Angolan government, in the third quarter of 2011, the Company recorded a full allowance of $4.1 million against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest.

The Company applied for a second time extension in June 2011 as suitable rigs would not be available until after the expiration of the first extension period. The Company has been provided assurances that the extension will be approved; however, the Company can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, the Company may risk forfeiture of its $10.0 million funds in escrow associated with the two-well drilling obligation and may be required to impair its leasehold costs and other investments totaling $11.0 million as of September 30, 2011.

The Company successfully drilled and completed an exploration well on its initial Granite Wash formation lease in Texas during the third quarter of 2011. The well began production in August 2011 and produced approximately 2,000 barrels of condensate and 132,000 mcf of natural gas in the quarter ended September 30, 2011.

The Company is in the planning stages including contracting for drilling rigs for the two properties where it is the operator in Montana. The Company has a 70% working interest in approximately 5,200 acres in Sheridan County, Montana in the Middle Bakken formation and a 65% working interest in approximately 22,000 acres in Roosevelt County, Montana in the Middle Bakken and lower formations.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for the nine months ended September 30, 2011 was $54.3 million, as compared to $34.9 million for the nine months ended September 30, 2010. Although net income for the nine months ended September 30, 2011 was comparable to net income in the nine months ended September 30, 2010, non-cash adjustments to net income were $23.6 million and $14.1 million for the nine months ended September 30, 2011 and 2010 respectively. Additionally, changes in working capital other than cash used $0.8 million for the nine months ended September 30, 2011, compared to a usage of $11.4 million for the nine months ended September 30, 2010.

Net cash used in investing activities for the nine months ended September 30, 2011 was $19.0 million, compared to net cash used in investing activities for the nine months ended September 30, 2010 of $19.9 million. For the nine months ended September 30, 2011, the Company paid $23.0 million for capital expenditures, of which $9.4 million was spent to acquire mineral interests in various leases in the Granite Wash formation in Hemphill County, Texas, and the Middle Bakken formation in Sheridan and Roosevelt

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Counties, Montana, and $10.1 million was spent to drill and complete the first well on the initial Granite Wash lease. The remainder of the funds were primarily spent in the Etame Marin block offshore Gabon for the expansion of the existing production platforms. These expenditures were partially offset by the release of escrowed funds in Gabon of $3.9 million. For the nine months ended September 30, 2010, the Company drilled two development wells and an exploration well, all in the Etame Marin block for $19.9 million.

For the nine months ended September 30, 2011, cash used in financing activities was $4.0 million consisting of distributions to a noncontrolling interest of $5.2 million and the receipt of $1.2 million in proceeds from the issuance of common stock upon the exercise of stock options. For the nine months ended September 30, 2010, cash used in financing activities of $4.4 million consisted of distributions to a noncontrolling interest owner of $4.5 million and the receipt of $0.1 million in proceeds from the issuance of common stock upon the exercise of stock options.

Capital Expenditures

During the nine months ended September 30, 2011, the Company incurred $24.2 million of net property and equipment additions, primarily associated with the $9.4 million acquisition of various mineral interests in the Granite Wash formation of Hemphill County, Texas and the Middle Bakken formation in Sheridan and Roosevelt Counties, Montana, and the $10.1 million drilling expenditure for the initial well in the Granite Wash formation lease in North Texas. Of the remaining $4.7 million, $4.3 million was incurred on expansion projects for various production platforms offshore Gabon.

During the remainder of 2011, the Company anticipates its share of capital expenditures will be approximately $6.0 million for platform modifications and other capital activity offshore Gabon and $11.0 million for drilling a second Granite Wash formation well in Texas and a well in the Poplar Dome unit in Montana.

Oil and Gas Exploration Costs

The Company uses the “successful efforts” method of accounting for its oil and gas exploration and development costs. All expenditures related to exploration, with the exception of costs of drilling exploration wells are charged as an expense when incurred. The costs of exploration wells are capitalized pending determination of whether commercially producible oil and gas reserves have been discovered. If the determination is made that a well did not encounter potentially economic oil and gas quantities, the well costs are charged as an expense. For the nine months ended September 30, 2011, exploration expense was $3.6 million, which was primarily comprised of $2.0 million spent in North America, $0.5 million offshore Gabon, $0.4 million onshore Gabon, $0.5 million in Angola and $0.3 million in the United Kingdom. For the nine months ended September 30, 2010, exploration expense was $2.1 million which included seismic reprocessing costs in Angola of $0.7 million and seismic reprocessing and other exploration expense in Gabon totaling $1.1 million.

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Liquidity

The Company’s primary source of capital has been cash flows from operations. At September 30, 2011, the Company had unrestricted cash of $112.6 million. The Company believes that this cash combined with cash flow from operations will be sufficient to fund the Company’s remaining 2011 and 2012 capital expenditure budget and additional investments in working capital resulting from potential growth. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, Block 5 in Angola, and the two Middle Bakken formation properties in Montana, 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.

Substantially all of the Company’s crude oil and gas is sold at the well head at posted or index prices under short-term contracts. In Gabon, the Company markets its crude oil under an agreement with Mercuria Trading NV. While the loss of Mercuria Trading NV as a buyer might have a material adverse effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil in Gabon.

Domestically, the Company markets its oil condensate and natural gas under arrangements with Cokinos Energy and Eagle Rock Field Services, LP, respectively. While the loss of Cokinos Energy or Eagle Rock Field Services, LP as buyers might have a material adverse effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its oil condensate and gas in the United States. The Company has access to several alternative buyers for oil and gas sales domestically.

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RESULTS OF OPERATIONS

Three months ended September 30, 2011 compared to three months ended September 30, 2010

Revenues

Total revenues were $37.4 million for the three months ended September 30, 2011 compared to $32.6 million for the comparable period in 2010. The Company sold approximately 324,000 net barrels of oil equivalent at an average price of $112.85 per barrel in the three months ended September 30, 2011. In the three months ended September 30, 2010, the Company sold approximately 429,000 barrels of oil equivalent at an average price of $76.17 per barrel. The lower sales volume is due to two liftings conducted in the quarter ended September 30, 2011 compared to three liftings conducted in the quarter ended September 30, 2010. Crude oil production from the Etame, Avouma, South Tchibala and Ebouri fields averaged approximately 21,500 BOPD compared to approximately 20,600 BOPD in the three months ended September 30, 2010. The production increase in the three months ended September 30, 2011 was due primarily to offshore Gabon development wells drilled in late 2010. Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO and thus crude oil sales do not always coincide with volumes produced in any given quarter.

Domestically, the Company sold approximately 137,000 net mcf of gas at an average price of $5.62 in the three months ended September 30, 2011. The Company sold 2,000 net mcf of gas at an average price of $2.72 in the three months ended September 30, 2010.

Operating Costs and Expenses

Total production expenses for the three months ended September 30, 2011 were $4.5 million compared to $4.8 million for the three months ended September 30, 2010. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized. For the three months ended September 30, 2011, production expenses of $3.0 million were capitalized, as compared to $0.3 million in the same period in 2010. This resulted in lower production expenses in the three months ended September 30, 2011, which were partly offset by higher expenses for Domestic Market Obligation (“DMO”) to the Republic of Gabon. DMO expense of $2.9 million was recorded in the three months ended September 30, 2011, as compared to $0.8 million in the three months ended September 30, 2010.

Exploration expense was $1.3 million for the three months ended September 30, 2011 compared to $0.7 million for the comparable period in 2010. For the three months ended September 30, 2011, exploration expense consisted primarily of $0.6 million for exploration activities in North America, $0.4 million for exploration activities offshore Gabon, and $0.2 million for exploration activities in Angola. Exploration expense for the three months ended September 30, 2010 consisted primarily of exploration activities of $0.2 million offshore Gabon, seismic reprocessing costs of $0.2 million in Angola, and prior year dry hole costs for withholding taxes at the Mutamba Iroru block of $0.2 million.

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Depreciation, depletion and amortization expenses were $5.2 million in the three months ended September 30, 2011 compared to $4.5 million in the three months ended September 30, 2010. Higher depreciation, depletion and amortization expenses during the three months ended September 30, 2011 compared to the three months ended September 30, 2010 were primarily due to depletion expenses recorded for the first Granite Wash well. In addition, the impact of lower sales volumes from offshore Gabon was partially offset by higher depletion rates for the quarter.

General and administrative expenses for the three months ended September 30, 2011 and 2010 were $2.6 million and $0.9 million, respectively. In each of the three month periods ended September 30, 2011 and 2010, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block. Overhead reimbursement for the three months ended September 30, 2011 was $0.5 million compared to $1.9 million for the same period in 2010.

During the three months ended September 30, 2011, the Company recorded a bad debt provision of $4.1 million related to the uncertainty in collecting its joint venture receivables in Angola.

Other Income (Expense)

Other income for the three months ended September 30, 2011 was $0.7 million compared to an expense of $0.3 million for the three months ended September 30, 2010. The other income recorded in the three months ended September 30, 2011 was primarily due to a foreign exchange gain of $0.4 million, while the expense in 2010 was attributable to foreign exchange losses.

Income Taxes

Income tax expense amounted to $17.1 million and $7.4 million for the three months ended September 30, 2011 and 2010, respectively. In the three months ended September 30, 2011 and 2010, the income taxes were all paid in Gabon. Income tax expense for the three months ended September 30, 2011 was higher due to a 12% increase in the oil revenues and a higher percentage of oil allocated as “profit oil” versus “cost oil” in Gabon. The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net Income

Net income including the noncontrolling interest for the three months ended September 30, 2011 was $3.5 million, compared to $13.9 million for the same period in 2010. The lower net income for the three month period in 2011 versus 2010 is mainly attributable to higher income taxes paid to the Republic of Gabon. Net income allocated to noncontrolling interest was $1.1 million and $1.5 million in the three months ended September 30, 2011 and 2010, respectively The noncontrolling interest is associated with VAALCO Energy (International), Inc., a subsidiary that is 90.01% owned by the Company.

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Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Revenues

Total revenues were $142.7 million for the nine months ended September 30, 2011 compared to $96.3 million for the comparable period in 2010. The Company sold approximately 1,262,000 net barrels of oil equivalent at an average price of $112.36 per barrel in the nine months ended September 30, 2011. In the nine months ended September 30, 2010, the Company sold approximately 1,275,000 net barrels of oil equivalent at an average price of $75.69 per barrel. Crude oil production from the Etame, Avouma, South Tchibala and Ebouri fields averaged 22,200 BOPD in the nine months ended September 30, 2011, compared to approximately 20,000 BOPD in the nine months ended September 30, 2010. The production increase in the nine months ended September 30, 2011 was due primarily to production from three development wells drilled in 2010, plus the successful workover of an additional well, all offshore Gabon. Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO and thus crude oil sales do not always coincide with volumes produced in any given quarter.

Operating Costs and Expenses

Total production expenses for the nine months ended September 30, 2011 were $15.5 million compared to $15.9 million in the nine months ended September 30, 2010. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized. For the nine months ended September 30, 2011, production expenses of $3.3 million were capitalized, as compared to $0.3 million in the same period in 2010. The lower production expense for the nine months ended September 30, 2011 was primarily due to higher capitalized production expenses partially offset by higher DMO expense. The higher capitalized production expenses were caused by a higher crude oil inventory balance resulting from two liftings conducted in the quarter ended September 30, 2011, compared to three liftings conducted in the quarter ended September 30, 2010.

Exploration expense was $3.6 million for the nine months ended September 30, 2011 compared to $2.1 million for the comparable period in 2010. Exploration expense for the nine months ended September 30, 2011 included $2.0 million exploration expenditures for North America, $0.4 million onshore Gabon, $0.5 million offshore Gabon, $0.5 million in Angola and $0.3 million in the United Kingdom. Exploration expense for the nine months ended September 30, 2010 included seismic reprocessing costs in Angola of $0.5 million, seismic reprocessing and site survey work on the Etame Marin block totaling $0.4 million and onshore Gabon exploration expense of $0.6 million, which included $0.4 million dry hole costs associated with the two 2009 unsuccessful exploration wells.

Depreciation, depletion and amortization expenses were $17.8 million for the nine months ended September 30, 2011 compared to $12.9 million for the nine months ended September 30, 2010. The higher depreciation, depletion and amortization expense during the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010 was primarily due to higher depletion rates in Gabon and the first production in the United States from the Granite Wash formation in Texas.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

General and administrative expenses for the nine months ended September 30, 2011 and 2010 were $8.1 million and $5.9 million, respectively. In both of the nine months ended September 30, 2011 and 2010, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block. Overhead reimbursement for the nine months ended September 30, 2011 was $1.7 million compared to $4.2 million in the same period in 2010.

During the nine months ended September 30, 2011 the Company recorded a bad debt provision of $4.1 million related to the uncertainty in collecting its joint venture receivables in Angola.

Other Income (Expense)

Other income for the nine months ended September 30, 2011 was $1.2 million compared to expense of $0.5 million for the nine months ended September 30, 2010. The other income recorded in the nine months ended September 30, 2011 was primarily due to a foreign exchange gain of $0.8 million, compared to a foreign exchange loss of $0.6 million for the same period in 2010. Interest income received on amounts on deposit was $0.1 million in each of the nine months ended September 30, 2011 and September 30, 2010.

Income Taxes

Income tax expense amounted to $65.0 million and $26.8 million for the nine months ended September 30, 2011 and 2010, respectively. In the nine months ended September 30, 2011 and 2010, the income taxes were all paid in Gabon. Income tax expense for the nine months ended September 30, 2011 was higher due to a 47% increase in the oil revenues and a higher percentage of oil allocated as “profit oil” versus “cost oil”. The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net Income

Net income including the noncontrolling interest for the nine months ended September 30, 2011 was $29.9 million, compared to a net income of $32.3 million for the same period in 2010. Higher income taxes paid to the Republic of Gabon partially offset by higher oil prices contributed to the lower net income in the nine months ended September 30, 2011. Net income allocated to noncontrolling interest for the nine months ended September 30, 2011 was $4.4 million as compared to $3.8 million for the nine months ended September 30, 2010. The noncontrolling interest is associated with VAALCO Energy (International), Inc., a subsidiary that is 90.01% owned by the Company.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

The Company’s results of operations are dependent upon the difference between prices received for its oil and gas production and the costs to find and produce such oil and gas. Oil and gas prices have been and are expected in the future to be volatile and subject to fluctuations based on a number of factors beyond the control of the Company. The Company does not presently have any active hedges in place, but may do so in the future.

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 files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosure. The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Quarterly Report on Form 10-Q. 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 Quarterly Report on Form 10-Q. There were no changes in the Company’s internal controls over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

There have been no material changes to the disclosure on this matter included in Part II, Item 1A of our quarterly report on Form 10-Q for the quarter ended March 31, 2011, and in our annual report on Form 10-K for the year ended December 31, 2010.

Rule 13a-14(a)/15d-14(a) Certifications

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SIGNATURES

In accordance with the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VAALCO ENERGY, INC.

(Registrant)

Dated: November 7, 2011

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EXHIBIT INDEX

Exhibits

Rule 13a-14(a)/15d-14(a) Certifications

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