UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2014

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, 2014, there were outstanding 57,740,881 shares of common stock, $0.10 par value per share, of the registrant.

VAALCO ENERGY, INC. AND SUBSIDIARIES

Table of Contents

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VAALCO ENERGY, INC. AND SUBSIDIARIES

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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VAALCO ENERGY, INC. AND SUBSIDIARIES

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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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(in thousands of dollars)

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(in thousands of dollars)

 See notes to unaudited condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.       UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND ACCOUNTING POLICIES

The condensed consolidated financial statements of VAALCO Energy, Inc. and subsidiaries (collectively, “VAALCO” or the “Company”), included herein are unaudited, but 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, 2013, 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 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. 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 Equatorial Guinea, West Africa. Domestically, the Company has interests in Texas, Montana, Alabama, and the Louisiana Gulf Coast area.

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

Accounting Policy- Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under accounting principles generally accepted in the United States and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. ASU 2014-09 is effective for annual and quarterly reporting periods of public entities beginning after December 15, 2016. Early application for public entities is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.

Allowance for Bad Debt

On a quarterly basis, the Company evaluates its accounts receivable balances to confirm collectability. When collectability is in doubt, the Company records an allowance against the accounts receivable balances with a corresponding charge to net income as bad debt expense. The Company’s accounts receivable balances are with its joint venture partners, purchasers of its oil, natural gas and natural gas liquids, and with the government of Gabon for reimbursements of Value-Added Tax (“VAT”) paid by the Company. Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company.

In the third quarter of 2014, the Company recorded a bad debt allowance of $1.8 million pertaining to VAT amounts owing for more than twelve months from the government of Gabon.

2.       EARNINGS PER SHARE

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, restricted and unrestricted shares 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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Options to purchase 1,203,324 and 2,364,392 share were excluded in the three months and nine months ended September 30, 2014, because they would have been anti-dilutive.  Options to purchase 3,204,865 and 2,134,300 shares were excluded in the three months and nine months ended September 30, 2013, respectively, because they would have been anti-dilutive.

3.       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 to employees will become exercisable over a period determined by the Compensation Committee, which in the past has been a five year life. A portion of the stock options granted in the nine months ended September 30, 2014 and 2013 vested immediately with the remainder 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 of our Board of Directors. At September 30, 2014, there were 4,537,715 shares subject to options authorized but not granted.

For the three months and nine months ended September 30, 2014, the Company recognized non-cash expense of $0.6 million and $2.7 million, respectively, related to stock based compensation. For the three months and nine months ended September 30, 2013, the Company recognized non-cash expense of $0.4 million and $2.6 million, respectively, related to stock based compensation. 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.

A summary of the stock option activity for the nine months ended September 30, 2014 is provided below:

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.

Shares of restricted stock are granted under the Company’s long-term incentive plan using the fair market value of the underlying shares on the date of grant. In general, restricted stocks granted to employees will vest over a period determined by the Compensation Committee which is generally a three year period, with the initial one-third vesting on the first grant date anniversary.

No restricted stocks were granted in the three months ended September 30, 2014. A summary of the restricted stock activity for the nine months ended September 30, 2014 is provided below:

As of September 30, 2014, unrecognized compensation costs totaled $3.3 million. The expense is expected to be recognized over a weighted average period of 2.6 years.

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4.       COMMITMENTS AND CONTINGENCIES

Gabon

As part of securing the second ten year production license with the government of Gabon for the Etame Marin block, the Company agreed to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement provides for annual funding beginning with the calendar year 2012 and continuing over the remaining life of the production license. Amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The initial funding took place in October 2014 for calendar years 2012 and 2013 totaling $2.4 million net to the Company. The funding for calendar year 2014 is expected to be paid in the fourth quarter of 2014 in the amount of $1.2 million net to the Company.  As in prior periods, the obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet.

The sixth exploration license for the Etame Marin block expired on July 7, 2014.  In the second quarter of 2014, and prior to the deadline, the Company submitted a proposal for a seventh exploration license and is in negotiations with the Republic of Gabon to obtain the extension.  As the Company would not be able to drill the remaining leasehold by the expiration of the exploration license, and due to the uncertainty of obtaining the exploration license, the balance of undeveloped leasehold costs of $0.8 million was recorded as exploration expense in the second quarter of 2014.

Angola

The Company is the operator of Block 5, offshore Angola, a 1.4 million acre property. 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. The Company had a two well exploration commitment per the terms of the primary exploration period.  Due to the uncertainty that the primary term of the exploration license would be extended by the Republic of Angola before the November 30, 2014 expiration date, in October 2014, the Company entered into the Subsequent Exploration Phase (“SEP”), together with its working interest partner, Sonangol P&P, as provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola. The SEP extends the exploration period for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. Entering into the SEP requires the Company and its partner to acquire 3D seismic covering six hundred square kilometers and to drill two additional exploration wells.

By entering the SEP, the Company is now required to drill a total of four exploration wells during the exploration extension period.  The four well obligations include the two well commitments under the primary exploration period that carries over to the SEP period.  A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in November 2017. Restricted cash of $10.0 million for the two new commitment wells will be recorded in the fourth quarter of 2014.

The Company has already satisfied the seismic obligation of the SEP with the purchase of 3D seismic in the outboard segment of the block which is currently being processed and will continue into 2015.

A drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well is expected to begin drilling in December 2014. Drilling this well will satisfy one of the four exploration well obligations and release $5.0 million of the $10.0 million recorded as restricted cash at September 30, 2014 by the Company.

Asset Retirement Obligation

The Company is carrying $13.7 million of asset retirement obligation as of September 30, 2014, representing the present value of our future obligations for the future abandonment costs of tangible assets such as platforms, well, pipelines and other facilities.

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A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows:

In the nine months ended September 30, 2014, the Company increased the asset retirement obligation to recognize the abandonment liability for two new platforms installed in the third quarter of 2014, in offshore Gabon.

5.       CAPITALIZATION OF EXPLORATORY WELL COSTS

ASC Topic 932—Extractive Industries provides that the cost of 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 that is not brought on to production would be assumed to be impaired and its costs would be charged to expense.

Offshore Gabon: In the second and third quarters of 2010, the Company drilled an exploratory well in the Southeast Etame field. A fixed leg platform for developing the Southeast Etame discovery area was constructed and, in the third quarter of 2014, installed.  A drilling rig has been contracted to drill a development well in the Southeast Etame field. The Company has capitalized $7.8 million for the discovery well in accordance with the criteria contained in the ASC Topic 932.

Onshore Gabon:  In the third and fourth quarters of 2012, the Company drilled an exploratory well (N’Gongui No. 2) in the Mutamba Iroru block onshore Gabon. The Company is currently finalizing a revised production sharing contract (“PSC”) with the government of Gabon to allow for development of the discovery. The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Company, its joint venture partner, and the Gabon government on July 31, 2014.  After the PSC is finalized and approved, an application for a development area is expected to be issued. At that point, a plan of development will be submitted to the Republic of Gabon. However, the Company can provide no assurances that such a request will be granted. The Company has capitalized $8.9 million for the discovery well in accordance with the criteria contained in ASC Topic 932.  

6.        DEBT

In January 2014, the Company executed a loan agreement with the International Finance Corporation (“IFC”) for a $65.0 million revolving credit facility, which is secured by the assets of the Company’s Gabon subsidiary. Borrowings under the credit facility totaled $15.0 million as of September 30, 2014 and are due in full upon maturity in January 2019, at which point it can be extended or converted to a term loan. The borrowings approximate fair value as the interest approximates current market rates for similar instruments. The Company is required to comply with certain covenants including maintaining debt to equity ratio of no greater than 60:40, and the ratio of net debt at the end of the quarter, to EBITDAX less than 3. The Company is in compliance with all covenants at September 30, 2014.  

7.       CAPITALIZATION OF INTEREST

Under the terms of the IFC loan executed in 2014, the Company is required to pay a commitment fee on the undrawn component of the credit facility.

The Company capitalizes interest costs and commitment fees on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use. For the three months and nine months ended September 30, 2014, the Company incurred interest expense of $0.3 million and $0.8 million, respectively, in connection with the IFC credit facility. All interest expense was capitalized.

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8.       SEGMENT INFORMATION

The Company’s operations are based in Gabon, Angola, Equatorial Guinea and 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 1.  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 and nine months ended September 30, 2014 and 2013 are as follows:

9.       SUBSEQUENT EVENTS

Gabon

In October 2014, the Company shut-in production from the Ebouri 2-H well due to a pressure communication issue.  The Company is performing diagnostic work to determine the cause and the resolution of the issue. The well was producing approximately 2,500 BOPD on a gross basis (700 BOPD net to the Company).

In October 2014, the Company received a provisional audit report related to our Etame Marin block operations from the Gabon Taxation Department as part of a special industry-wide audit of business practices and financial transactions in the Republic of Gabon.  With limited information pertaining to the report, the Company currently cannot reasonably estimate a range of potential loss, if any, as a result of the audits.  While the ultimate outcome of the claim and impact on VAALCO cannot be predicted, management believes that the claims are unfounded.  In November 2014, the Company responded to the Gabon Taxation Department requesting joint meetings to advance the resolution of this matter.

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Angola

In October 2014, the Company entered into the Subsequent Exploration Phase (“SEP”) together with its working interest partner, Sonangol P&P, as provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola. The Company entered into the SEP due to uncertainty that the primary term of the exploration license would be extended by the Republic of Angola before the November 30, 2014 expiration date. The SEP requires the Company and its partner to acquire 3D seismic covering six hundred square kilometers and to drill two additional exploration wells.  

By entering into the SEP, the Company is now required to drill a total of four exploration wells during the exploration extension period.  The four well obligations include the two well commitments under the primary exploration period that carries over to the SEP period.  A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in November, 2017. Restricted cash of $10.0 million for the two new commitment wells will be recorded in the fourth quarter of 2014.

The Company has already satisfied the seismic obligation with the purchase of 3D seismic in the outboard segment of the block which is currently being processed and will continue into 2015.

A drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well is expected to begin drilling in December 2014. Drilling this well will satisfy one of the four exploration well obligations and release $5.0 million of the $10.0 million recorded as restricted cash at September 30, 2014 by the Company.

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ITEM 2.          MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 future financial position, capitalization of exploration and interest expense, future operating performance and results, reserve quantities and net present values, future commodity prices, business strategy, derivatives activities, the amount and nature of future 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,” “forecast,” “outlook,” “will,” “could,” “should,” “may,” “likely,” “plan,” “probably” or similar expressions, the Company is making forward-looking statements. Many risks and uncertainties 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, but are not limited to: the volatility of oil and natural gas prices; the uncertainty of estimates of oil and natural gas reserves; the impact of competition; the availability and cost of seismic, drilling and other equipment; operating hazards inherent in the exploration for and production of oil and natural gas; difficulties encountered during the exploration for and production of oil and natural gas; difficulties encountered in delivering oil to commercial markets; discovery, acquisition, development and replacement of oil and gas reserves; timing and amount of future production of oil and gas; hedging decisions, including whether or not to enter into derivative financial instruments; our ability to effectively integrate companies and properties that we acquire; general economic conditions, including any future economic downturn, disruption in financial markets and the availability of credit; changes in customer demand and producers’ supply; future capital requirements and the Company’s ability to attract capital; 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, 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; weather conditions; and statements set forth in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013.

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.

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.

INTRODUCTION

VAALCO owns producing properties and conducts exploration activities as an operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, and conducts exploration activities as a non-operator in Equatorial Guinea, West Africa.  VAALCO is the operator of unconventional resource properties in the United States located in Texas and Montana. The Company also owns minor interests in conventional production activities as a non-operator in the United States.

A significant component of the Company’s results of operations is dependent upon the difference between prices received for its offshore Gabon oil production and the costs to find and produce such oil. Oil (and natural 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. Similarly, the costs to find and produce oil and natural gas are largely not within the control of the Company, particularly in regard to the cost of leasing drilling rigs to drill and maintain offshore wells.

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Offshore Gabon

A key focus of the Company is to maintain oil production from the Etame Marin block, located offshore Gabon, at optimal levels. The Company operates the Etame, Avouma, South Tchibala and Ebouri fields on behalf of a consortium of five companies. Three subsea wells, plus production from two platforms, are tied back by pipelines to deliver oil and associated gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased Floating, Production, Storage and Offloading vessel (“FPSO”) anchored to the seabed on the block. With the FPSO limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day, the challenge is to optimize production on both a near and long-term basis subject to investment and operational agreements between the Company and the consortium.

As part of the near-term optimization, drilling and workover campaigns are developed and executed to drill new wells,  replace maturing wells, develop bypassed oil and perform workovers to replace electrical submersible pumps (“ESP’s”)  in existing wells. In the first quarter of 2014, the Company drilled an unsuccessful exploratory well offshore Gabon and performed a workover to replace the ESP’s on a well in the Avouma field. In April 2014, the Company commenced drilling a development well in the South Tchibala field to replace a well with damaged casing. The well was successfully brought on production in May 2014.

Long-term optimization progress continues to be made by the Company and its partners with the successful installation of the two additional offshore production platforms, which were installed in September 2014. The two production platforms are part of the future development plans for the Etame Marin block. One platform is located in the Etame field and the second platform is located between the Southeast Etame and North Tchibala fields. The Company drilled a successful exploration well in the Southeast Etame area in 2010 which will be developed from the second platform. The Company has contracted a drilling rig to commence, at a minimum, a six development well drilling program, which moved onto location and began drilling the first well in October 2014.

The total estimated cost to build and install the platforms is $336.0 million ($102.0 million net to the Company). The cost of the wells is not included in the platform costs.  

In July 2012, the Company discovered the presence of hydrogen sulfide (“H₂S”) from two of the three producing wells in the Ebouri field. The wells were shut-in for safety reasons resulting in a decrease of approximately 2,000 BOPD on a gross basis or approximately 10% of the gross daily production from the Etame Marin block. In addition, field testing conducted in July 2014, confirmed the presence of  H₂S in the Etame 5-H well, and the well has been shut-in. Analysis and options for re-establishing production from the impacted areas continued through the third quarter of 2014.  To re-establish and maximize production from the impacted areas, additional capital investment will be required, including a new centralized platform processing facility capable of removing H₂S from Etame Marin block production, recompletion of the temporarily abandoned wells, and potentially, additional new wells. The Company and its partners have entered the next phase that includes front-end engineering design and cost projections.  Final investment decision is expected in the first quarter of 2015 with a goal of re-establishing production from the area impacted by H2S in the first half of 2017. In October 2014, the Company shut-in production from the Ebouri 2-H well due to pressure communication issue.  The Company is performing diagnostic work to determine the cause and the resolution of the issue. The well was producing approximately 2,500 BOPD on a gross basis (700 BOPD net to the Company).

The sixth exploration license for the Etame Marin block expired on July 7, 2014.  In the second quarter of 2014, and prior to the deadline, the Company submitted a proposal for a seventh exploration license and is in negotiations with the Republic of Gabon to obtain the extension.  As the Company would not be able to drill the remaining leasehold by the expiration of the exploration license, and due to the uncertainty of obtaining the exploration license, the balance of undeveloped leasehold costs of $0.8 million was recorded as exploration expense in the second quarter of 2014.      

Onshore Gabon

The Company operates the Mutamba Iroru block located onshore Gabon. The Company has a 50% working interest in the block (41% net working interest assuming the Republic of Gabon exercises its back-in rights).  The N’Gongui discovery well was drilled in 2012 and the Company is currently finalizing a revised production sharing contract (“PSC”) with the government of Gabon. The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Company, its joint venture partner, and the Government of Gabon on July 31, 2014. After the PSC is finalized and approved, an application for a development area is expected to be issued. At that point, a plan of development will be submitted to the Republic of Gabon. However, the Company can provide no assurances that such a request will be granted.   Development of the onshore block is expected to capitalize on synergies such as office space, warehouse and open yard space and experienced personnel from our operating base in Port Gentil, Gabon.

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Angola

The Company is the operator of Block 5, offshore Angola, a 1.4 million acre property. 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. The Company had a two well exploration commitment per the terms of the primary exploration period. Due to the uncertainty that the primary term of the exploration license would be extended by the Republic of Angola before the November 30, 2014 expiration date, in October 2014, the Company entered into the Subsequent Exploration Phase (“SEP”), together with its working interest partner, Sonangol P&P, as provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola. The SEP extends the exploration period for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. Entering the SEP requires the Company and its partner to acquire 3D seismic covering six hundred square kilometers and to drill two additional exploration wells.

By entering into the SEP, the Company is now required to drill a total of four exploration wells during the exploration extension period.  The four well obligations include the two well commitments under the primary exploration period that carries over to the SEP period. A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in November 2017. Restricted cash of $10.0 million for the two new commitment wells will be recorded in the fourth quarter of 2014.

The Company has already satisfied the seismic obligation of the SEP with the purchase of 3D seismic in the outboard segment of the block which is currently being processed and will continue into 2015.

A drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well is expected to begin drilling in December, 2014. Drilling this well will satisfy one of the four exploration well obligations and release $5.0 million of the $10.0 million recorded as restricted cash at September 30, 2014 by the Company.

Offshore Equatorial Guinea

The Company has a 31% working interest in Block P, offshore Equatorial Guinea. Prior to the Company’s acquisition in the block, two oil discoveries had been made on the block, and there is exploration potential on other areas of the block. The Company continues to work with GEPetrol, the block operator, on a joint operatorship model and with the Ministry of Mines, Industry and Energy regarding timing and budgeting for development and exploration activities.

Domestic

The Company operates two producing wells in the Granite Wash formation in Texas and has a leasehold position in Montana. The Company is not expecting to focus on further domestic activities or property acquisitions in the near term. The Company also owns minor interests in conventional production activities as a non-operator in the United States.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for the nine months ended September 30, 2014 was $54.8 million, as compared to net cash provided by operating activities of $36.8 million for the nine months ended September 30, 2013. The increase in cash from operations for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 was primarily due to an increase in net income by $4.1 million, a positive variance of $15.6 million related to changes in operating assets and liabilities partially offset by a negative variance in non-cash adjustments of $1.8 million.

Net cash used in investing activities for the nine months ended September, 30, 2014 was $68.0 million, compared to net cash used in investing activities for the nine months ended September 30, 2013 of $57.0 million. For the nine months ended September 30, 2014 the Company paid $68.1 million for capital expenditures, primarily related to the construction and installation of the two platforms offshore Gabon. For the nine months ended September 30, 2013 the Company paid $56.1 million for capital expenditures, and added $0.9 million to its restricted cash balance in Gabon.

For the nine months ended September 30, 2014, net cash from financing activities was $16.3 million consisting of $15.0 million of borrowings offset by $1.9 million of debt issuance cost related to the $65.0 million credit facility from the International Finance Corporation (“IFC”). In addition, the Company received proceeds from the issuance of common stock upon the exercise of stock options of $3.2 million net of treasury shares.  For the nine months ended September 30, 2013, net cash used in financing activities was $10.1 million consisting of treasury stock purchases of $10.7 million, partially offset by the receipt of $0.6 million in proceeds from the issuance of common stock upon the exercise of stock options. 

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Capital Expenditures

During the nine months ended September 30, 2014, the Company incurred $65.9 million of net property and equipment additions, primarily associated with the construction and installation of two new platforms offshore Gabon, which total $59.1 million. Additionally, the Company spent $5.8 million related to the drilling of a replacement development well in South Tchibala field, offshore Gabon.  During the fourth quarter of 2014, the Company anticipates its share of capital expenditures will be approximately $25.3 million, primarily associated with the drilling of the Etame 8-H and 9-H wells from the Etame platform offshore Gabon and the spudding of the Kindele well offshore Angola.

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 exploratory wells, are charged as an expense when incurred. The costs of exploratory wells are capitalized pending determination of whether commercially producible oil and natural 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, 2014, exploration expense was $15.2 million, primarily comprised of $11.7 million related to an unsuccessful offshore Gabon exploration well, $1.6 million related to the impairment of leasehold costs offshore Gabon, and $2.0 million in Angola for seismic processing.

For the nine months ended September 30, 2013, exploration expense was $21.5 million, primarily comprised of $11.2 million related to the Company’s unsuccessful exploration activities in the United States, and $9.0 million of dry-hole costs related to two unsuccessful offshore Gabon exploration wells. Additional exploration costs incurred in the nine months ended September 30, 2013 were $0.5 million onshore Gabon, $0.5 million offshore Gabon, and $0.2 million in Equatorial Guinea.

Liquidity

Historically, the Company’s primary sources of capital have been from cash flows from operations and a strong cash balance on hand. The Company also has access to capital through the IFC credit facility as well as future sales of the Company’s debt and equity securities.

At September 30, 2014, the Company had unrestricted cash of $133.5 million. The Company believes that this cash combined with cash flow from operations and the IFC loan facility will be sufficient to fund the Company’s remaining 2014 capital expenditure budget, and additional working capital requirements resulting from potential growth. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, and Block 5 in Angola, the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from its partners prior to significant funding commitments.

In January 2014, the Company finalized a $65.0 million revolving credit facility with the IFC, secured by the assets of the Company’s Gabon subsidiary. Borrowings under the credit facility totaled $15.0 million as of September 30, 2014 and are due in full upon maturity in January 2019 at which point it can be extended or converted to a term loan. The Company was in compliance with all covenants at September 30, 2014 and is required to maintain the following ratios:

Amounts outstanding under the IFC Loan bear interest at the London InterBank Offered Rate (“LIBOR”) plus 3.75% for the senior tranche and LIBOR plus 5.75% for the subordinated tranche. The Company is also required to pay a commitment fee in respect of unutilized commitments, which is equal to 1.5% on the senior tranche and 2.3% on the subordinated tranche. The Company paid a 2.5% closing fee in connection with the loan.

Beginning in the second quarter of 2014, the Company began marketing its oil from Gabon utilizing a third party in order to sell, based on a fixed barrel fee, on spot markets.

Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. The Company has access to several alternative buyers for oil, gas, and natural gas liquids domestically.

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RESULTS OF OPERATIONS

Three months ended September 30, 2014 compared to three months ended September 30, 2013

Total Revenues

Total oil and natural gas revenues were $24.5 million for the three months ended September 30, 2014, compared to $37.7 million for the same period in 2013. The decrease in revenue is primarily related to the lower number of barrels lifted from the Company’s offshore Gabon operations and a decrease in the realized sales price per barrel in the three months ended September 30, 2014 compared to the same period in 2013.

Oil Revenues

Gabon

Crude oil revenues for the three months ended September 30, 2014 were $24.1 million, a $13.2 million decrease, compared revenues of $37.3 million for the same period in 2013.  In the three months ended September 30, 2014, the Company sold approximately 255,000 net barrels of oil at an average price of $94.57 per Bbl, while in the three months ended September 30, 2013 it sold approximately 337,000 net barrels of oil at an average price of $110.54 per Bbl.  Sales volumes decreased in the three months ended September 30, 2014 as compared to the same period in 2013, due to lower number of barrels lifted.

In the three months ended September 30, 2014, the Company produced approximately 411,000 barrels, compared to approximately 437,000 barrels for the same period ended September 30, 2013. The decrease in production was primarily due to a six day shut in of the FPSO for scheduled maintenance and system upgrades. 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.

United States

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the three months ended September 30, 2014 were $51,000, resulting from the sale of approximately 600 net barrels of oil at an average price of $83.49.  For the same period in 2013, condensate sales were $142,000, resulting from the sale of approximately 1,600 net barrels of oil condensate at an average price of $88.83 per Bbl.

Natural Gas Revenues

United States

Natural gas revenues including revenues from natural gas liquids for the three months ended September 30, 2014 were $249,000, compared to $338,000 for the same period in 2013.  Natural gas sales volumes were 54 MMcf at an average price of $4.61 per Mcf for the three months ended September 30, 2014, compared to sales volumes of 74 MMcf at an average price of $4.57 per Mcf for the same period in 2013.

Operating Costs and Expenses

Production expenses for the three months ended September 30, 2014 were $7.1 million, compared to $12.6 million for the same period in 2013.  Operating costs in the three months ended September 30, 2014 were lower than the operating costs for the same period in 2013 as the latter period was impacted by offshore Gabon costs including $2.1 million of well workover costs to replace electrical submersible pumps, $1.0 million related to deck boiler repairs onboard the FPSO, $0.8 million incurred for generator repairs on the Avouma platform, and $0.7 million of costs to  temporarily suspend the Ebouri wells affected by elevated levels of H₂S.

Exploration expenses for the three months ended September 30, 2014 was $0.6 million, compared to $11.1 million for the same period in 2013.  For the three months ended September 30, 2014, exploration expenses consisted primarily of seismic processing in Angola. For the three months ended September 30, 2013, exploration expenses consisted primarily of $6.0 million dry hole costs related to two offshore Gabon unsuccessful exploration wells,  $3.0 million of dry hole costs related to a well drilled in the fourth quarter of 2012 in Roosevelt County, Montana where it was decided in the third quarter of 2013 to not proceed with additional completion activities, and $2.0 million to expense portions of undeveloped leaseholds held in Texas and Montana, United States. 

Depreciation, depletion and amortization expenses were $4.3 million for the three months ended September 30, 2014, compared to $4.0 million for the three months ended September 30, 2013.  The higher depreciation, depletion and amortization expenses during the three months ended September 30, 2014 compared to the same period in 2013 were due to higher depletion rates. Depletion rates for three months ended September 30, 2014 were $11.67 per Bbl, compared to $10.71 Bbl for the three months ended September 30, 2013.

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General and administrative expenses for the three months ended September 30, 2014 and 2013 were $4.0 million and $1.9 million, respectively.  The increase in general and administrative costs for the three months ended September 30, 2014 compared to the same period in 2013 was primarily due to increased personnel costs, and higher professional support services costs. For three month ended September 30, 2014 and 2013, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block.

During the three months ended September 30, 2014, the Company recorded a bad debt allowance of $1.8 million related to past due reimbursements of Value Added Tax (“VAT”) from the government of Gabon. The allowance pertains to amounts owing in excess of twelve months.

Other Income (expense)

Other income for the three months ended September 30, 2014 was $0.2 million, comprised principally of foreign exchange gains.  Other expense for the three months ended September 30, 2013 was $56,000, comprised principally of losses on foreign exchange transactions.  

Income Taxes

Income tax expense amounted to $3.8 million and $5.7 million for the three months ended September 30, 2014 and 2013, respectively.  For the three months ended September 30, 2014 and 2013, the income taxes were all incurred in Gabon.  Income taxes for the three months ended September 30, 2014 were lower due to lower sales volumes and a lower 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 for the three months ended September 30, 2014 was $3.1 million, compared to $2.4 million for the same period in 2013, primarily due to lower expenses.

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013

Total Revenues

Total oil and natural gas revenues were $104.7 million for the nine months ended September 30, 2014, compared to $111.0 million for the same period in 2013. The decrease in revenue is primarily related to the lower number of barrels lifted from the Company’s offshore Gabon operations and a decrease in the realized sales price per barrel in the nine months ended September 30, 2014 compared to the same period in 2013.

Oil Revenues

Gabon

Crude oil revenues for the nine months ended September 30, 2014 were $103.5 million, a $6.0 million decrease from revenues of $109.5 million for the same period in 2013.  The Company sold approximately 989,000 net barrels of oil equivalent at an average price of $104.65 per Bbl for the nine months ended September 30, 2014.  The Company sold approximately 1,013,000 net barrels of oil at an average price of $108.06 per Bbl in the nine months ended September 30, 2013. 

For the nine months ended September 30, 2014, the Company produced approximately 1,246,900 barrels, compared to approximately 985,000 net barrels for the same period ended September 30, 2013. 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.

United States

Condensate sales from the Granite Wash wells, located in Hemphill County, Texas for the nine months ended September 30, 2014 were $259,000, resulting from the sale of approximately 2,500 barrels at an average price of $103.47 per Bbl.  Condensate sales for the nine months ended September 30, 2013 were $336,000, resulting from the sale of approximately 4,000 barrels of oil condensate at an average price of $83.88 per Bbl.

Natural Gas Revenues

United States

Natural gas revenues, including revenues from natural gas liquids, for the nine months ended September 30, 2014 were $0.8 million, compared to $1.2 million for the comparable period in 2013. Natural gas sales volumes were 181 MMcf at an average price of $4.68

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per Mcf for the nine months ended September 30, 2014, compared to sales volumes of 257 MMcf at an average price of $4.50 per Mcf for the same period in 2013.

Production expenses for the nine months ended September 30, 2014 were $21.6 million compared to $28.0 million for the nine months ended September 30, 2013.  The lower production expenses for the nine months ended September 30, 2014 compared to 2013 were primarily associated with lower workover costs to replace electrical submersible pumps on offshore Gabon wells and due to lower FPSO related expenses.

For the nine months ended September 30, 2014, exploration expense was $15.2 million, primarily comprised of $11.7 million related to an unsuccessful offshore Gabon exploration well and $1.6 million related to the impairment of leasehold costs offshore Gabon. Additional exploration costs incurred for the three months ended September 30, 2014 were $2.0 million related to seismic processing in Angola.

For the nine months ended September 30, 2013, exploration expense was $21.5 million, including $11.4 million related to the Company’s unsuccessful exploration activities in the United States properties and $9.0 million in dry-hole costs related to two unsuccessful offshore Gabon exploration wells. Additional exploration costs incurred in the nine months ended September 30, 2013 were $0.5 million onshore Gabon,$0.5 million offshore Gabon, and $0.2 million in Equatorial Guinea.

Depreciation, depletion and amortization expenses were $15.4 million for the nine months ended September 30, 2014 compared to $11.0 million for the nine months ended September 30, 2013.  The higher depreciation, depletion and amortization expenses during the nine months ended September 30, 2014, compared to the same period in 2013, were primarily due to higher depletion rates. Depletion rates increased to $11.58 per Bbl for the nine months ended September 30, 2014 compared to $9.54 per Bbl for the nine months ended September 30, 2013.

General and administrative expenses for the nine months ended September 30, 2014 and 2013 were $10.7 million and $8.0 million, respectively.  The increase in general and administrative costs for the nine months ended September 30, 2014 compared to the same period in 2013 was primarily due to increased personnel costs, and higher professional support services costs. For nine month ended September 30, 2014 and 2013, the Company benefited from overhead reimbursements associated with production and development operations on the Etame Marin block.

During the nine months ended September 30, 2014, the Company recorded a bad debt allowance of $1.8 million related to past due reimbursements of Value Added Tax (“VAT”) from the government of Gabon. The allowance pertains to amounts owing in excess of twelve months.

Other Income (expense)

Other expense for the nine months ended September 30, 2014 was $0.2 million, compared to other expense of $0.1 million for the same period in 2013.  The other expense is comprised principally of foreign exchange losses recorded in the nine months ended September 30, 2014 and 2013.

Income Taxes

Income tax expense amounted to $18.9 million and $24.5 million for the nine months ended September 30, 2014 and 2013, respectively.  In the nine months ended September 30, 2014 and 2013, the income taxes were all incurred in Gabon.  Income taxes in the nine months ended September 30, 2014 were lower due to lower sales volumes and a lower 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 for the nine months ended September 30, 2014 was $20.8 million, compared to a net income of $16.7 million for the same period in 2013, primarily due to lower expenses.

ITEM 3.          QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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.

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ITEM 4.          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 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.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control – Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of September 30, 2014, the Company continues to utilize the 1992 Framework during the transition to the 2013 Framework by December 15, 2014.

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PART II. OTHER INFORMATION

ITEM 1A.       RISK FACTORS

Other than as described below, there have been no material changes with respect to the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2013.

ITEM 6.          EXHIBITS

(a) Exhibits

3. Articles of Incorporation and Bylaws

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

Section 1350 Certificates

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Schema Document.

101.CAL XBRL Calculation Linkbase Document.

101.DEF XBRL Definition Linkbase Document.

101.LAB XBRL Label Linkbase Document.

101.PRE XBRL Presentation Linkbase Document.

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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 10, 2014

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EXHIBIT INDEX

Exhibits

3. Articles of Incorporation and Bylaws

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

Section 1350 Certificates

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Schema Document.

101.CAL XBRL Calculation Linkbase Document.

101.DEF XBRL Definition Linkbase Document.

101.LAB XBRL Label Linkbase Document.

101.PRE XBRL Presentation Linkbase Document.

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