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, 2016



☐  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 31, 2016, there were outstanding 58,633,937 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,” “the Company”, “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

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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 CASH FLOWS

(Unaudited)

(in thousands)



See notes to condensed consolidated financial statements. 

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VAALCO ENERGY, INC. AND SUBSIDIARIES 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

   1.  ORGANIZATION AND 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. As operator, we have production operations and conduct exploration activities in Gabon, West Africa. As non-operator, we participate in exploration and development activities in Equatorial Guinea, West Africa. In the United States, VAALCO is the operator of two unconventional wells in North Texas and holds undeveloped leasehold acreage in Montana. We also own some minor interests in conventional production activities as a non-operator in the United States. As discussed further in Note 4 below, we have discontinued operations associated with our activities in Angola, West Africa.

Our consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., 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 (“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, 2015, which include a summary of the significant accounting policies.

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications did not affect our consolidated financial results.

Correction of error – Accounts with partners and allowance for bad debts – Subsequent to the issuance of our 2015 financial statements, we identified an error in the presentation on our consolidated balance sheet of the accounts with partners and the associated allowance for bad debts. These accounts incorrectly included a fully reserved receivable of $7.6 million which should have been charged off against the reserve in 2012 when efforts to collect from a removed partner were no longer viable and had been abandoned.  To correct this error, we removed the reference to the $7.6 million allowance from the caption. This correction had no impact on our consolidated balance sheet or the consolidated results of operations.

Bad debt – Quarterly, we evaluate our accounts receivable balances to confirm collectability. When collectability is in doubt, we record an allowance against the accounts receivable and a corresponding income charge for bad debts, which appears in the “Bad debt expense (recovery) and other” line of our condensed consolidated statements of operations. The majority of our accounts receivable balances are with our joint venture partners, purchasers of our production and the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to us. 

In the three and nine months ended September 30, 2016, we increased the allowance related to VAT due from Gabon by $0.1 million and $0.6 million, respectively. During the three and nine months ended September 30, 2015 we recorded an allowance of $2.8 million related to the VAT receivable due from Gabon.  In June 2016, we entered into an agreement with the government of Gabon to receive payments related to the outstanding VAT receivable balance as of December 31, 2015 in thirty-six monthly installments of $0.2 million net to VAALCO. We received one monthly installment payment in July 2016; however, no further payments have been received. The Gabonese government has informed us that they do not expect to make any further payments until early 2017 due to liquidity constraints.

General and administrative related to shareholder matters – During the third quarter of 2015, a shareholder group consisting of Group 42, Inc., Bradley L. Radoff and certain other participants (collectively, the "Group 42-BLR Group") attempted to gain control of our Board of Directors. In December 2015, we reached an agreement with the Group 42-BLR Group that included changes to the composition of the Board of Directors and other actions. In connection with this agreement, we reimbursed the Group 42-BLR Group for $350,000 of its legal expenses. Related shareholder litigation filed in Delaware was dismissed by the Delaware Chancery Court on April 20, 2016. See Note 7 below for further discussion of the litigation. 

2.  LIQUIDITY AND GOING CONCERN

Our revenues, cash flows, profitability, oil and natural gas reserve values and future rates of growth are substantially dependent upon prevailing prices for oil and natural gas. Our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and natural gas prices. Historically, world-wide oil and natural gas prices and markets have been volatile, and will likely continue to be volatile. In particular, the prices of oil and natural gas declined dramatically in the second half

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of 2014 and remained low, decreasing further in 2015 and early 2016. Revenues have increased from $11.0 million in the first quarter 2016 to $14.6 million in the third quarter of 2016 primarily as a result of improving prices. 

As discussed in Note 6 below,  in June 2016, we modified our revolving credit facility with the International Finance Corporation (the “IFC”) converting $20 million of our revolving credit facility into a term loan with $15 million borrowed and the option to request an additional $5 million in a single draw between now and December 31, 2016, subject to the IFC’s approval. Our available liquidity, therefore, continues to be limited.  

If we fail to satisfy our obligations with respect to our indebtedness or trade payables, or fail to comply with the financial and other restrictive covenants contained in our amended loan agreement with the IFC, an event of default under the amended loan agreement and acceleration of our term loan debt and other indebtedness could result,  which could permit the IFC to foreclose on any of our assets securing that debt. Any accelerated debt would become immediately due and payable. As discussed in Note 6 below,  certain of our financial covenants under the amended loan agreement have been relaxed through the end of 2016.

During the third quarter of 2016, we received notice from the New York Stock Exchange (“NYSE”) that our stock had fallen below the minimum listing standards which requires that the average closing price of our common stock be not less than $1.00 per share for a period of over 30 consecutive trading days.  We are considering various options to come into compliance with this requirement; however, should the delisting occur, it could cause additional difficulties in accessing the capital markets.

If oil and natural gas prices continue at levels seen in the second and third quarters of 2016, we expect that for the remainder of 2016 through the end of 2017 we will generate cash flows sufficient to cover our operating expenses. However, an unfavorable resolution of current obligations or depressed oil and natural gas prices, like those seen in the first quarter of 2016,  would have a material adverse effect on our liquidity, financial condition, results of operations and on the carrying value of our proved oil and natural gas properties. To fund potential growth opportunities going forward, we are considering multiple alternatives, including, but not limited to, additional debt or equity financing through traditional sources or strategic partnerships. There can be no guarantee of future capital acquisition or fundraising success. Our current cash position and our ability to access additional capital may limit our available opportunities and not provide sufficient cash to support our operations.  These conditions continue to raise doubts about our ability to continue as a going concern. 

Our financial statements for the three and nine months ended September 30, 2016 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business. The financial statements do not include any adjustments relating to the recoverability and classification of assets or the amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern.

3.  NEW ACCOUNTING STANDARDS

Not yet adopted

In August 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) related to how certain cash receipts and payments are presented and classified in the statement of cash flows. These cash flow issues include debt prepayment or extinguishment costs, settlement of zero-coupon debt, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. We are currently evaluating the provisions of this guidance and are assessing its potential impact on our cash flows and related disclosures. Due to the nature of this accounting standards update,  this may have an impact on items reported in our statements of cash flows, but no impact is expected on our financial position, results of operations or related disclosures as a result of implementation.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including our trade and partner receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date which is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model which increases the allowance when losses are probable. This change is effective for all public companies for fiscal years beginning after December 31, 2019, including interim periods within those fiscal years and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We are currently evaluating the provisions of ASU 2016-13 and are assessing its potential impact on our financial position, results of operations, cash flows and related disclosures.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statements of cash flows. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 31, 2016, with early adoption permitted. Varying transition methods (modified retrospective, retrospective or prospective) are applicable to different provisions of

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the standard. We are in the process of evaluating all changes, both required and elective, and are developing implementation plans for each as appropriate; however, we do not expect any of the changes to have a significant impact on our financial position, results of operations, cash flows or related disclosures.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which amended the accounting standards for leases.  ASU 2016-02 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Certain aspects of lease accounting have been simplified. Additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early application permitted. We are currently evaluating the provisions of this update and are assessing the potential impact on our financial position, results of operations, cash flows and related disclosures. 

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which 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 new 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 approach to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a modified retrospective approach to adoption. In July 2015, the FASB approved a one-year deferral of the effective date of ASU 2014-09 to annual reporting periods beginning after December 15, 2017 for public companies. The FASB approved early adoption of the standard, but not before the original effective date of annual reporting periods beginning after December 15, 2016. Since May 2014, several additional accounting standards updates have been issued by FASB to clarify implementation issues. We continue to evaluate the impact of this revised guidance and the several clarifications that have been issued since. We have not yet quantified the impact, if any, of this amended guidance on our financial position, results of operations, cash flows and related disclosures.

Adopted

In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03) that requires 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 prior GAAP, debt issuance costs were reported as deferred charges (i.e., as an asset). We adopted ASU 2015-03 in the first quarter of 2016. As discussed in Note 6 below, in the second quarter of 2016, our loan agreement was modified into a term loan. At that time, a portion of deferred debt issuance costs related to the revolving credit facility were charged to expense. The remaining unamortized deferred financing costs plus the incremental costs of converting the revolver into a term loan are presented as a direct reduction of Long-term debt on our condensed consolidated balance sheet.







4.  AQUISITIONS AND DISPOSITIONS

Sojitz Acquisition

On July 28, 2016, we signed a purchase and sale agreement to acquire an additional 2.98% working interest (3.23% participating interest) in the Etame Marin block located offshore the Republic of Gabon from Sojitz Etame Limited (“Sojitz”), which represents all interest owned by Sojitz in the concession. The acquisition has an effective date of August 1, 2016, and closing is expected by December 31, 2016, subject to customary closing conditions. Payment for the acquisition is expected to be primarily funded by cash on hand; however, we intend to issue a request to the IFC to borrow the $5.0 million potentially available under the Additional Term Loan. Completion of the transaction is not contingent on obtaining approval of our request.

Sale of Certain U.S. Properties

On September 21, 2016, we signed a letter of intent to sell our interests in two wells in the Hefley field in North Texas for $850,000. We expect this transaction to be concluded during the fourth quarter of 2016. On October 17, 2016, we signed a letter of intent to sell our interests in the East Poplar Dome field in Montana for $250,000. We expect this transaction to be concluded during the fourth quarter of 2016. Based on the net book value for these assets as of September 30, 2016, we expect any gain/loss to be insignificant.

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Discontinued Operations - Angola

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, with a commitment to drill two exploratory wells. In October 2014, we entered into the Subsequent Exploration Phase (“SEP”) which extended the exploration period to November 30, 2017 and required us and our partner to drill two additional exploration wells. Our working interest is 40% and we carry the Angolan national oil company, Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P, our joint venture partner, that we were withdrawing from the joint operating agreement effective October 31, 2016. Further to our decision to withdraw from Angola, we have taken actions to begin closing our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, as of September 30, 2016, the Angola segment met all the criteria to be classified as assets held for sale; therefore, we classified all the related assets and liabilities as those of discontinued operations in the condensed consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in our condensed consolidated statements of operations. We segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in our condensed consolidated statements of cash flows. The following tables summarize selected financial information related to the Angola segment’s operations as of September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015.

Summarized Results of Discontinued Operations





Assets and Liabilities Attributable to Discontinued Operations





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Drilling Obligation

Under the production sharing agreement for Block 5, we and our working interest partner, Sonangol P&P, were obligated to perform exploration activities in Angola that would result in drilling or commencing four wells by November 30, 2017. With the drilling of the Kindele #1 in 2015, the obligation was reduced to three wells. Under the contract, VAALCO is required to pay a $5.0 million penalty for each of the three wells not completed; however, the penalty amounts can be reduced by exploration expenses incurred. Prior to the September 30, 2016 quarterly reporting period, we classified the $15.0 million commitment for drilling these wells as long term restricted cash on our balance sheet. As a result of our decision to terminate the contract, we are no longer reflecting the $15.0 million as restricted cash. We believe that a substantial portion of the penalty amount has been reduced due to exploration expenditures made. Support for our determination is being presented to Angola government authorities, and we anticipate further discussions on this matter. However, due to the uncertainties as to the ultimate outcome, we have accrued a $15.0 million liability for the penalty which represents what we believe to be the maximum potential amount due under the agreement.

Other Matters – Partner Receivable

The government-assigned working interest partner was delinquent in paying their share of the costs several times in 2009 and was removed from the production sharing contract in 2010 by a governmental decree. Efforts to collect from the defaulted partner were abandoned in 2012. The available 40% working interest in Block 5, offshore Angola was assigned to Sonangol P&P effective on January 1, 2014. We invoiced Sonangol P&P for the unpaid delinquent amounts from the defaulted partner plus the amounts incurred during the period prior to assignment of the working interest totaling $7.6 million plus interest in April 2014. Because this amount was not paid and Sonangol P&P was slow in paying monthly cash call invoices since their assignment, we placed Sonangol P&P in default in the first quarter of 2015.

On March 14, 2016, we received a $19.0 million payment from Sonangol P&P for the full amount owed us as of December 31, 2015, including the $7.6 million of pre-assignment costs and default interest of $3.2 million. The $7.6 million recovery is reflected in the “Bad debt expense (recovery) and other” line of our summarized results of discontinued operations. Default interest of $3.2 million is shown in the “Interest income” line of our summarized results of discontinued operations.





5.  OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

We review our oil and natural gas producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When an oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in our impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.

During the third quarter of 2016, our negative price differential to Brent narrowed and we incurred no significant capital spending.  We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the Avouma field in the Etame Marine block offshore Gabon. Recently, at the Avouma field, the electrical submersible pumps (“ESPs”) in the South Tchibala 2-H well and the Avouma 2-H well failed, and these wells are temporarily shut-in. Workovers are being planned to replace the ESPs and bring the wells back on production by late in the fourth quarter 2016. The reserves used in our impairment evaluation of the Avouma field were revised to reflect the impact of this lost production for several months and the impact of the forward price curve. The undiscounted future net cash flows for the Avouma field were in excess of the field’s carrying value. No impairment was required for the Avouma field, or any of our other fields in Gabon, for the third quarter of 2016.

As a result of the letter of intent signed to sell our interests in the two wells in North Texas for $850,000, we performed an impairment test and determined that a $0.1 million impairment was required.

Declining forecasted oil prices in 2015 caused us to perform impairment reviews of our proved properties in each quarter of 2015 and 2016 for all fields in 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. 

6.  DEBT

On June 29, 2016, we executed a Supplemental Agreement with the IFC which, among other things, amended and restated our existing loan agreement to convert $20 million of the revolving portion of the credit facility, to a term loan (the “Term Loan”) with $15 million outstanding and an additional $5 million (the “Additional Term Loan”), which can be requested in a single draw, subject to the IFC’s approval, between now and December 31, 2016. The amended loan agreement is secured by the assets of our Gabon subsidiary, VAALCO Gabon (Etame), Inc. and is guaranteed by VAALCO as the parent company. Before we are able to draw the Additional Term Loan, the IFC, as part of their consideration of our loan request, will make a determination of whether our Gabon subsidiary’s current and projected revenues from operations are sufficient to cover the aggregate amount of principal, interest, commissions, fees and any other amounts due in respect of the Additional Term Loan. If drawn, the Additional Term Loan amount shall be amortized in equal quarterly installments through June 30, 2018. The amended loan agreement provides for quarterly principal and interest payments on

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the amounts currently outstanding through June 30, 2019, with interest accruing at a rate of LIBOR plus 5.75%; however, principal repayments under the amended loan agreement are dependent upon the timing of our additional borrowing, if any, with the payments to commence on either December 31, 2016 or March 31, 2017. If we do not borrow under the Additional Term Loan before December 15, 2016, no principal payments are due until March 31, 2017.

Compared to the $15.0 million carrying value of debt, the estimated fair value of the term loan is $15.0 million when measured using a discounted cash flow model over the life of the current borrowings at forecasted interest rates. The inputs to this model are Level 3 in the fair value hierarchy.

Covenants

Under the amended loan agreement, quarter-end net debt to EBITDAX (as defined in the loan agreement) must be no more than 3.0 to 1.0. However, the quarter-end net debt to EBITDAX limitation has been raised to 5.0 to 1.0 for all periods through the end of 2016. Additionally, our debt service coverage ratio must be greater than 1.2 to 1.0 at each quarter end.  Forecasting our compliance with these and other financial covenants in future periods is inherently uncertain; therefore, we can make no assurance that we will be able to comply with our term loan covenants in future periods. Factors that could impact our quarter-end financial covenants 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 were in compliance with all financial covenants as of September 30, 2016.

Interest 

Until June 29, 2016, under the terms of the original revolving credit facility, we paid commitment fees on the undrawn portion of the total commitment. Commitment fees were equal to 1.5% of the unused balance of the senior tranche of $50.0 million and 2.3% of the unused balance of the subordinated tranche of $15.0 million when a commitment was available for utilization. Subsequent to June 29, 2016 through December 31, 2016, commitment fees are 2.3% of the undrawn Additional Term Loan of $5 million.

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.

The table below shows the components of the Interest expense line of our condensed consolidated statements of operations and the average effective interest rate, excluding commitment fees, on our borrowings:

































7.  COMMITMENTS AND CONTINGENCIES

Litigation

Gusinsky litigation

On December 7, 2015, Plaintiff Vladimir Gusinsky Living Trust filed a stockholder class action lawsuit in the Court of Chancery of the State of Delaware (the “Court”) against the Company and all of its directors alleging that certain provisions of the Company’s Restated Charter and Second Amended and Restated Bylaws that restricted the removal of its directors to removal for cause only (the “director removal provisions”) were invalid as a matter of Delaware law. Plaintiff George Shapiro also filed a similar stockholder class action lawsuit in the Court on December 7, 2015. Thereafter, the plaintiffs agreed to the consolidation of their cases (the “Consolidated Case”).

After a hearing on the Consolidated Case on December 21, 2015, Vice Chancellor Laster issued an opinion in In re VAALCO Energy, Inc. Stockholder Litigation, Consol. C.A. No. 11775-VCL holding that, in the absence of a classified board or cumulative voting, the director removal provisions conflicted with Section 141(k) of the Delaware General Corporation Law and are therefore invalid.

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On April 20, 2016, the Court approved a Stipulation and Order of Dismissal entered into by the parties in the Consolidated Case. We agreed to settle plaintiffs’ application for an award of attorneys’ fees and expenses totaling $775,000 due to the costs of defense of that application and the litigation risk associated therewith, all of which were covered by our directors and officers insurance as a covered claim.

Butcher settlement

On October 3, 2016, the Court approved a Stipulation and Order of Dismissal entered into by the parties in a stockholder class action lawsuit against the Company and all of its directors alleging that a previously terminated shareholder rights agreement, no longer in effect, and certain provisions of the former CEO’s and former CFO’s employment agreements securing change-in-control severance benefits were invalid under Delaware law, case number C.A. No. 12277-VCL, filed on April 29, 2016,  in the Court. After the Company and its directors moved to dismiss the lawsuit, the Plaintiff Daniel Butcher agreed to dismiss the lawsuit as moot, and the Company agreed to settle Plaintiff’s application for an award of attorneys’ fees, which it expects its insurer to pay, due to the anticipated costs of continuing to prosecute the motion to dismiss and defending the Plaintiff’s fee application, as well as the litigation risk associated therewith. 

Rig commitment

In 2014, we entered into a long-term contract for a jackup drilling rig for the multi-well development drilling campaign offshore Gabon. The campaign included the drilling of development wells and workovers of existing wells in the Etame Marin block. We began demobilization in January 2016 and released the drilling rig in February 2016, prior to the original July 2016 contract termination date, because we no longer intended to drill any wells in 2016 on our Etame Marin block offshore Gabon. In June 2016, we reached an agreement with the drilling contractor to pay $5.1 million net to VAALCO’s interest for unused rig days under the contract. We are paying this amount, plus the demobilization charges, in seven equal monthly installments which began in July 2016. As of September 30, 2016, the remaining amount to pay was $3.6 million net to VAALCO’s interest. The related expense is reported in the “Other operating expense” line of our condensed consolidated statements of operations.

Gabon

Offshore

Abandonment

We have an agreed cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block. Based upon the abandonment study completed in January 2016, the abandonment cost estimate used for this purpose is approximately $61.1 million ($17.3 million net to VAALCO) on an undiscounted basis. The obligation for abandonment of the Gabon offshore facilities is included in the “Asset retirement obligations” line on our condensed consolidated balance sheet. Through December 31, 2015, $18.3 million ($5.1 million net to VAALCO) on an undiscounted basis has been funded, with the next funding of $9.1 million  ($2.6 million net to VAALCO) expected to be required sometime later in 2016. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheet. Future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.

Audits

We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements.

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 final agreement was reached with the Gabon Taxation Department in October 2016.  During 2015, we accrued an estimated settlement of $0.3 million net to VAALCO based upon preliminary negotiations and expect to pay this amount in November 2016 in accordance with the final settlement agreement.

As of September 30, 2016, we had accrued $2.2 million net to VAALCO in “Accrued liabilities and other” on our condensed consolidated balance sheet for certain payroll taxes in Gabon which were not paid pertaining to labor provided to us over a number of years by a third-party contractor. While the payroll taxes were for individuals who were not our employees, we could be deemed liable for these expenses as the end user of the services provided. A process of negotiation with government payroll agencies in Gabon is underway to resolve this matter.

8. DERIVATIVES AND FAIR VALUE

In April 2016, we entered into put contracts on 36,000 barrels of oil per month for the period from June 2016 through February 2017 at Dated Brent of $40 per barrel. This volume represents approximately one-third of our total forecasted sales volumes for the period. While these crude oil puts are intended to be an economic hedge to mitigate the impact of a decline in oil prices, we have not elected hedge accounting. The contracts will be measured at fair value each period, with changes in fair value recognized in net income. We do not enter into derivative instruments for speculative or trading proposes.

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Our put contracts are subject to agreements similar to a master netting agreement under which we have the legal right to offset assets and liabilities. At September 30, 2016, all of the put contracts were assets.

The following table sets forth, by level within the fair value hierarchy and location on our condensed consolidated balance sheets, the reported values of derivative instruments accounted for at fair value on a recurring basis:



We had neither derivative instruments outstanding as of December 31, 2015 nor derivative instrument activity during 2015. 

The crude oil put contracts are measured at fair value using the Black’s option pricing model. Level 2 observable inputs used in the valuation model include market information as of the reporting date, such as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates.  The determination of the put contract fair value includes the impact of the counterparty’s non-performance risk. 

To mitigate counterparty risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.

The following table sets forth the effect of derivative instruments on our condensed consolidated statements of operations:



























9.  COMPENSATION

Stock options

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. 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 life, with the options vesting over a service period of up to five years. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of our Board of Directors. A portion of the stock options granted in the nine months ended September 30, 2016 and 2015 were vested immediately with the remainder vesting over a two year period.

Stock option activity for the nine months ended September 30, 2016 is provided below:



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Common and restricted shares

Shares of restricted stock may be granted under our long-term incentive plan and related compensation expense is recorded using the fair market value of the underlying shares on the date of grant. 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. Share grants to directors vest immediately and are not restricted.



In the three months ended March 31, 2016, 31,808 shares were added to treasury due to tax withholding on vesting restricted shares.  No shares were added to treasury in the second and third quarters of 2016.

Stock appreciation rights

Stock appreciation rights (“SARs”) are granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR.  The spread is the difference between the SAR price per share specified in a SAR award on the date of grant (which may not be less than the fair market value of our common stock on the date of grant) and the fair market value per share on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of our Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of our Board of Directors. The 815,355 SARs granted in the three months ended March 31, 2016 vest over a three year period with a life of 5 years and have a maximum spread of 300% of the $1.04 SAR price per share specified in a SAR award on the date of grant. Compensation payable related to these awards through September 30, 2016 is not significant.

Compensation expense

We record non-cash compensation expense related to stock-based compensation in the “General and administrative” expense line of our condensed consolidated statements of operations. Non-cash compensation expense related to stock options, SARs, common stock and restricted stock was ($0.5) million and $1.1 million for the three and nine months ended September 30, 2016 and was $0.7 million and $3.0 million for the three and nine months ended September 30, 2015. Because we do not pay significant United States federal income taxes, no amounts were recorded for tax benefits.

10. INCOME TAXES

VAALCO and its domestic subsidiaries file a consolidated United States income tax return. Certain subsidiaries’ operations are also subject to foreign income taxes.

As discussed further in the Notes to the consolidated financial statements in our Form 10-K for December 31, 2015, we have deferred tax assets related to foreign tax credits, alternative minimum tax credits, and domestic and foreign net operating losses (“NOLs”). Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. We do not anticipate utilization of the foreign tax credits prior to expiration nor do we expect to generate sufficient taxable income to utilize other deferred tax assets. On the basis of this evaluation, full valuation allowances have been recorded as of September 30, 2016 and December 31, 2015.

NOLs for our Gabon and Angola subsidiaries are included in the respective subsidiaries’ cost oil accounts which will be offset against future taxable revenues.

Income taxes attributable to continuing operations for the three and nine months ended September 30, 2016 and all of the income taxes for the three and nine months ended September 30, 2015 are attributable to foreign taxes payable in Gabon.

As discussed further in Note 4 above, our Angola operations are reflected as discontinued. In Angola, NOLs are not available to offset financial gains which include foreign exchange gains and interest income. During the three and nine months ended September 30, 2016, we recorded an immaterial amount and $3.1 million for income taxes attributable to discontinued operations in Angola on financial gains related to foreign exchange gains as well as the interest paid by Sonangol P&P on their past due joint interest account balance.

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11.  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.

A reconciliation from basic to diluted shares follows:   

Because we recognized net losses for the three and nine months ended September 30, 2016, there were no dilutive securities for those periods.

12.  SEGMENT INFORMATION

Our operations are based in Gabon, Equatorial Guinea and the United States (“U.S.”).  Each of our three reportable operating segments is organized and managed based upon geographic location. Our Chief Executive Officer, who is the chief operating decision maker, and management, review and evaluate 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 costs which are not allocated to the reportable operating segments.

Segment activity of continuing operations for the three and nine months ended September 30, 2016 and 2015 and segment assets at September 30, 2016 and December 31, 2015 are as follows:





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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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 and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,”, “target”, “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 “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 Form 10-K”) and under the heading “Item 1A. Risk Factor” in our Quarterly Report on Form 10-Q for the period ended June 30, 2016 (“June 30 2016 Form 10-Q”) identifies additional factors that could cause our results or performance to differ materially from those we express in 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



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uncertainties inherent in the forward-looking statements which are included in this report, the 2015 Form 10-K and the June 30, 2016 Form 10-Q, 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.

INTRODUCTION

VAALCO is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. As operator, we have production operations and conduct exploration activities in Gabon, West Africa.  We participate in exploration and development activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of two unconventional wells in the United States in North Texas and holds undeveloped leasehold acreage in Montana. We also own some minor interests in conventional production activities as a non-operator in the United States. As discussed further in Note 4 to the condensed consolidated financial statements, we have discontinued operations associated with our activities in Angola, West Africa, and have entered into letters of intent to sell our interests in North Texas and Montana.

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 which continued through 2015 and into early 2016. Current prices, while higher than those in early 2016, are significantly less than they were in the several years prior to mid-2014. Sustained low oil and natural gas prices or further decreases in oil and natural gas prices could have a material adverse effect on our financial condition and the carrying value of our proved oil and natural gas properties and undeveloped leasehold interests and our ability to borrow amounts under the Additional Term Loan with the International Finance Corporation (the “IFC”). As with prices received for oil production, the costs to find and produce oil and natural gas are largely not within our control. 

CURRENT DEVELOPMENTS    

In 2016, prices for oil, natural gas and natural gas liquids continued to remain at low levels experienced in 2015. These low prices have affected our business in numerous ways, including causing:

Price declines also adversely affected our borrowing capacity based mainly on the value of our oil and natural gas reserves. Our borrowing base was reduced from $65.0 million to $20.1 million effective December 31, 2015. On June 29, 2016, we executed a Supplemental Agreement with the IFC, the lender under our revolving credit facility which among other things, amended and restated our loan agreement to convert $20 million of the revolving portion of the credit facility into a term loan.  Currently $15 million is outstanding as a term loan with an additional $5 million that may be requested in a single draw between now and December 31, 2016, subject to the IFC’s approval.  See Note 6 to the condensed consolidated financial statements and “Capital Resources and Liquidity—Liquidity—Credit Facility” below for additional details about the loan agreement.

In January 2016, our Board of Directors formed a strategic committee to oversee the evaluation of our strategic alternatives. The committee is exploring strategic options including, but not limited to, securing additional investment to support existing projects and growth opportunities, joint ventures, asset sales or farm-outs, our potential sale or merger, or continuing to pursue our existing operating plan. We will continue to pursue ways to increase liquidity. However, we can give no assurances that any of these strategic alternatives can be completed, and if so, on reasonable terms that are acceptable to us. 

As discussed in Note 5 to the condensed consolidated financial statements, we recorded impairments on our proved oil and natural gas properties in periods prior to 2016. We could experience write-downs in the remainder of 2016. 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. Our impairment calculations have been based upon reserve economics using forecasted future prices, adjusted for specifics related to our production. If projected per barrel prices used in the impairment calculation made as of September 30, 2016 had been $5.00 lower, there would still have been no impairment.  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.    

As discussed further in Note 4 to the condensed consolidated financial statements, on September 30, 2016, we notified Sonangol P&P, our joint venture partner in Block 5, that we were withdrawing from the Block 5 joint operating agreement effective October 31, 2016.  In addition to the withdrawal, we have taken actions to begin closing our office in Angola and do not intend to conduct future

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activities in Angola.  As a result of this strategic shift, as of September 30, 2016, the Angola segment has been reflected as discontinued in our financial statements.

As discussed further in Note 4 to the condensed consolidated financial statements, on March 14, 2016, we received payment of $19.0 million from Sonangol P&P for the full amount owed us as of December 31, 2015, including the $7.6 million of pre-assignment costs.  The $7.6 million recovery is reflected in the “Bad debt expense (recovery) and other” line of our summarized results of discontinued operations. Default interest of $3.2 million was received and is shown in the Interest income line of our summarized results of discontinued operations. While this payment improved our liquidity in the short-term, we are continuing to pursue alternatives for increasing our liquidity. 

As discussed further in Note 4 to the condensed consolidated financial statements, on July 28, 2016, we signed a purchase and sale agreement to acquire an additional 2.98% working interest (3.23% participating interest) in the Etame Marin block located offshore the Republic of Gabon from Sojitz Etame Limited (“Sojitz”), which represents all the interest owned by Sojitz in the concession.

As discussed in Note 4 to the condensed consolidated financial statements, on September 21, 2016, we signed a letter of intent to sell our interests in two wells in the Hefley field in North Texas for $850,000 and on October 17, 2016, we signed a letter of intent to sell our interests in the East Poplar Dome field in Montana for $250,000.  We expect these transactions to be concluded during the fourth quarter of 2016. As a result of the letter of intent signed to sell our interests in the two wells in North Texas for $850,000, we performed an impairment test and determined that a $0.1 million impairment was required. Substantially all of the reserves and production in the United States are attributable to the Hefley field.  As of December 31, 2015, proved reserves in the United States were 190.5 MBOE, and sales volumes in the United States for the nine months ended September 30, 2016 were 18.0 MBOE.

In light of the continued depressed levels of oil prices, we intend to focus on maintaining oil production levels and lowering operating costs with respect to current production in our Etame Marin block located offshore Gabon. In early 2016, we determined that additional development drilling is uneconomic at then current commodity prices. In January 2016, we began demobilizing our contracted drilling rig and do not intend to drill any wells in 2016 on the Etame Marin block. In June 2016, we reached an agreement with the drilling contractor to pay $5.1 million net to VAALCO’s interest for unused rig days under the contract. We are paying this amount, plus the demobilization charges, in seven equal monthly installments beginning in July 2016. We are currently evaluating with our partners the prospect of conducting some development drilling in 2017.

GOING CONCERN    

Our revenues, cash flows, profitability, oil and natural gas reserve values and future rates of growth are substantially dependent upon prevailing prices for oil and natural gas. Our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and natural gas prices. Historically, world-wide oil and natural gas prices and markets have been volatile, and will likely continue to be volatile. In particular, the prices of oil and natural gas declined dramatically in the second half of 2014 and remained low, decreasing further in 2015 and early 2016. Revenues have increased from $11.0 million in the first quarter 2016 to $14.6 million in the third quarter of 2016 primarily as a result of improving prices.  

As discussed in Note 6 to the condensed consolidated financial statements,  in June 2016, we modified our revolving credit facility with the IFC converting $20 million of our revolving credit facility into a term loan with $15 million borrowed and the option to request, with approval being at the IFC’s discretion, an additional $5 million in a single draw between now and December 31, 2016. Our available liquidity, therefore, continues to be limited. 

If we fail to satisfy our obligations with respect to our indebtedness or trade payables, or fail to comply with the financial and other restrictive covenants contained in our loan agreement with the IFC, an event of default under the amended loan agreement and acceleration of our term loan debt and other indebtedness could result,  which could permit the IFC to foreclose on any of our assets securing that debt. Any accelerated debt would become immediately due and payable. As discussed in Note 6,  certain of our financial covenants under the amended loan agreement have been relaxed through the end of 2016.

During the third quarter of 2016, we received notice from the New York Stock Exchange (“NYSE”) that our stock had fallen below the minimum listing standards which requires that the average closing price of our common stock be not less than $1.00 per share for a period of over 30 consecutive trading days. We are considering various options to come into compliance with this requirement; however, should the delisting occur, it could cause additional difficulties in accessing the capital markets.

If oil and natural gas prices continue at levels seen in the second and third quarters of 2016, we expect that for the remainder of 2016 through the end of 2017 we will generate cash flows sufficient to cover our operating expenses. However, depressed oil and natural gas prices, like those seen in the first quarter of 2016, would have a material adverse effect on our liquidity, financial condition, results of operations and on the carrying value of our proved oil and natural gas properties. To fund potential growth opportunities going forward, we are considering multiple alternatives, including, but not limited to, additional debt or equity financing through traditional sources or strategic partnerships. There can be no guarantee of future capital acquisition or fundraising success. Our current cash position and our ability to access additional capital may limit our available opportunities and not provide sufficient cash to support our operations.  These conditions continue to raise doubts about our ability to continue as a going concern. 

Our financial statements for the three and nine months ended September 30, 2016 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business. The financial statements do not include any adjustments relating to the recoverability and classification of assets or the amounts and classification of

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liabilities that might be necessary should we be unable to continue as a going concern. See Note 2 to the condensed consolidated financial statements.

ACTIVITIES BY ASSET 

Gabon

Offshore

Development and Production

We operate the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of five companies. In 2015, we completed a development plan, initiated in 2012, consisting of two new platforms, a multi-well development drilling campaign and several well workovers.  As of September 30, 2016 production is from three subsea wells and six platform wells which are tied back by pipelines to deliver oil and associated natural 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. During the first nine months of 2016 and 2015, production from the block was approximately 4,835 MBbls (1,181 MBbls net) and 4,972 MBbls (1,215 MBbls net).

During the first quarter of 2016, workovers were conducted on two wells producing from the Avouma platform. An electrical submersible pump (“ESP”) was successfully replaced in the first well and the second workover was suspended due to operational problems. Following the workovers and an ESP failure in another Avouma well, there were two wells producing from the Avouma platform, which were the South Tchibala 2-H and the Avouma 2-H.

During the second and third quarters of 2016, however, the ESPs in the South Tchibala 2-H well and the Avouma 2-H well failed, and these wells are temporarily shut-in. These wells were producing approximately 4,400 gross BOPD, or 1,075 BOPD net to VAALCO just before being temporarily shut-in. Production decreased from 4,725 BOPD in the second quarter of 2016 to 3,772 BOPD as a result of the ESP failures.  We are working to mobilize a hydraulic workover unit onto the Avouma platform to remove the failed ESPs and have them analyzed for the cause of the failure by the manufacturer. We are developing a plan to replace the ESPs in the affected wells and anticipate restoring at least a portion of the shut-in production by late fourth quarter 2016. Based on recent technical analysis, the temporary shut-in of these wells will not have a significant impact on our estimated reserves; however, volumes will now not include those from the affected wells. Our net share of the cost is expected to be approximately $3.1 million.  

Impairment

No impairment of proved properties was necessary in the nine months ended September 30, 2016. In the three and nine months ended September 30, 2015, we recorded aggregate impairment of $18.0 million and $29.2 million, respectively, to write down our investment in certain fields of the Etame Marin block to their fair value. The decrease in fair value was primarily a result of lower forecasted oil prices, as well as higher costs for planned development wells used in the impairment evaluation.

Onshore 

VAALCO has a 50% working interest (41% net working interest assuming the Republic of Gabon exercises its back-in rights) and operates the Mutamba Iroru block located onshore Gabon. We made a discovery on the block in 2012; however, 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, and all capitalized costs related to the project, including capitalized exploratory well costs, were charged to exploration expense in the third quarter of 2015. The government of Gabon believes that our production sharing contract (“PSC”) for the block expired in mid-2014. While we maintain that the PSC is still valid, we expect that a new PSC would be required in order to pursue development, and we would only enter into a new PSC in the event that the project becomes economic. We can provide no assurances as to either the approval of a new PSC by the Government of Gabon, or the subsequent approval of a development plan by the Government of Gabon.

Equatorial Guinea

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, two oil discoveries had been made on the block, establishing a development and production area (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. The Ministry of Mines, Industry and Energy and GEPetrol, the current block operator, are reviewing a revised joint operating agreement which would name us as operator of Block P. Given the current depressed commodity prices, it is likely we will minimize any near-term expenditures and expenses in Equatorial Guinea. Before beginning exploration, we and our partners will need to evaluate 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.

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CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

A summary of our cash flows for the nine months ended September 30, 2016 and 2015 are as follows:



The decrease in net cash provided by operating activities for the nine months ended September 30, 2016 compared to the same period of 2015 was primarily related to:  lower 2016 crude oil prices, lower oil sales volume and higher workover expense, as well as a reduction in cash provided by changes in working capital.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. During the nine months ended September 30, 2016, these expenditures on a cash basis were $12.8 million, primarily related to final payments made on invoices related to the development program completed in 2015. This compares to $53.3 million in the same period of 2015. These cash property and equipment expenditures are included in capital expenditures. See “Capital Expenditures” below for further discussion. The nine months ended September 30, 2016 and 2015 also included the cash inflows of $15.3 million and $5.5 million, respectively, for the reduction in restricted cash. Prior to the September 30, 2016 quarterly reporting period, we classified the $15.0 million commitment for drilling these wells as long term restricted cash on our balance sheet. As a result of our decision to terminate the contract, we are no longer reflecting the $15.0 million as restricted cash. Reductions in restricted cash in the nine months ended September 30, 2015 were primarily a result of fulfilling the commitment for one of the four exploration wells in Angola.

Capital Expenditures

During nine months ended September 30, 2016,  we had negative accrual basis capital expenditures of $1.7 million as a result of better information. We now expect full-year 2016 capital expenditures to be less than $1.0 million, which is mainly for equipment and enhancements.  Capital expenditures of $44.4 million incurred during the nine months ended September 30, 2015 were primarily associated with the drilling of four development wells offshore Gabon. The difference between capital expenditures and the property and equipment expenditures reported in our condensed consolidated statements of cash flows is attributable to changes in accruals for costs incurred but not yet invoiced or paid on the report dates.

Liquidity

Credit Facility    

Historically, our primary sources of capital have been cash flows from operating activities, borrowings under the credit facility with the IFC and cash balances on hand.

On June 29, 2016, we executed a Supplemental Agreement with the IFC which, among other things, amended and restated the existing loan agreement to convert $20 million of the revolving portion of the credit facility, to a term loan (the “Term Loan”) with $15 million outstanding and an additional $5 million (the “Additional Term Loan”) which can be requested in a single draw, subject to the IFC’s approval, between now and December 31, 2016. The amended loan agreement is secured by the assets of our Gabon subsidiary, VAALCO Gabon (Etame), Inc. and is guaranteed by VAALCO as the parent company. Before we are able to draw the Additional Term Loan, the IFC, as part of their consideration of our loan request, will make a determination of whether our Gabon subsidiary’s current and projected revenues from operations are sufficient to cover the aggregate amount of principal, interest, commissions, fees and any other amounts due in respect of the Additional Term Loan. If drawn, the Additional Term Loan amount shall be amortized in equal quarterly installments through June 30, 2018. The amended loan agreement provides for quarterly principal and interest payments on the amounts currently outstanding through June 30, 2019, with interest accruing at a rate of LIBOR plus 5.75%; however, principal repayments under the amended loan agreement are dependent upon the timing of our additional borrowing, if any, with the payments to commence on either December 31, 2016 or March 31, 2017. If we do not borrow under the additional borrowing provision before December 15, 2016, no principal payments are due until March 31, 2017.

The amended loan agreement contains a number of restrictive covenants that impose significant operating and financial restrictions on us. These covenants restrict our ability to engage in certain actions, including potentially limiting our ability to sell assets, make future borrowings or incur other additional indebtedness. Our ability to meet our quarter-end net debt to EBITDAX ratio and our debt service coverage ratio can be affected by events beyond our control, including changes in commodity prices. There can be no assurance that we will be able to comply with these covenants in future periods. In addition, if we receive any waivers or amendments to our amended loan agreement, the lender may impose additional operating and financial restrictions on us or modify the terms of the loan agreement.

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Under the amended loan agreement, quarter-end net debt to EBITDAX (as defined in the loan agreement) must be no more than 3.0 to 1.0. However, the quarter-end net debt to EBITDAX limitation has been raised to 5.0 to 1.0 for all periods through the end of 2016. Additionally, our debt service coverage ratio must be greater than 1.2 to 1.0 at each quarter end. Forecasting our compliance with these and other financial covenants in future periods is inherently uncertain. Factors that could impact our quarter-end financial covenants 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, 2016. However, we can make no assurance that we will be able to comply with these financial covenants in the future. 

Cash on Hand

At September 30, 2016, we had unrestricted cash of $26.9 million, including $15.0 million which previously was recorded as long term restricted cash prior to the September 30, 2016 quarterly reporting period.  Previously, we classified the $15.0 million commitment for drilling the three remaining Angola exploratory well commitments as long term restricted cash on our balance sheet; however, as a result of our decision to terminate the joint operating agreement, we are no longer reflecting the $15.0 million as restricted cash. We have also accrued $15 million for the penalty which we believe represents the maximum potential amount due under the agreement. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, we enter into project related activities on behalf of our working interest partners. We generally obtain advances from partners prior to significant funding commitments.

We currently sell our crude oil production from Gabon under a term contract that ends in January 2017. Pricing under the contract is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.  For additional disclosure about our liquidity and capital resources see “-Going Concern.”

Share Repurchase

In the three and nine months ended September 30, 2016, no purchases were made under the share repurchase program authorized by our Board of Directors on August 4, 2015. See the 2015 Form 10-K for further information about the program.

OFF-BALANCE SHEET ARRANGEMENTS

Our guarantee of the offshore Gabon FPSO lease has $133 million in remaining minimum obligations for the gross amount of charter payments at September 30, 2016.  There have been no other changes to our off-balance sheet arrangements since December 31, 2015.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

Other than the negotiated reduction in the drilling rig commitment,  the amendment of our loan agreement and the Sojitz purchase and sale agreement,  and the drilling obligation in Angola discussed in Notes 7,  6 and 4 respectively, to the condensed consolidated financial statements, there have been no significant changes to our commitments and contractual obligations subsequent to December 31, 2015.

CRITICAL ACCOUNTING POLICIES

There have been no changes to our critical accounting policies subsequent to December 31, 2015.

NEW ACCOUNTING STANDARDS

See Note 3 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three months ended September 30, 2016 compared to the three months ended September 30, 2015

We reported a  net loss for the three months ended September 30, 2016 of $15.6 million compared to a  $33.7 million net loss for the same period of 2015. These losses are inclusive of loss from discontinued operations for the three months ended September 30, 2016 of $15.8 million and income from discontinued operations for the three months ended September 30, 2015 of $0.9 million. Further discussion of results by significant line item follows:  

Oil and natural gas revenues decreased $2.9 million between the three months ended September 30, 2016 compared to the same period of 2015. Based on the average realized oil prices in the table below, the decrease in revenue is primarily related to 13% lower oil sales volume due to temporarily shut-in wells and 4% lower realized oil prices due to decreases in the Dated Brent market price. As a result of the elections in Gabon, we chose to lift earlier in the month in August which resulted in lower lifting volumes for the quarter.

The revenue changes in the three months ended September 30, 2016 identified as related to changes in price or volume are shown in the table below: 



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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 liftings in the third quarters of both 2016 and 2015. Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 39,000 and 55,000 barrels at September 30, 2016 and 2015.

Production expenses decreased $0.7 million in the three months ended September 30, 2016 compared to the same period of 2015 primarily as a result of cost reductions implemented in late 2015 and early 2016.

Exploration expense was minimal in the three months ended September 30, 2016.  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.    

Depreciation, depletion and amortization (“DD&A”) decreased $6.6 million in the three months ended September 30, 2016 compared to the same period of 2015.  For the three months ended September 30, 2016, DD&A per BOE was lower due to impairments in 2015.

General and administrative expenses decreased $0.2 million in the three months ended September 30, 2016 compared to the same period of 2015. This is primarily a result of lower stock-based compensation expense reflecting forfeitures related to employee departures.  In addition, we took steps beginning in 2015 to reduce overall general and administrative costs, with decreases realized in personnel costs, services and various other cost categories.  However, the amount of overhead we are able to recover from our partners in 2016 has decreased and partially offset the benefits from reductions in personnel and other costs. Under our operating agreements the amount of overhead recoverable is larger when capital spending is higher, as it was in 2015 with the development program in Gabon and the exploratory drilling in Angola. 

Impairment of proved properties is discussed in detail in Note 5 to the condensed consolidated financial statements.

Other operating expenses for the three months ended September 30, 2016 includes $0.2 million related to the demobilization and release of the contracted drilling rig in Gabon.

Interest expense decreased $0.1 million in the three months ended September 30, 2016 compared to the same period of 2015 due to conversion of the credit facility to the Term Loan. Under the terms of the original revolving credit facility, we paid commitment fees on the undrawn portion of the total commitment. From June 29, 2016 through December 31, 2016, commitment fees are 2.3% of the undrawn Additional Term Loan of $5 million. The decrease in commitment fees is partially offset by a decrease in capitalized interest as none of the interest expense incurred in the three months ended September 30, 2016 was capitalized; however, a considerable portion of the interest expense incurred in the same period of 2015 was capitalized. See Note 6 to the condensed consolidated financial statements for further discussion of our loan agreement and interest expense. 

Other, net consists primarily of derivative instrument gains (losses) as discussed in Note 8 to the condensed consolidated financial statements and foreign currency gains (losses).

Income tax expense decreased $0.5 million in the three months ended September 30, 2016 compared to the same period of 2015.  Income tax expense in both periods is primarily attributable to our operations in Gabon and is lower in 2016 than income tax for the comparable 2015 period as a result of lower revenues.

Income (loss) from discontinued operations is attributable to our Angola segment as discussed further in Note 4 to the condensed consolidated financial statements. Loss from discontinued operations increased $16.6 million in the three months ended September 30, 2016 compared to the same period of 2015 due to the $15.0 million accrual related to the potential drilling penalty in 2016 and a

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decrease of $2.0 million in foreign exchange gains. This was partially offset by a decrease of $0.7 million in general and administrative expenses in the three months ended September 30, 2016 compared to the same period of 2015.

Nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 

We reported a net loss of $23.9 million for the nine months ended September 30, 2016 compared to $77.9 million for the same period of 2015.  These losses are inclusive of losses from discontinued operations for the nine months ended September 30, 2016 and 2015 of $8.0 million and $27.8 million, respectively. Further discussion of results by significant line item follows:  

Oil and natural gas revenues decreased $18.5 million between the nine months ended September 30, 2016 compared to the same period of 2015. Based on the average realized oil prices in the table below, the decrease in revenue is primarily related to 26% lower realized oil prices, which are due to decreases in the Dated Brent market price. The improvement in oil sales volume in the first and second quarters of 2016 partially offset the volume reduction in the third quarter of 2016 when compared to 2015.

The revenue changes in the nine months ended September 30, 2016 identified as related to changes in price or volume are shown in the table below:









We made nine and eight liftings in the nine months ended September 30, 2016 and 2015, respectively.  

Production expenses decreased $0.9 million in the nine months ended September 30, 2016 compared to the same period of 2015. Cost reductions implemented in late 2015 and early 2016 are taking effect and the estimated accrual for workovers was reduced based on better information.

Exploration expense was minimal in the nine months ended September 30, 2016 compared to exploration expense for the nine months ended September 30, 2015, which was primarily comprised of the impairment of our unproved leasehold in Montana and seismic activity. 

Depreciation, depletion and amortization (“DD&A”) decreased $17.7 million in the nine months ended September 30, 2016 compared to the same period of 2015.  For the nine months ended September 30, 2016, DD&A per BOE rates were lower due to impairments in 2015.

General and administrative expenses decreased $0.5 million in the nine months ended September 30, 2016 compared to the same period of 2015. This is primarily a result of lower stock-based compensation expense reflecting forfeitures related to employee departures.  In addition, we took steps beginning in 2015 to reduce overall general and administrative costs, with decreases realized in personnel costs, services and various other cost categories. However, the full benefit of those reductions is not apparent because the amount of overhead we are able to recover from our partners in 2016 has decreased. Under our operating agreements the amount of overhead recoverable is larger when capital spending is higher, as it was in 2015 with the development program in Gabon and the exploratory drilling in Angola.

Impairment of proved properties is discussed in detail in Note 5 to the condensed consolidated financial statements.

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Other operating expenses for the nine months ended September 30, 2016 includes $2.1 million accrued for certain payroll taxes in Gabon which were not paid pertaining to labor provided to us over a number of years by a third-party contractor and $7.9 million, net to VAALCO, of expense associated with the demobilization and release of the contracted drilling rig. In June 2016, we reached an agreement with the drilling contractor to pay less than our originally estimated maximum day rate, plus demobilization costs, in seven equal monthly installments beginning in July 2016.

General and administrative related to shareholder matters for the nine months ended September 30, 2016 reflects our reimbursement by our insurance carrier of some previously expensed legal costs.  

Bad debt expense (recovery) and other for the nine months ended September 30, 2016 primarily consists of net increases in the VAT allowance.

Interest expense increased $1.2 million in the  nine months ended September 30, 2016 compared to the same period of 2015 primarily due to the write-off of deferred financing costs in June upon conversion of the credit facility to the Term Loan and a decrease in capitalized interest as none of the interest expense incurred in the nine months ended September 30, 2016 was capitalized; however, a considerable portion of the interest expense incurred in the same period of 2015 was capitalized. See Note 6 to the condensed consolidated financial statements for further discussion of our loan agreement and interest expense. 

Other, net consists primarily of derivative instrument gains (losses) as discussed in Note 8 to the condensed consolidated financial statements and foreign currency gains (losses).

Income tax expense decreased $3.5 million in the nine months ended September 30, 2016 compared to the same period of 2015. Income tax expense in both periods is primarily attributable to our operations in Gabon and is lower in 2016 than income tax for the comparable 2015 period as a result of lower revenues.

Loss from discontinued operations is attributable to our Angola segment as discussed further in Note 4 to the condensed consolidated financial statements. Loss from discontinued operations decreased $19.8 million in the nine months ended September 30, 2016 compared to the same period of 2015. Results for the nine months ended September 30, 2016 were primarily attributable to the $15.0 million accrual related to the potential drilling penalty and other exploration expense, partially offset by $7.6 million of bad debt recovery and $3.2 million of default interest discussed further in Note 1 to the condensed consolidated financial statements. Results for the 2015 comparable period were primarily attributable to dry hole costs for the Kindele #1 well. In addition, the 2015 comparable period included general and administrative expenses and foreign exchange gains.

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, derivative instruments 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 losing value against the U.S. dollar over recent quarters.

Interest Rate Risk

The floating rate on our amended loan agreement exposes us to risks associated with changes in interest rates (LIBOR). At September 30, 2016, we have a  $15.0 million term loan. Fluctuations in floating interest rates will cause our interest costs to fluctuate. If the balance of the debt at September 30, 2016 were to remain constant, a 1% change in market interest rates would impact our cash flow by an estimated $150,000 per year. As future quarterly payments reduce the principal of the term loan, our cash flow becomes less sensitive to fluctuations in interest rate.    

COUNTERPARTY Risk

We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparty. To mitigate this risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.

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Commodity Price Risk

Our major market risk exposure continues to be the prices received for our oil and natural gas production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for oil and natural gas have been volatile and unpredictable in recent years, and this volatility is expected to continue.  Beginning in the third quarter of 2014, the prices for oil and natural gas began a dramatic decline which continued through 2015 and into 2016. Current prices are significantly less than they were in the several years prior to 2015. Sustained low oil and natural gas prices or further decreases in oil and natural 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 IFC credit facility.  Were oil sales to remain constant at the most recent quarterly sales volumes of 343 MBbls, a $5 per Bbl decrease in oil price would be expected to cause a $1.7 million decrease per quarter ($6.9 million annualized) in revenues and operating income (loss) and a $1.4 million increase per quarter ($5.8 million annualized) in net loss.

In order to partially limit our commodity price risk, in April 2016, we entered into put contracts on 36,000 barrels of oil per month for the period from June 2016 through February 2017 at Dated Brent of $40 per barrel. This volume represents approximately one-third of our total forecasted sales volumes for the period. While these crude oil derivative contracts are intended to be an economic hedge, they are not designated as hedges for accounting purposes. The contracts are measured at fair value at the end of each quarter, with changes in value flowing through net income. See Note 8 to the condensed consolidated financial statements for further information about these contracts, their fair value and their impact on our net income. We had no commodity price derivatives outstanding as of and during the three and nine months ended September 30, 2015.

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 submit 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 by 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 Exchange Act) 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, 2015, a material weakness was previously identified in our internal control over financial reporting related to the control environment, risk assessment and internal control over financial reporting due to insufficient financial reporting resources.

A material weakness was previously identified by our management and disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014. In 2015, management began remediation measures to address this material weakness as described in our 2015 Form 10-K. Management determined that while the overall effectiveness of internal control over financial reporting was enhanced during 2015, newly implemented controls were not yet operating effectively at December 31, 2015. Accordingly, management, with oversight from our Audit Committee, determined to:

We began implementing these measures in the first quarter of 2016 and continue to refine the remediation plan. 

We believe that the steps described above and in our 2015 Form 10-K have enhanced the overall effectiveness of our internal control over financial reporting. However, management concluded that the newly implemented controls were not operating effectively at September  30, 2016 and that as of September  30, 2016 the same material weakness existed. Management is committed to improving its internal control processes and believes that the measures described above should remediate the material weakness that was identified in 2014 and continued into 2015 and strengthen internal control over financial reporting. As we continue to evaluate and improve internal control over financial reporting, adequate time to test and evaluate the effectiveness of the measure taken is needed and modifications to certain of the remediation procedures described above may be necessary. Distress in the oil and gas industry coupled with our status within that industry as a small company with some doubt about its ability to continue as a going concern present challenges in attracting and retaining finance and accounting personnel.  We have experienced changes in key finance and accounting personnel over the past few years, including during the third and fourth quarters of 2016 which results in uncertainty as to the effective implementation of our remedial actions.  We are working diligently to demonstrate the effectiveness of the remedial actions for the material weakness.

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 weakness that exists at September 30, 2016 will continue to exist.

Based on our evaluation of the material weakness described above, 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 this material weakness.

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Except for the activities taken related to the remediation of the material weakness described above, there were no changes in our internal control over financial reporting that occurred during three months ended September 30, 2016 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.

On December 7, 2015, Plaintiff Vladimir Gusinsky Living Trust filed a stockholder class action lawsuit in the Court of Chancery of the State of Delaware (the “Court”) against the Company and all of its directors alleging that certain provisions of the Company’s Restated Charter and Second Amended and Restated Bylaws that restricted the removal of its directors to removal for cause only (the “director removal provisions”) were invalid as a matter of Delaware law. Plaintiff George Shapiro also filed a similar stockholder class action lawsuit in the Court on December 7, 2015. Thereafter, the plaintiffs agreed to the consolidation of their cases (the “Consolidated Case”).

After a hearing on the Consolidated Case on December 21, 2015, Vice Chancellor Laster issued an opinion in In re VAALCO Energy, Inc. Stockholder Litigation, Consol. C.A. No. 11775-VCL holding that, in the absence of a classified board or cumulative voting, the director removal provisions conflicted with Section 141(k) of the Delaware General Corporation Law and are therefore invalid.

On April 20, 2016, the Court approved a Stipulation and Order of Dismissal entered into by the parties in the Consolidated Case. We agreed to settle plaintiffs’ application for an award of attorneys’ fees and expenses due to the costs of defense of that application and litigation risk associated therewith.

On October 3, 2016, the Court of Chancery of the State of Delaware (the “Court”) approved a Stipulation and Order of Dismissal entered into by the parties in a stockholder class action lawsuit against the Company and all of its directors alleging that a previously terminated shareholder rights agreement, no longer in effect, and certain provisions of the former CEO’s and former CFO’s employment agreements securing change-in-control severance benefits were invalid under Delaware law, case number C.A. No. 12277-VCL, filed on April 29, 2016,  in the Court.  After the Company and its directors moved to dismiss the lawsuit, the Plaintiff Daniel Butcher agreed to dismiss the lawsuit as moot, and the Company agreed to settle Plaintiff’s application for an award of attorneys’ fees, which it expects its insurer to pay, due to the anticipated costs of continuing to prosecute the motion to dismiss and defending the Plaintiff’s fee application, as well as the litigation risk associated therewith. 

The Stipulation and Order of Dismissal is attached as Exhibit 99.1 to this Quarterly Report on Form 10-Q and is incorporated herein by reference.

 ITEM 1A.  RISK FACTORS 

We may incur a significant penalty for failing to drill all the commitment wells under our production sharing contract in Angola

Under the production sharing contract for Block 5 in Angola, we and our working interest partner were obligated to perform certain exploration activities by November 30, 2017. In the first quarter of 2015, we drilled an unsuccessful exploratory well on the Kindele prospect, which satisfied one of the well commitments. The agreement requires us to drill or commence drilling three additional exploration wells by the expiration date. A $10.0 million assessment ($5.0 million net to VAALCO) applies to each of the three remaining exploratory well commitments, if any, that have not been drilled before the expiration of the license. We have evaluated the penalty provisions in the production sharing agreement, and believe that a substantial portion of the penalty has been satisfied with prior expenditures on the concession. Support for our determination is being presented to governmental authorities and we anticipate further discussions on this matter. However, due to the uncertainties as to the ultimate outcome, we have accrued a $15 million for the penalty, which represents the maximum potential amount due under the agreement. An unfavorable result on the resolution of the ultimate amount of the penalty could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

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 known 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 2015 Form 10-K. There have been no material changes in our risk factors from those described in our 2015 Form 10-K.

 

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ITEM 6.  EXHIBITS

(a) Exhibits 

(a)  Filed herewith

(b)  Furnished herewith



 

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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 8, 2016

 

 

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EXHIBIT INDEX

Exhibits



(a)  Filed herewith

(b)  Furnished herewith

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