UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

(Mark One)

 

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

For the quarterly period ended September 30, 2015

 

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

For the transition period from _______ to _______

Commission file number 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified 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  ☒    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  ☒    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 check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).          Yes  ☐    No   ☒.

As of October  30, 2015, there were outstanding 58,403,943 shares of common stock, $0.10 par value per share, of the registrant. 

 

 

 

 

 

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VAALCO ENERGY, INC. AND SUBSIDIARIES

Table of Contents

 

 

 Unless the context otherwise indicates, references to “VAALCO,” “we,” “our,” or “us” in this Form 10-Q are references to VAALCO Energy, Inc., including its wholly-owned subsidiaries.

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PART I. FINANCIAL INFORMATION

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS  

(Unaudited)

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

 

See notes to condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)

 

 

See notes to condensed consolidated financial statements.

 

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

(in thousands)

 

 

See notes to condensed consolidated financial statements. 

 

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

 

 

See notes to condensed consolidated financial statements. 

 

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VAALCO ENERGY, INC. AND SUBSIDIARIES 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.  ACCOUNTING POLICIES

VAALCO Energy, Inc. and its consolidated subsidiaries (“VAALCO” or the “Company”) is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. We own producing properties and conduct exploration activities as operator in Gabon, West Africa, conduct exploration activities as an operator in Angola, West Africa, and participate in exploration and development activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of unconventional resource properties in the United States in North Texas and undeveloped leasehold in Montana. We also own some minor interests in conventional production activities as a non-operator in the United States.

Our consolidated 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., VAALCO Energy Mauritius (EG) Limited and VAALCO Energy (USA), Inc.

These condensed consolidated financial statements are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results to be expected for the full year.

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014, which include a summary of the significant accounting policies.

Correction of Immaterial Error

In connection with its assessment of impairment for the three months ended September 30, 2015, the Company identified an immaterial error in the calculation of future cash flows used to determine the impairment amount.  This immaterial error was present in the calculation of the impairment for the December 31, 2014, March 31, 2015 and June 30, 2015 periods.  As a result of this immaterial error, the impairment charge of $98.3 million recorded for the year ended December 31, 2014 was understated by $7.0 million or 7%, and the net loss of $77.6 million was understated by the same amount which represented 9% of the net loss for the period.  For the three months ended March 31, 2015, the impact of the error resulted in an overstatement of the impairment charge of $3.1 million or 57%, and for the three months ended June 30, 2015, the error resulted in an understatement of the impairment charge of $0.5 million or 9%.  As a result, and after considering the related impact on depletion which was overstated, for the three months ended March 31, 2015, the net loss was overstated by $3.5 million or 9%, and for the three months ended June 30, 2015 the net loss was understated by $0.1 million or 1%.  For the six months ended June 30, 2015, the impairment charge was overstated by $2.6 million or 23%.   After considering the related impact on depletion, the net loss for the six months ended June 30, 2015 was overstated by $3.5 million or 8%.

 

In accordance with Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, the Company evaluated these errors, including both qualitative and quantitative considerations, and concluded that the errors did not, individually or in the aggregate, result in a material misstatement of our previously issued consolidated financial statements.  In addition, the Company determined that the inclusion of the correction of the error in the financial statements for the three and nine months ended September 30, 2015 would not, individually or in the aggregate, result in a material misstatement of the current period consolidated financial statements.  The Company has recorded an additional impairment charge of $4.5 million or 33% in the three months ended September 30, 2015 to correct the error related to the prior periods (increase (decrease) to the impairment of $7.0 million attributable to the year ended December 31, 2014, $(3.1) million attributable to the three months ended March 31, 2015 and $0.6 million attributable to the three months ended June 30, 2015). The related impact on depletion was $0.4 million and $0.5 million attributable to the three months ended March 31, 2015 and June 30, 2015.  In total, the net loss for the three months ended September 30, 2015 reflects an additional net charge of $3.6 million (increase (decrease) to the impairment of $7.0 million attributable to the year ended December 31, 2014, $(3.5) million attributable to the three months ended March 31, 2015 and $0.1 million attributable to the three months ended June 30, 2015).  This resulted in an 11% increase in the net loss for the three months ended September 30, 2015. For the nine months ended September 30, 2015, the impact of correcting the error was $7.0 million related entirely to impairment and to the year ended December 31, 2014 period.  This resulted in a 9% increase in the net loss for the period.  

Allowance for Bad Debts

Quarterly, we evaluate our accounts receivable balances to confirm collectability.  When collectability is in doubt, we record an allowance against the accounts receivable and corresponding income charge for bad debts which appears in the Other costs and expenses line of the condensed consolidated statement of operations.  In the three months ended September 30, 2015 and 2014, we

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recorded an allowance of $2.8 million and $1.8 million related to Value Added Tax (“VAT”) which the government of Gabon has not reimbursed. These were the only allowances recorded during the nine months ended September 30, 2015 and 2014. The remaining amount receivable is being reported as a long-term item in the Value added tax receivable line of the September 30, 2015 balance sheet. 

2.  NEW ACCOUNTING STANDARDS

In April 2015, the FASB issued guidance that will require the presentation of debt issuance costs in financial statements as a direct reduction of the related debt liabilities with amortization of debt issuance costs reported as interest expense. Under current U.S. GAAP, debt issuance costs are reported as deferred charges (i.e., as an asset). This guidance is effective for annual periods, and interim periods within those fiscal years, beginning after December 15, 2015 and is to be applied retrospectively upon adoption. Early adoption is permitted, including adoption in an interim period for financial statements that have not been previously issued. We do not expect the adoption of this amended guidance to have a significant impact on our financial position, results of operations or cash flows.

In May 2014, the Financial Accounting Standards Board (“FASB”) issued revised guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a modified retrospective approach. In July 2015, the FASB approved a one year deferral of the effective date of this standard to annual reporting periods beginning after December 15, 2017. The FASB approved early adoption of the standard, but not before the original effective date of December 15, 2016. We are evaluating the transition methods and the impact of the amended guidance could have on our financial position, results of operations, cash flows or related disclosures.

In August 2014, the FASB issued an update to accounting standards that requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. This guidance is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of this standards update and assessing the impact, if any, it may have on our consolidated financial statements.

3.  STOCK-BASED COMPENSATION

Stock options are granted under our 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 participants will become exercisable over a period determined by the Compensation Committee of our Board of Directors, which in the past has been a five year term, with the options vesting over a service period of two to five years. A portion of the stock options granted in the nine months ended September 30, 2015 and 2014 were 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.

We record non-cash compensation expense related to stock-based compensation as general and administrative expense.  For the three and nine months ended September 30, 2015, non-cash compensation expense was $0.7 million and $3.0 million, and was $0.6 million and $2.7 million for the same periods of 2014, related to the issuance of stock options and restricted stock. Because we do not pay significant United States federal income taxes, no amounts were recorded for tax benefits.

Stock option activity for the nine months ended September 30, 2015 is provided below:

Shares of restricted stock are granted under our long-term incentive plan using the fair market value of the underlying shares on the date of grant. In general, restricted stock granted to employees will vest over a period determined by the Compensation Committee which is generally a three year period, vesting in three equal parts on the first three anniversaries of the date of the grant.

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Restricted stock activity for the nine months ended September 30, 2015 is provided below:

 

 

 

 

 

4.  IMPAIRMENT OF PROVED PROPERTIES

We review our oil and gas producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its estimated fair value.

Declining forecasted oil prices in 2015 caused us to perform impairment reviews of our proved properties in each quarter of 2015 for the five fields comprising the Etame Marin block offshore Gabon and the Hefley field in North Texas.  For the three and nine months ended September 30, 2015, impairments of proved properties of $18.0 million and $29.2 million were recorded.

For the quarter ended September 30, 2015, we performed an impairment evaluation using the year end 2014 independently prepared reserve report with reserve revisions based on drilling and production results through September 30, 2015 and forward price curves near September 30, 2015. Impairment was indicated for the North Tchibala field, as a result of lower forecasted oil prices, as well as higher costs for planned development wells used in the impairment evaluation. We recorded an impairment charge of $13.5 million for the quarter ended September 30, 2015, reducing the carrying value of this field to its aggregate fair value of $0.2 million. As discussed further in Note 1, we also recorded impairment charges of $4.5 million and $7.0 million during the three and nine months ended September 30, 2015 to correct an immaterial error related to the impairment calculations in prior periods.

For the quarters ended March 31 and June 30, 2015, we performed impairment evaluations resulting in impairments of $5.4 million for the March 31, 2015 quarter and of $5.8 million for the June 30, 2015 quarter.  These related to the Southeast Etame and North Tchibala fields and were primarily a result of declines in forecasted oil prices, as well as higher costs for planned development wells used in the impairment evaluation.

Each quarter, fair value was measured using a discounted cash flow method and based on estimates of future revenues and costs associated with the Etame Marin block offshore Gabon and the Hefley field in North Texas. Significant Level 3 inputs to the calculation of discounted cash flows include our estimate of future crude oil and natural gas prices, production costs, development costs and anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. For crude oil, estimates were based on NYMEX Brent prices, adjusted for quality, transportation fees, and market differential.

Beginning in the third quarter of 2014, oil prices began a substantial decline which has persisted into 2015. As this period of sustained reduced oil prices continues, further non-cash impairments of proved properties could be necessary in future periods, as a result of further declines in prices, higher than expected capital and production costs, lower production rates or other factors.

In the three and nine months ended September 30, 2014, we determined that no impairment charge was necessary.

5.  EARNINGS PER SHARE

Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, we assume that restricted stock is outstanding on the date of grant, and we assume the issuance of shares from the exercise of stock options using the treasury stock method.

Diluted shares consist of the following:   

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Because we recognized net losses for the three and nine months ended September 30, 2015, there were no dilutive securities for those periods.

6.  SEGMENT INFORMATION

Our operations are based in Gabon, Angola, Equatorial Guinea and the United States (“USA”).  Each of our four reportable operating segments is organized and managed based upon geographic location. Management reviews and evaluates the operation of each geographic segment separately primarily based on Operating income (loss). 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.  Corporate and other is primarily corporate and operations support not allocated to the reportable operating segments.

Segment activity for the three and nine months ended September 30, 2015 and 2014 and segment assets at September 30, 2015 and December 31, 2014 are as follows:

 

 

 

 

 

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7.  CAPITALIZATION OF EXPLORATORY WELL COSTS

At June 30, 2015, we had $9.2 million of exploratory well costs that had been capitalized pending the determination of proved reserves. All costs were related to the N’Gongui No. 2 discovery well that was drilled in the third and fourth quarters of 2012 in the Mutamba Iroru block onshore Gabon.

Since the discovery, we have performed quarterly evaluations of the suspended well costs for the N’Gongui No. 2 discovery to determine whether sufficient progress is being made towards development, as well as the economic and operational viability of the project. The evaluation of economic viability takes into account a number of factors, including alternative development scenarios, estimated reserves, projected drilling and development costs and projected oil price data. As a result of lower projected oil price data at September 30, 2015, the results from the economic modeling indicated that the costs for this well did not continue to meet the criteria for suspended well costs. Accordingly, the costs were recorded in exploration expense in the third quarter of 2015. 

8.  ASSET RETIREMENT OBLIGATIONS 

Asset retirement obligations represent the present value of our future obligations for the future abandonment costs of tangible assets such as platforms, well, pipelines and other facilities. Changes in our asset retirement obligations are presented as follows:

 

In the nine months ended September 30, 2015, we increased the asset retirement obligation to recognize abandonment liabilities for additional offshore Gabon development wells.

ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and gas properties. We use current retirement costs to estimate the expected cash outflows for retirement obligations. These current retirement costs are based primarily on third-party abandonment studies which are performed periodically. As discussed further in Note 11 below, we have commissioned a third party to provide an updated abandonment study this year. Initial indications from the third-party performing the study show that estimated costs have increased, and in turn the asset retirement obligation could increase by $10.0 million to $15.0 million. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

9.  DEBT

In January 2014, we executed a loan agreement with the International Finance Corporation (“IFC”) for a $65.0 million revolving credit facility (“IFC credit facility”), which is secured by the assets of our Gabon subsidiary, VAALCO Gabon (Etame), Inc. In May 2015, the IFC credit facility was amended to remove the affirmative covenant that we maintain a debt to equity ratio at or below that of 60:40, which lifted a restriction on borrowing capacity. Under the amended IFC credit facility agreement, we are required to maintain a ratio of our net debt to EBITDAX (as defined in the credit agreement) of not more than 3.0 to 1.0. The borrowing base under the IFC credit facility is based upon our proved reserves and risk adjusted probable reserves and is re-determined semi-annually by the IFC. In addition, the borrowing base may be adjusted pursuant to certain non-scheduled re-determinations. As a result of the borrowing base redetermination as of June 30, 2015, our borrowing capacity was reaffirmed at the maximum capacity under the facility.

Forecasting our compliance with the financial covenant in future periods is inherently uncertain. Factors that could impact our net debt to EBITDAX in future periods include future realized prices for sales of oil and natural gas, estimated future production, returns generated by our capital program, and future interest costs, among others. We are in compliance with all financial covenants as of September 30, 2015.

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Borrowings outstanding under the IFC credit facility were $15.0 million as of September 30, 2015, and are due in full upon maturity in December 2019. The borrowings approximate fair value, as the interest approximates current market rates for similar instruments. The interest rate on outstanding borrowings, excluding commitment fees, was 4.0% in the three and nine months ended September 30, 2015.  Interest expense incurred, including commitment fees on the available balance, was $0.4 million and $1.1 million for the three and nine months ended September 30, 2015.

We capitalize interest and commitment fees related to 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 and nine months ended September 30, 2015 $0.2 million and $0.8 million of interest expense was capitalized, while $0.3 million and $0.8 million of interest expense was capitalized for the three and nine months ended September 30, 2014.

10.  SHAREHOLDERS’EQUITY

Preferred Stock

Authorized preferred stock consists of 500,000 shares with a par value of $25 per share, of which 15,000 shares were designated on September 26, 2015 as Series A Junior Participating Preferred Stock (“Series A Preferred Stock”) by the VAALCO Board of Directors (“Board of Directors”) in accordance with the Stockholder Rights Agreement discussed below.  No shares of preferred stock were issued and outstanding as of September 30, 2015 or 2014.

Treasury Stock

In the nine months ended September 30, 2015, we withheld 114,985 shares to satisfy tax withholding obligations related to stock option exercises.

Stockholder Rights Agreement

On September 26, 2015, VAALCO entered into a Rights Agreement (the “Rights Agreement”) with Computershare Trust Company, N.A., as Rights Agent, pursuant to which the Board of Directors declared a dividend of one right (“Right”) for each outstanding share of common stock to stockholders of record at the close of business on October 7, 2015.  Each Right entitles the registered holder to purchase from VAALCO one ten-thousandth of a share of Series A Preferred Stock at a price of $7.20, subject to certain adjustments (the “exercise price”).  As of November 6, 2015, the Rights were not exercisable and remained attached to the shares of common stock.

The Rights will not be exercisable until the earlier to occur of (i) the tenth business day following a public announcement or filing that a person has, or group of affiliated or associated persons or persons acting in concert (as defined in the Rights Agreement) have, become an “Acquiring Person,” which is defined as a person or group of affiliated or associated persons or persons acting in concert who, at any time after the date of the Rights Agreement, have acquired, or obtained the right to acquire, beneficial ownership of 10% or more of VAALCO’s outstanding shares of common stock, subject to certain exceptions, or (ii) the tenth business day (or such other date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the commencement of, or announcement of an intention to commence, a tender offer or exchange offer, the consummation of which would result in any person becoming an Acquiring Person.

In the event that, after a person or a group of affiliated or associated persons has become an Acquiring Person, VAALCO is acquired in a merger or other business combination transaction, or 50% or more of VAALCO’s assets or earning power are sold, each holder of a Right will thereafter have the right to receive, upon the exercise thereof at the then current exercise price of the Right, that number of shares of common stock of the acquiring company having a value at the time of that transaction equal to two times the exercise price of the Right.

At any time after any person or group of affiliated persons becomes an Acquiring Person and prior to the Acquiring Person’s acquisition of 50% or more of VAALCO’s outstanding common stock, the Board of Directors, at its option, may exchange all or part of the then outstanding and exercisable Rights for shares of common stock at an exchange ratio of one share of common stock per outstanding Right (subject to adjustment).   At any time before any person or group of affiliated or associated persons becomes an Acquiring Person, the Board of Directors may redeem the Rights in whole, but not in part, at a price of $0.001 per Right (subject to certain adjustments).

11.  COMMITMENTS AND CONTINGENCIES

Subsequent Events

On November 6, 2015, a stockholder group consisting of Group 42, Inc., Bradley L. Radoff and certain other participants (collectively, the “Group 42-BLR Group”) filed a preliminary consent solicitation statement on Schedule 14A with the Securities and Exchange Commission.  The Group 42-BLR Group intends to attempt to amend our bylaws, remove four duly elected members of our Board of Directors and replace them with Group 42-BLR Group’s nominees. VAALCO intends to vigorously defend itself and continue to act in the best interests of all stockholders.

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Lease Obligations

We contracted for two drilling rigs during the year ended December 31, 2014. In April 2014, we contracted with a drilling rig to begin a multi-well development drilling campaign offshore Gabon. The campaign includes drilling of development wells from the Etame platform, development wells from the Southeast Etame/North Tchibala (“SEENT”) platform and workovers of existing wells in the Etame Marin block. The rig commenced drilling activities in October 2014 and continues under a contract until July 2016, at a day rate of approximately $168,000 on a gross basis for 2015 and $172,000 on a gross basis for 2016. Our net share of the initial total commitment related to this rig was $25.8 million. As a result of drilling activity through September 30, 2015, the remaining net share of the commitment is $14.3 million. 

The second drilling rig contract was signed in July 2014 for a semi-submersible rig to drill an exploration well on the Kindele prospect, a post-salt objective on Block 5, offshore Angola.  The Kindele well was drilled in the first quarter of 2015 and the rig was released on April 19, 2015.  We have no further commitment under this contract.

Gabon

Offshore

Abandonment

As part of securing the first of two-five year extensions to the Etame field production license to which we are entitled from the government of Gabon, we agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block. The agreement was finalized in the first quarter of 2014 (effective 2011) providing for annual funding over a period of ten years at 12.14% of the total abandonment estimate for the first seven years and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable. The abandonment estimate originally used for this purpose is approximately $10.1 million net to VAALCO on an undiscounted basis. The initial funding took place in October 2014 for calendar years 2012 and 2013 totaling $8.4 million ($2.3 million net to VAALCO). The funding for calendar year 2014 was paid in the first quarter of 2015 in the amount of $4.2 million ($1.2 million net to VAALCO).  The obligation for abandonment of the Gabon offshore facilities is included in the Asset retirement obligation shown on our balance sheet. This cash funding is reflected under other long term assets as Abandonment funding.

We are required under the Etame production sharing contract to conduct regular abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin Block. In September 2015, we commissioned a new abandonment study. Due to two new platforms and to the development wells drilled since the prior study, the final results of the abandonment study will result in an increase in the amounts necessary to fund future abandonment obligations. We will be required to expend greater amounts than are currently being funded, which may have an adverse effect on our cash flow.  Additionally, no assurances can be given that future cash flows from our reserves will be sufficient to cover such costs as they are incurred in the future. Initial indications from the third-party performing the study show that estimated costs have increased. This would increase the abandonment estimate used for funding purposes from the $10.1 million net to VAALCO on an undiscounted basis currently used to between $14.0 million and $28.0 million, and in turn the annual abandonment requirements for 2015 through 2021 are expected to increase by between $0.6 million and $2.5 million.

Audits

In October 2014, we received a provisional audit report related to the 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.  In November 2014, we responded to the Gabon Taxation Department requesting joint meetings to advance the resolution of this matter and later provided a formal reply to the provisional audit report in February 2015.  A tentative agreement was reached with the Gabon Taxation Department in April 2015, and we are working with the Gabon Taxation Department to finalize the audit. We expect that resolution of the audit exceptions will not result in a material impact to our financial position, results of operations or cash flows.

The audit of 2011 and 2012 by the Directorate General of Hydrocarbons (“DGH”), which is responsible for implementation of oil policy and the management and development of oil and gas resources in Gabon, was fully resolved and settled in September 2015 for $0.3 million net to VAALCO.

Angola    

Offshore

In November 2006, we signed a production sharing contract for Block 5 offshore Angola. The four year primary term, with an optional three year extension, awards us exploration rights to 1.4 million acres offshore central Angola. Our working interest is 40%. Additionally, we are 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, we had commitments to acquire and process seismic and drill two exploration wells.  The seismic commitments were met within the time period, but the wells were not drilled due to partner non-performance.

The government-assigned working interest partner was delinquent in 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

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from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Additional extensions were subsequently granted by the Angolan government until November 30, 2014 to drill the two exploration commitment wells.

In the fourth quarter of 2013, we received a written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, had been assigned to Sonangol E.P., the National Concessionaire.  The Ministry of Petroleum also confirmed that Sonangol E.P. would assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The assignment was made effective on January 1, 2014. Our position is that the unpaid amounts from the defaulted partner plus the amounts incurred on the partner’s behalf during the period prior to assignment of the working interest to Sonangol P&P are the responsibility of the acquirer of the working interest. We invoiced Sonangol P&P for these amounts totaling $7.6 million plus interest in April 2014.  Due to the uncertainty of collection, we have recorded a full allowance totaling $7.6 million during 2011 through 2013 for the amount owed us above our 40% working interest plus the 10% carried interest. Because this amount continues to be owed and due to slow payment history of the monthly cash call invoices since their assignment date of January 1, 2014, we placed Sonangol P&P in default in the first quarter of 2015. Sonangol E.P. acknowledged the legitimacy of the amounts owed and pledged to work to bring the Sonangol P&P account to a current status. Although payments totaling $22.2 million have been received from Sonangol P&P in 2015, they continue to be in default as of November 6, 2015 due to non-payment of the pre-assignment costs and unpaid recent cash call invoices.  The balance in Accounts with partners includes a joint interest receivable of $7.3 million at September 30, 2015.

In April 2014, we received a letter and contractual amendment proposal from Sonangol E.P., related to the extension of the two well drilling commitment, prior to the expiration of the extension on November 30, 2014. 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, we entered into the Subsequent Exploration Phase (“SEP”), together with our working interest partner, Sonangol P&P. 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 us and our partner to acquire 3D seismic covering a total of six hundred square kilometers and to drill two additional exploration wells.

We satisfied the seismic obligation of the SEP with the 2013 acquisition of additional seismic data covering the deeper segment of the block.  Processing of the seismic data began in 2014 and was completed in 2015, with evaluation continuing in 2015.

After entering into the SEP, we are required to drill a total of four exploration wells during the exploration extension period. This four well obligation includes 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.  In the first quarter of 2015, we drilled an unsuccessful exploratory well on the Kindele prospect, a post-salt objective. At September 30, 2015, the $15.0 million included in long-term restricted cash reflected on our balance sheet is related to the remaining 3 well commitment under the offshore Angola exploration agreement.

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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, (the “Exchange Act”) which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, plans and objectives of our management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “will,” “could,” “should,” “may,” “likely,” “plan,” “probably” or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

The information contained in this report and the information set forth under the heading “Risk Factors” set forth in our Annual Report on Form 10-K for the year ended December 31, 2014 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2015 identifies additional factors that could cause our results or performance to differ materially from those we express in our forward-looking statements. Although we believe that the assumptions underlying our 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, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this report.

Our forward-looking statements speak only as of the date made and we will not update these forward-looking statements unless the securities laws require us to do so. Our 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.

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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 participates in exploration and development activities as a non-operator in Equatorial Guinea, West Africa.  VAALCO is the operator of unconventional resource properties in the United States in North Texas and unproved leasehold in Montana. We also own minor interests in conventional production activities as a non-operator in the United States.

A significant component of our results of operations is dependent upon the difference between prices received for our 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 our control. Beginning in the third quarter of 2014, the prices for oil and natural gas began a dramatic decline, and current prices are significantly less than they have been over the last several years.  Sustained low oil and gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and the borrowing base under our International Finance Corporation credit facility (“IFC credit facility”). As with prices received for oil production, the costs to find and produce oil and natural gas are largely not within our control, particularly in regard to the cost of leasing drilling rigs to drill and maintain offshore wells. 

CURRENT DEVELOPMENTS    

In the nine months ended September 30, 2015, prices for oil, natural gas and natural gas liquids have continued to decline, and they continue to remain low by historical standards. These low prices have affected our business in numerous ways, including:

Price declines can also adversely affect future semi-annual determinations of the amount we can borrow under our IFC credit facility since that determination is based mainly on the value of our oil and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects. We amended our IFC credit facility in May 2015 to remove the affirmative covenant that we maintain a debt to equity ratio at or below that of 60:40 which will help preserve our liquidity and financial flexibility.

We may also pursue ways to increase liquidity and increase activity within our asset base by pursuing joint ventures, farm-outs of our acreage and/or the monetization of our producing assets. We can give no assurances that such transactions can be completed on terms acceptable to us. 

As discussed in Note 4 to the condensed consolidated income statements, we have recorded impairments of our proved properties in each of the three quarters of 2015. We may experience additional write-downs in the fourth quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, and reserve additions and adjustments. Impairments calculated for this and previous quarters have been based upon reserve economics using forecasted future prices, adjusted for specifics related to our production.  If per barrel prices had been $5.00 lower, our third quarter impairment would have increased by approximately $19 million. Given the uncertainty associated with the factors used in these calculations, these estimates should not necessarily be construed as indicative of our future financial results. 

Gabon

Offshore

Development and Production

One of our key focuses is maintenance of oil production from the Etame Marin block, located offshore Gabon in which our working interest is 28.1%. We operate the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of five companies. As part of the ongoing development plans for the Etame Marin block, two new production platforms, the Etame and Southeast Etame/North Tchibala (“SEENT”) platforms, were installed in the offshore waters of Gabon in the third quarter of 2014. As of September 30, 2015 production from three subsea wells and nine platform wells 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 barrels of oil per day (“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 VAALCO and the consortium.

As part of the near-term optimization, drilling and workover campaigns are developed and executed to drill new wells, develop bypassed oil and perform workovers to replace electrical submersible pumps (“ESPs”) in existing wells.  Thus far in 2015, two new development wells were drilled and brought on production from the Etame platform offshore Gabon.  The Etame 10-H well was brought on production in the first quarter of 2015, and the Etame 12-H well, which began drilling in March 2015, was brought on

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production in the second quarter of 2015.  We believe that the Etame 10-H well also confirmed the presence of an undrained lower lobe of the Gamba reservoir.

With the drilling rig under long-term contract, we moved it early in the second quarter of 2015 to the SEENT platform offshore Gabon.  Two new development wells were drilled and brought on production from this platform as of September 30, 2015.  The Southeast Etame 2-H well, drilled to a field where we had exploration success in 2010, was brought on production in July 2015. The Southeast Etame 2-H well required re-drilling a segment of the well following a mechanical failure. The North Tchibala 1-H well, targeting the Dentale formation also required re-drilling a segment of the well due to wellbore collapse. The well was brought on production in mid-September 2015. Oil discoveries were made in the North Tchibala field in the Dentale formation prior to our acquisition of the Etame Marin block in 1995.    We are currently drilling the North Tchibala 2-H well from the SEENT platform. This is our second well targeting the Dentale formation, and it is expected to be completed in November 2015. Given favorable sea state conditions, the contract rig will then move to the Avouma/South Tchibala platform to perform workovers to replace electrical submersible pumps on three existing wells, two of which are currently off production.

The 2015 annual maintenance turnaround for the FPSO has been rescheduled to January 2016.  It is expected to last approximately six days.  During this time period, all production will be shut-in.

Oil Reserves Impacted by Hydrogen Sulfide (“H₂S”)

With respect to longer-term optimization, the Etame consortium is evaluating options for handling oil containing H₂S that has impacted certain wells in the Ebouri and Etame fields.  In July 2012, we discovered the presence of H₂S from two of the three producing wells in the Ebouri field. The wells were shut-in for safety and marketability reasons resulting in a production decrease of approximately 2,000 BOPD on a gross basis, or approximately 10% of the gross daily production from the Etame Marin block at that time. In addition, H₂S was first detected in January 2014 and later confirmed in July 2014 in the Etame 5-H well in the Etame field,  The Etame 8-H well was drilled in the fourth quarter of 2014 and testing in the first quarter of 2015 confirmed the presence of H₂S.  Both the Etame 5-H and 8-H wells remain shut-in.    

To re-establish and maximize production from the impacted areas, additional capital investment will be required, including one or more processing facilities capable of removing H₂S, recompletion of the temporarily abandoned wells, and potentially, additional new wells. Considering the sustained low oil prices, we and our partners are focusing on more cost efficient options for one or more processing facilities (e.g. chemical removal options, construction of a smaller facility on existing structures, or the use of surplus equipment and used structures). We continue to evaluate the economics of various alternatives, and we expect to present the outcome of the evaluation to our partners in the fourth quarter of 2015. 

There can be no assurances that any processing facilities will be completed by 2017, if at all, or that a more cost effective facility will cover all affected areas of the Ebouri and Etame fields.  Should the evaluation result in no economic alternative, a decrease of as much as 2.4 million barrels of proved undeveloped reserves could result.

Impairment

In the fourth quarter of 2014, we recorded an impairment loss of $98.3 million to write down our investment in certain fields comprising the Etame Marin Block, offshore Gabon, to fair value as a result of the declines in the forecasted oil prices used in the impairment testing and calculation.  As a result of further declines in prices and increased development well costs, during the first and second quarters of 2015, we recorded impairments totaling $11.2 million for the six months ended June 30, 2015 to write down our investment in the Southeast Etame and North Tchibala fields offshore Gabon.  For the quarter ended September 30, 2015, impairment was indicated for the North Tchibala field, primarily as a result of lower forecasted oil prices as well as higher costs for planned development wells used in the impairment evaluation. We recorded an impairment charge of $13.5 million in the quarter ended September 30, 2015.  As discussed further in Note 1 to the condensed consolidated financial statements, we also recorded an impairment charge of $4.5 million during the three months ended September 30, 2015 to correct an immaterial error related to the impairment calculations in prior periods.

Onshore

VAALCO operates the Mutamba Iroru block located onshore Gabon. We have a 50% working interest in the block (41% net working interest assuming the Republic of Gabon exercises its back-in rights).  After drilling two unsuccessful exploration wells on the block in 2009, we entered into an agreement with Total Gabon to continue the exploration activities. Following seismic reprocessing, a well was drilled in 2012, resulting in a discovery.

Since mid-2014, we have been working to finalize a revised or new production sharing contract (“PSC”) with the government of Gabon to allow for development of the discovery and to maintain exploration rights on the block.  A term sheet, which specifies financial and other obligations to be included in a new PSC, was signed in the third quarter of 2014.

A letter received in September 2015 from the Gabon government expressed their view that the initial PSC has expired and encouraged us to expeditiously enter into a new PSC along the terms of the signed term sheet which, among other factors, honors the 2012 discovery and the accumulated cost account which is used in the calculation of Gabon production taxes.  We and our joint venture partner do not agree with the government’s assertion that the initial PSC has expired, but did reach agreement on entering into a revised/new PSC in accordance with the term sheet agreement. 

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Meetings were held in October 2015 with the government regarding further amendments to the previously agreed terms of a new PSC, taking into account the substantial decrease in the oil price compared to the price environment when the term sheet was signed in the third quarter of 2014.  We have also met with the joint venture partner in October 2015 and anticipate further meetings with the joint venture partner and the government will take place in the fourth quarter of 2015.

We can provide no assurance that we, with or without the joint venture partner, will enter into a new PSC. We can provide no assurances as to either the approval of the PSC by the Government of Gabon, or the subsequent approval of a development area by the Government of Gabon. As discussed further in Note 7 to the condensed consolidated financial statements, the September 30, 2015 evaluation of the suspended well costs for the N’Gongui No. 2 well resulted in a determination that these costs no longer met the criteria, and accordingly we included the costs in exploration expense for the three months ended September 30, 2015.

Angola

Offshore

In November 2006, we signed a production sharing contract for Block 5, offshore Angola. The four year primary term, with an optional three year extension, awarded us exploration rights to 1.4 million acres offshore central Angola. VAALCO’s working interest is 40%. Additionally, we are 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, we had commitments to acquire and process seismic and drill two exploration wells.  The seismic commitments were met within the time period, but the wells were not drilled due to partner non-performance.

The government-assigned working interest partner was delinquent in 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. Additional extensions were subsequently granted by the Angolan government until November 30, 2014 to drill the two exploration commitment wells.

In the fourth quarter of 2013, we received a written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, has been assigned to Sonangol E.P., the National Concessionaire.  The Ministry of Petroleum also confirmed that Sonangol E.P. would assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The assignment was made effective on January 1, 2014. Our position is that the unpaid amounts from the defaulted partner plus the amounts incurred on the partner’s behalf during the period prior to assignment of the working interest to Sonangol P&P are the responsibility of the acquirer of the working interest.  We invoiced Sonangol P&P for these amounts totaling $7.6 million plus interest in April 2014.  Due to the uncertainty of collection, we have recorded a full allowance totaling $7.6 million during 2011 through 2013 for the amount owed above its 40% working interest plus the 10% carried interest. Because this amount continues to be owed and due to slow payment history of the monthly cash call invoices since their assignment date of January 1, 2014, we placed Sonangol P&P in default in the first quarter of 2015.   Sonangol E.P. acknowledged the legitimacy of the amounts owed and pledged to work to bring the Sonangol P&P account to a current status. Although payments totaling $22.2 million have been received from Sonangol P&P in 2015, they continue to be in default as of November 6, 2015 due to non-payment of the pre-assignment costs and unpaid recent cash call invoices. The balance in Accounts with partners includes a joint interest receivable of $7.3 million at September 30, 2015.

In April 2014, we received a letter and contractual amendment proposal from Sonangol E.P., related to the extension of the two well drilling commitment, prior to the expiration of the extension on November 30, 2014. 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, we entered into the Subsequent Exploration Phase (“SEP”), together with our working interest partner, Sonangol P&P. 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 us and our partner to acquire 3D seismic covering a total of six hundred square kilometers and to drill two additional exploration wells.

We satisfied the seismic obligation of the SEP with the 2013 acquisition of additional seismic data covering the deeper segment of the block.  Processing of the seismic data began in 2014 and was completed in 2015, with evaluation continuing in 2015.

By entering into the SEP, we are 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.  In the first quarter of 2015, we drilled an unsuccessful exploratory well on the Kindele prospect, a post-salt objective. At September 30, 2015, the $15.0 million included in long-term restricted cash on our balance sheet is related to the remaining 3-well commitment under the offshore Angola exploration agreement.

The exploratory well on the Kindele prospect was drilled in the first quarter of 2015, and while thick, well-developed sands were encountered in the primary objectives, the sands were determined to be water-bearing, and the well was plugged and abandoned.  Accordingly, we charged $27.2 million to exploration expense in the first quarter of 2015 for the well and related unproved leasehold impairment. 

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Equatorial Guinea

Offshore

VAALCO has a 31% working interest in a portion of Block P, offshore Equatorial Guinea, which was acquired for $10.0 million in 2012 primarily for the exploration potential on the block. Prior to our acquisition in the block, two oil discoveries had been made on the block, establishing a development and production area in the block (the “PDA”). At the time the PDA was established, the block was divided into PDA and non-PDA portions, and we do not have a participating interest in the non-PDA portion of the block. VAALCO continues to work with the Ministry of Mines, Industry and Energy and GEPetrol, the current block operator, on a revised joint operating agreement which we expect will name VAALCO as operator.  We and our partners are also working on timing and budgeting for development and exploration activities in the PDA, including the approval of a development and production plan. Development project economics are being re-evaluated considering the continued depressed oil prices and the expected decrease in development costs associated with the fall in oil prices. The production sharing contract covering the PDA provides for a development and production period of twenty-five years from the date of approval of a development and production plan.

United States

VAALCO operates two producing wells in the Granite Wash formation in Texas and has a leasehold position in Montana. Due to the sustained low oil prices, we charged approximately $0.6 million of our $1.2 million undeveloped leasehold position in Montana to exploration expense in the nine months ended September 30, 2015. We also own minor interests in conventional production activities as a non-operator in the United States.  During the nine months ended September 30, 2015, we sold certain of these minor interests for $0.4 million. 

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the nine months ended September 30, 2015 and 2014 are as follows:

 

The decrease in net cash from operating activities was primarily related to the significantly lower crude oil prices in 2015, which reduced net income.

Property and equipment expenditures are our most significant investing activities.  During the nine months ended September 30, 2015, these expenditures on a cash basis were $72.2 million compared to $68.1 million in the same period of 2014. These cash property and equipment expenditures are included in capital expenditures. See “Capital Expenditures” below for further discussion. In addition, restricted cash decreased by $5.5 million during the nine months ended September 30, 2015, primarily as a result of fulfilling the commitment for one of the four exploration wells in Angola. 

Net cash provided by financing activities of $0.5 million in the nine months ended September 30, 2015 related to stock option exercises. This compares to $16.3 million provided by financing activities in the nine months ended September 30, 2014 which is primarily related to borrowings under the IFC facility.

Capital Expenditures

During the nine months ended September 30, 2015, our capital expenditures (on an accrual basis), including dry hole costs expended in the period, were $75.4 million compared to $65.9 million in the same period of 2014. The difference between capital expenditures and the property and equipment expenditures reported in the Condensed Consolidated Statement of Cash Flows is attributable to changes in accruals for costs incurred but not yet invoiced or paid on the report date. Capital expenditures in 2015 were primarily associated with the drilling of four development wells offshore Gabon and the unsuccessful exploratory Kindele well offshore Angola. Capital expenditures in 2014 were primarily associated with the construction of the two new platforms offshore Gabon. We began drilling the North Tchibala 2-H in September 2015 and results are expected before year end. Our net share of capital expenditures is expected to  be  $10.0 million to $11.0 million in the fourth quarter of 2015.   

Liquidity

Credit Facility

Historically, our primary sources of capital have been cash flows from operating activities and cash balance on hand. We also have access to capital through the IFC credit facility, as well as future sales of our debt and equity securities.

We have a $65.0 million revolving credit facility with the IFC credit facility, which is secured by the assets of our Gabon subsidiary, VAALCO Gabon (Etame), Inc. In May 2015, the IFC credit facility was amended to remove the affirmative covenant that we

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maintain a debt to equity ratio at or below that of 60:40, which lifted a restriction on borrowing capacity. Borrowings outstanding under the IFC credit facility were $15.0 million as of September 30, 2015, and are due in full upon maturity in December 2019 at which point it can be extended or converted to a term loan. Under the IFC credit facility we are required to maintain the ratio of net debt to earnings before interest, tax, depreciation and amortization, and exploration expenses (EBITDAX), for the 12 trailing months ended on the most recent quarter end date, at less than 3:1. We were in compliance with all financial covenants at September 30, 2015.

The borrowing base under the IFC credit facility is based upon our proved reserves and risk adjusted probable reserves and is re-determined semi-annually by the IFC. In addition, the borrowing base may be adjusted pursuant to certain non-scheduled re-determinations. As a result of the borrowing base redetermination as of June 30, 2015, our borrowing capacity was reaffirmed at the full $65 million level, the maximum capacity under the facility; therefore $50 million is available for borrowing at September 30, 2015.

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. We are 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.

At September 30, 2015, we had unrestricted cash of $ 40.7 million. We believe that this cash, combined with cash flow from operations will be sufficient to fund our remaining 2015 capital expenditure budget, which in total for the year is expected to be in the range of $83 million to $86 million, and any 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, we enter into project related activities on behalf of our working interest partners. We generally obtain advances from partners prior to significant funding commitments.

Through April 2015, we  sold our crude oil production from Gabon using an agency model under a contract with a third party to sell, based on a fixed barrel fee, on the spot market. We currently sell our crude oil production from Gabon under a term contract with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors, that ends in July 2016.  Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. We have access to several alternative buyers for oil, gas, and natural gas liquids domestically.

Share Repurchase

On August 4, 2015, we announced that our Board of Directors authorized a share repurchase program allowing us to repurchase up to approximately 5.8 million shares of our common stock through February 3, 2017. Under the share repurchase program, the common stock could be purchased on the open market, in privately negotiated transactions or otherwise in compliance with all of the conditions of Rule 10b-18 under the Securities Exchange Act of 1934, as amended. The timing of the common stock repurchased will be at the discretion of management and will depend on a number of factors, including price, market conditions and regulatory requirements. We retain the right to limit, terminate or extend the share repurchase program at any time without prior notice. Payment for shares repurchased under the program will be from cash on hand.  No purchases were made under this share repurchase program in the quarter ended September 30, 2015.

OFF-BALANCE SHEET ARRANGEMENTS

Our guarantee of the offshore Gabon FPSO lease has $158 million in remaining minimum obligations for the gross amount of charter payments at September 30, 2015. There have been no other changes to our off-balance sheet arrangements since December 31, 2014.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

Refer to Note 11 to the condensed consolidated financial statements for discussion of changes in leases related to rig commitments and updates on other significant contractual commitments.

CRITICAL ACCOUNTING POLICIES

There have been no changes to our critical accounting policies subsequent to December 31, 2014.

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three and nine months  ended September 30, 2015 compared to the three and nine months ended September 30, 2014

We reported net losses for the three and nine months ended September 30, 2015 of $33.7  million and $77.9 million compared to net income of $3.1 million and $20.8 million for the same periods of 2014. The net loss in 2015 is primarily attributable to decreased revenues resulting from the severe decline in oil prices, the increase in exploration expense related to the unsuccessful exploration well drilled in Angola in the first quarter of 2015, the third quarter 2015 write-off of $9.2 million of exploratory well costs related to the N’Gongui No. 2 discovery that had been capitalized pending the determination of proved reserves, and non-cash proved property impairments in the Etame Marin block offshore Gabon in all quarters of 2015. Our realized oil prices in the 2015 periods are approximately half what they were in the same periods of 2014.  Further discussion of results by significant income line item follows.

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Oil and gas revenues decreased $6.9 million and $41.7 million in the three and nine months ended September 30, 2015 compared to the same periods of 2014. The decrease in revenue is primarily related to significantly lower realized oil prices, which are due to decreases in the Dated Brent market price and an adverse increase in marketing differentials for our crude. 

The revenue changes in the three and nine months ended September 30, 2015 identified as related to changes in price or volume are shown in the table below:

 

 

 

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. We made three and eight liftings in the three and nine months ended September 30, 2015, while we made two and seven liftings in the same periods of 2014. Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 55,000 and 117,000 barrels at September 30, 2015 and 2014.

Production expenses increased $0.7 million and $5.0 million in the three and nine months ended September 30, 2015 compared to the same periods of 2014.  Overall production expenses are higher as a result of having two additional platforms operating during the period and as a result of increased production volumes, partially offset by a decrease in the domestic market obligation.  The domestic market obligation is a required subsidy paid to the Gabonese government to help fund the country’s refinery needs. Production expenses in the nine months ended September 30, 2015 are also higher because the first quarter of 2015 included expenses of $1.4 million related to preconstruction costs for a centralized processing facility to remove H₂S from the sour production on the block.

Exploration expense increased $8.4 million and $22.4 million in the three and nine months ended September 30, 2015 compared to the same periods of 2014. During the three months ended September 30, 2015, we charged to dry hole costs $9.2 million of exploratory well costs incurred in 2012 related to the N’Gongui No. 2 discovery that had been capitalized pending the determination of proved reserves. The following table shows exploration expense in detail. Differences in dry hole costs are the primary reason for higher exploration expenses in the nine months ended September 30, 2015. Exploration expense was primarily comprised of the unsuccessful exploratory well offshore Angola in 2015 and the unsuccessful exploratory well offshore Gabon in 2014. 

 

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Depreciation, depletion and amortization (“DD&A”) expenses increased $4.0 million and $8.0 million in the three and nine months ended September 30, 2015 compared to the same periods of 2014.  Higher oil sales volumes in both the three and nine months of 2015 impacted the increase for the periods.  With the completion of the 12-H well in Etame in the three months ended June 30, 2015, the remaining Etame platform costs were added to the depletable costs,  increasing our rate of depletion per barrel in the second and third quarters of 2015. Also included in DD&A for the three months ended September 30, 2015 is the correction of an immaterial error of $0.9 million related to the first and second quarters of 2015.  This reduction is further discussed in Note 1 to the condensed consolidated financial statements.

General and administrative expenses decreased $0.2 million and increased $0.8 million in the three and nine months ended September 30, 2015 compared to the same periods of 2014. The increase in general and administrative expense for the nine-month periods was primarily related to increased stock compensation and professional fees.

Other costs and expenses for the three months ended September 30, 2015 and 2014 are allowances for Value Added Tax (“VAT”) which the government of Gabon is required to reimburse but has not reimbursed.

Impairment of proved properties is discussed in detail in Note 4 to the unaudited condensed consolidated financial statements. Declining forecasted oil prices in 2015 caused us to perform impairment reviews of our proved properties in each of the quarters of 2015 for the five fields comprising the Etame Marin block offshore Gabon and the for Hefley field in North Texas.  For the three and nine months ended September 30, 2015, the impairments of proved properties were $18.0 million and $29.2 million. As discussed further in Notes 1 and 4 to the condensed consolidated financial statements, the impairment includes a charge of $4.5 million and $7.0 million for the three and nine months ended September 30, 2015 which is for the correction of a prior period immaterial error which caused the impairments to be understated.

Interest expense increased $0.5 million and $1.1 million in the three and nine months ended September 30, 2015.  All interest expense incurred on the IFC credit facility was capitalized in the three and nine months ended September 30, 2014, while only a portion of the interest expense incurred could be capitalized in the same periods of 2015.  See Note 9 to the unaudited condensed consolidated financial statements for further discussion of interest expense. 

Other, net consists primarily of foreign currency gains (losses).  Because the U.S. dollar has strengthened in 2015, net gains are reported for the three and nine months ended September 30, 2015.

Income tax expense decreased $1.1 million and $8.6 million in the three and nine months ended September 30, 2015 compared to the same periods of 2014. In all periods presented, all income taxes were paid in Gabon. Income taxes paid to the government of Gabon are a function of taxation on the remaining profit oil value after deducting the royalty and the cost oil values.    The decrease in income tax expenses was primarily associated with the decrease in revenue due to the lower realized prices.  

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign exchange rates and interest rates as described below.

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our costs in Gabon and Angola are denominated in the respective local currency. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has fluctuated widely in response to international political conditions, general economic conditions and other factors beyond our control. The exchange rate between the Angola local currency and the U.S. dollar has fluctuated for similar reasons, with the Angola local currency devaluing over recent quarters.

Interest Rate Risk

The floating rate on our IFC credit facility exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in this interest rate.  At September 30, 2015, we have borrowed $15.0 million under the IFC credit facility.  Fluctuations in floating interest rates will cause our interest costs to fluctuate. During three and nine months ended September 30, 2015, the average effective interest rate on our debt, excluding commitment fees, was 4.0%. If the balance of the debt at September 30, 2015 were to remain constant, a 1% change in market interest rates would impact our cash flow by an estimated $150,000 per year.    

Commodity Price Risk

Our major market risk exposure continues to be the prices received for our oil and gas production. Sales prices are primarily driven by the prevailing market prices applicable to our production.  Market prices for oil and gas have been volatile and unpredictable in recent years, and this volatility is expected to continue in the future. Beginning in the third quarter of 2014, the prices for oil and natural gas began a dramatic decline, and current prices are significantly less than they have been over the last several years.  Sustained low oil and gas prices could have a material adverse effect on our financial condition, the valuation of our proved reserves and the borrowing base under our IFC credit facility. Were oil sales to remain constant at the most recently quarterly sales volumes of 397 MBbls, a $5 

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per Bbl decrease in oil price would be expected to cause a $2.0 million per quarter ($8.0 million annualized) reduction in revenues and operating income (loss) and a $1.8 million per quarter ($7.0 million annualized) reduction in net income (loss).

We had no commodity price derivatives in place as of the date of this report, or throughout 2015 and 2014.

ITEM 4.  CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in the reports we file 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 our management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure. Our management, including the principal executive officer and principal financial officer, has evaluated the effectiveness of our 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. As described in the Annual Report on Form 10-K for the year ended December 31, 2014, material weaknesses were identified in our internal control over financial reporting related to (1) internal control over the preparation and review of the impairment evaluation of oil and gas properties and (2) the control environment, risk assessment and internal controls over financial reporting due to insufficient financial reporting resources.  Based on that evaluation, our principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were not effective as of the end of the period covered by this Quarterly Report on Form 10-Q as a result of these material weaknesses.

In response to the identified material weaknesses, our management, with oversight from our Audit Committee, is taking certain actions to remediate the material weaknesses described above.  In March 2015, we hired an experienced corporate controller to fill a vacancy created during the fourth quarter of 2014.  In connection with the Form 10-Q for the June 30, 2015 period, our management redesigned controls over management’s review of the evaluation of impairment testing of oil and gas properties to address the associated risks and further expanded the procedures for reviewing data used as inputs into the oil and gas properties impairment calculation.  In addition, our management has executed a plan to manage the impact of personnel turnover by enhancing the business understanding and relevant knowledge possessed by those responsible for ensuring proper management review and effective financial reporting controls.

Management is committed to improving our internal control processes and believes that the measures described above should remediate the material weaknesses identified and strengthen internal control over financial reporting. As we continue to evaluate and improve internal control over financial reporting, additional measures to remediate the material weaknesses or modifications to certain of the remediation procedures described above may be necessary. We expect to complete the required remedial actions during fiscal year 2015. While senior management and our Audit Committee are closely monitoring the implementation of these remediation plans, we cannot provide any assurance that these remediation efforts will be successful or that internal control over financial reporting will be effective as a result of these efforts. Until the remediation steps set forth above are fully implemented and operating for a sufficient period of time, the material weaknesses described above will continue to exist.

Except for the activities taken related to the remediation of the material weakness described above, there were no changes in our internal controls over financial reporting that occurred during three months ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

 ITEM 1.  LEGAL PROCEEDINGS

We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.  It is management’s opinion that all claims and litigation we are involved in are not likely to have a material adverse effect on our consolidated financial position, cash flows or results of operations.

 ITEM 1A.  RISK FACTORS

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently know to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in Item 1A “Risk Factors” in our 2014 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ending March 31, 2015. Except for the risk factor set forth below, there have been no material changes in our risk factors from those described in our 2014 Annual Report and our Quarterly Report on Form 10-Q for the quarter ending March 31, 2015.

If the assumptions underlying our accruals for abandonment costs are too low, we could be required to expend greater amounts than expected.

Almost all of our producing properties are located offshore. The costs to abandon offshore wells may be substantial. For financial accounting purposes, we record the fair value of a liability for an asset retirement obligation on the balance sheet in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. The estimated liability is reflected as Asset retirement obligation in the balance sheets. In 2011, as part of securing the first of two five-year extensions, to the Etame field

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production license, we agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block.  On an annual basis over the remaining life of the production license, we fund a portion of these estimated abandonment costs.  The amount of cash funded through the end of a period is reflected separately from the asset retirement obligation under other long term assets as “Abandonment funding” and is non-refundable to us.

We are required under the Etame production sharing contract to conduct regular abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin Block. In September 2015, we commissioned a new abandonment study. Due to two new platforms and to the development wells drilled since the prior study, the final results of the abandonment study will result in an increase in the amounts necessary to fund future abandonment obligations. We will be required to expend greater amounts than are currently being funded, which may have an adverse effect on our cash flow.  Additionally, no assurances can be given that future cash flows from our reserves will be sufficient to cover such costs as they are incurred in the future. Initial indications from the third-party performing the study show that estimated costs have increased. This would increase the abandonment estimate used for funding purposes from the $10.1 million net to VAALCO on an undiscounted basis currently used to between $14.0 million and $28.0 million, and in turn the annual abandonment requirements for 2015 through 2021 are expected to increase by between $0.6 million and $2.5 million.

The Group 42-BLR Group consent solicitation will likely be disruptive and costly, and the possibility that the consent solicitation could result in the replacement of a majority of the members of our Board of Directors could cause uncertainty about the direction of our business. 

The Group 42-BLR Group consent solicitation will likely be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our strategic plan. Perceived uncertainties as to our future direction as a result of changes to the composition of the Board of Directors may lead to the perception of a change in the direction of the business, instability or lack of continuity which may be exploited by our competitors, cause concern to the governments of the countries in which we operate and to our current or potential clients, and make it more difficult to attract and retain qualified personnel. The impact of the Group 42-BLR Group consent solicitation due to these or other factors may undermine our business and have a material adverse effect on our results of operations.

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ITEM 6.  EXHIBITS

(a) Exhibits 

(a)  Filed herewith

(b)  Furnished herewith

*     Management contract or compensatory plan or arrangement

 

 

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SIGNATURE

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 9, 2015

 

 

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EXHIBIT INDEX

Exhibits

 

(a)  Filed herewith

(b)  Furnished herewith

*     Management contract or compensatory plan or arrangement

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