UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q

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(Mark One)

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

For the quarterly period ended March 31, 2019



☐  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

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VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)

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(713) 623-0801

(Registrant’s telephone number, including area code)

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Securities registered pursuant to Section 12(b) of the Act:



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 every Interactive Data File required to be submitted 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 such files).    Yes  ☒    No  ☐ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 April 30, 2019, there were outstanding 59,796,459 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

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (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 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 SHAREHOLDERS’ EQUITY (Unaudited)

(in thousands)



































































See notes to condensed consolidated financial statements. 

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)













See notes to condensed consolidated financial statements. 

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VAALCO ENERGY, INC. AND SUBSIDIARIES

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. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO,” or the “Company”) is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration activities in Gabon, West Africa. We have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 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 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, 2018, which includes a summary of the significant accounting policies.

Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at March 31, 2019 and December 31, 2018, respectively; each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long term amounts at March 31, 2019 and December 31, 2018 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 10.  We invest restricted and excess cash in readily redeemable money market funds.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows:







We are required under the Exploration and Production Sharing Contract entitled “Etame Marin No. G4-160,” dated as of July 7, 1995, as amended, (the “Etame PSC”) for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts needed to fund the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in November 2018.  This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.  See Note 10 for further discussion.

Bad debts – Quarterly, we evaluate our accounts receivable balances to confirm collectability. When collectability is in doubt, we record an allowance against the accounts receivable, purchases of production and a corresponding income charge for bad debts, which appears in the “Bad debt recovery and other” line item of the condensed consolidated statements of operations. The majority of our accounts receivable balances are with our joint venture owners 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. Portions of our costs in Gabon (including our VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”).

As of March 31, 2019, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $7.7 million ($2.6 million, net to VAALCO).  As of March 31, 2019, the exchange rate was XAF 584.7 = $1.00.

For the three months ended March 31, 2019, we recorded a net recovery of $32 thousand related to the allowance for bad debt for VAT for which the government of Gabon has not reimbursed us.  For the three months ended March 31, 2018, we recorded a net recovery of $0.1 million.  The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and

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other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on profit/loss. Such foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.

The following table provides a roll forward of the aggregate allowance:



Derivative Instruments and Hedging Activities – We use derivative financial instruments to achieve a more predictable cash flow from oil production by reducing our exposure to price fluctuations.  Our derivative instruments at March 31, 2019 and December 31, 2018, consisted of oil swaps, which require us to pay a counterparty when the price of oil exceeds $74.00 per barrel, and where the price of oil falls below $74.00, we receive a payment from the counterparty.

 

We record balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments loss, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations.  See Note 8 for further discussion. 

Fair Value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:

Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in our internally developed present value of future cash flows model that underlies the fair-value measurement).

Fair value of financial instruments – Our assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets, accounts payable and guarantee. As discussed further above, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. With respect to our other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments.  There were no transfers between levels for the three months ended March 31, 2019.



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Leases – In February 2016, the Financial Accounting Standards Board (“FASB”) issued a new standard related to leases to increase transparency and comparability among organizations by requiring the recognition of operating lease right-of-use (“ROU”) assets and lease liabilities on the balance sheet. Most prominent among the changes in the standard is the recognition of ROU assets and lease liabilities by lessees for those leases classified as operating leases. Under the standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The Company is also required to recognize and measure new leases at the adoption date and recognize a cumulative-effect adjustment in the period of adoption using a modified retrospective approach, with certain practical expedients available.

 

The Company adopted Accounting Standards Codification (“ASC”) 842 effective January 1, 2019 using the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The standard had an impact on the Company’s condensed consolidated balance sheet but did not have an impact on the Company’s condensed consolidated statements of operations or condensed consolidated statements of cash flows upon adoption and as a result, a cumulative-effect adjustment was not required. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases.  See Notes 2 and 10 for further discussion. 

The Company determines whether an arrangement is a lease at inception. At commencement, the Company records a ROU asset and lease liability for the operating leases on its consolidated balance sheet based on the present value of lease payments over the lease term. ROU assets represent our right to use an underlying asset for the lease term and lease liability obligations represent our obligation to make lease payments arising from the lease. The Company has lease agreements that have both lease and non-lease components and has elected to separate these. Payments related to the lease component are included in the calculation of the lease liability; payments related to non-lease components are recorded consistent with other accounting guidance. The Company uses the implicit rate when readily determinable; however, as most of the Company’s leases do not provide an implicit rate, the Company estimated its incremental borrowing rate in accordance with the standard based on the information available at the commencement date in determining the present value of lease payments. The ROU asset also includes any lease payments made prior to the commencement date, including initial direct costs and excluding lease incentives. The Company’s lease terms include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Lease expense is recognized on a straight-line basis over the lease term.

Asset retirement obligations (“ARO”) – We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

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A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and natural gas properties. We use current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and natural gas production facilities. Accretion of interest increases the initial ARO liabilities over time until the liability matches the amount expected to settle the related retirement obligation. See Note 11 for further discussion.

Revenue recognition– Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements.  There is a single performance obligation (delivering oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place.  In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame PSC.  The Etame PSC is not a customer contract.  The terms of the Etame PSC includes provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price and a shared portion of “Profit Oil” determined based on daily production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs.  For both royalties and Profit Oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments. See Note 6 for further discussion.

Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Gains and losses on foreign currency transactions are included in income. Within the condensed consolidated statements of operations line item “Other income (expense)—Other, net,” we recognized a loss on foreign currency transactions of $0.2 million during the three months ended March 31, 2019.  During the three months ended March 31, 2018, we recognized a gain on foreign currency transactions of $0.1 million.  

Income taxes – Our tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year. We also operate in foreign jurisdictions where the tax laws relating to the oil and natural gas industry are open to interpretation which could potentially result in tax authorities asserting additional tax liabilities. While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered are earnings generated in previous periods, forecasted earnings and the expiration period of net operating loss carry forwards or foreign tax credit carryovers.

In certain jurisdictions, we may deem the likelihood of realizing deferred tax assets as remote where we expect that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, we have not recognized deferred tax assets.  Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material effect on our consolidated financial position and results of operations.  See Note 13 for further discussion.    

2.  NEW ACCOUNTING STANDARDS

Adopted

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”), which amends the accounting standards for leases.  This accounting standard was further clarified by ASU 2018-10, Codification Improvements to Topic 842 and ASU 2018-11, Leases: Targeted Improvements, both of which were issued in July 2018 together (“Topic 842”).  Topic 842 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 and 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. The amendments are effective for

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fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early application permitted. In transition, lessees and lessors may use either a prospective approach in which they recognize and measure leases at the date of adoption and recognize a cumulative effect adjustment to the opening balance of retained earnings or they may use a modified retrospective approach in which leases are recognized and measured at the beginning of the earliest period presented. We used the prospective approach with adoption of the new standard effective January 1, 2019.  Leases with terms greater than 12 months, which were previously treated as operating leases, have been capitalized. The adoption of this standard resulted in the recording of a right of use asset related to certain of our operating leases with a corresponding lease liability. This resulted in a significant increase in total assets and liabilities and a decrease in working capital.  In connection with our implementation plan, we reviewed our lease contracts and evaluated other contracts to identify embedded leases to determine the appropriate accounting treatment.    The new leasing standard requires capitalization based on the expected term of this lease which may or may not extend beyond the minimum period. The most significant lease we currently have is related to the FPSO.  As of January 1, 2019, for operating leases under which we are the lessee, we recorded a non‑cash adjustment of $38.9 million in “Right of use operating lease assets” to recognize an aggregate right‑of‑use asset, and we recorded a corresponding $10.2 million and $28.7 million in “Operating lease liabilities” and “Long-term operating lease liabilities,” respectively, for the aggregate operating lease liability.  We have accounted for lease and non‑lease components of our operating leases separately.  We have not recognized ROU assets or lease liabilities for our short‑term leases.  Our adoption did not have and is not expected in the future to have a material effect on our condensed consolidated statements of operations or cash flows.   See Note 10 for further discussion.

Not yet adopted

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in Accounting ASC 350, Intangibles - Goodwill and Other, in making the determination as to which implementation costs are to be capitalized as assets and which costs are to be expensed as incurred. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, and an entity can elect to apply the new guidance on a prospective or retrospective basis. The Company is currently evaluating the impact of adopting this guidance.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). This ASU modifies the disclosure requirements for fair value measurements. ASU 2018-13 removes the requirement to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements. ASU 2018-13 requires disclosure of changes in unrealized gains and losses for the period included in other comprehensive income (loss) for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For all entities, ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. We are currently evaluating the effect that this guidance will have on our consolidated financial statements and disclosures.

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 joint venture owners’ 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 15, 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.







3.  DISPOSITIONS

Discontinued Operations - Angola

In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). Our working interest is 40%, and we carry Sonangol P&P, for 10% of the work program.  On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P., that we were withdrawing from the Block 5 PSA. Further to the decision to withdraw from Angola, we have taken actions to close our office in Angola and reduce future activities in Angola. As a result of this strategic shift, 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 assets and liabilities as of March 31, 2019 and December 31, 2018 and its results of operations for the three months ended March 31, 2019 and 2018.

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Summarized Results of Discontinued Operations



Assets and Liabilities Attributable to Discontinued Operations



Drilling Obligation

Under the Block 5 PSA, we and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases identified in the Block 5 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The Block 5 PSA provides a stipulated payment of $10.0 million for each of the three exploration wells for which a drilling obligation remains under the terms of the Block 5 PSA, of which our participating interest share would be $5.0 million per well. We reflected an accrual of $15.0 million for a potential payment as of December 31, 2018.  The Company and Sonangol E.P. finalized and signed a settlement agreement which allows for the termination of the Company’s rights, liabilities and outstanding obligations for Block 5 in Angola in the first quarter of 2019. The settlement agreement includes a payment of $4.5 million from the Company and elimination of the $3.3 million receivable from Sonangol P&P. The receivable is related to joint interest billings and was reflected as current assets from discontinued operations at year-end 2018.  The cash payment from the Company will become due within 15 days after the execution of an executive decree from the Ministry of Mineral Resources and Petroleum.  As a result, the Company adjusted a previously accrued liability and recognized a net of tax non-cash benefit from discontinued operations of $5.7 million in the first quarter of 2019.



4.  SEGMENT INFORMATION

Our operations are based in Gabon and we have an undeveloped block in Equatorial Guinea.  Each of our two 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.

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Segment activity of continuing operations for the three months ended March 31, 2019 and 2018 as well as long-lived assets and segment assets at March 31, 2019 and December 31, 2018 are as follows:



















Information about our most significant customers

We sell our crude oil production from Gabon under term contracts with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.  From August 2015 through January 2019, we sold our crude oil to Glencore Energy UK Ltd.  (“Glencore”).  We signed a new contract with Mercuria Energy Trading SA (“Mercuria”) which covers sales from February 2019 through January 2020 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.  Sales of oil to Glencore and Mercuria were approximately 100% of total revenues for the period during the terms of their contracts.















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5.  EARNINGS PER SHARE

Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, we assume that restricted stock is outstanding on the date of vesting, 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:   





















6.  REVENUE



Substantially all of our revenues are attributable to our Gabon operations.  Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPA”). These contracts have been and will be renewed or replaced from time to time either with the current buyer or another buyer. Since August 2015, the COSPA has been executed with the same buyer, initially for a one-year period, with amendments to extend the period through January 31, 2018.  On February 1, 2018, a new COSPA was entered into with this same customer, which terminated January 31, 2019.  A new COSPA with a different customer has been executed for the period from February 2019 through January 2020.

   

The COSPA with the third party is renegotiated near the end of the contract term and may be entered into with a different buyer or the same buyer going forward.   Except for internal costs (which are expensed as incurred), there are no upfront costs associated with obtaining a new COSPA. 



Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place.  This is referred to as a “lifting”.  Liftings can take one to two days to complete.  The intervals between liftings are generally 30 days; however, changes in the timing of liftings will impact the number of liftings which occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations.  We have utilized the practical expedient in ASC Topic 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. 



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We account for production imbalances as a reduction in reserves.  See Note 2 for further information.  The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property, and we would recognize a liability if our existing proved reserves were not adequate to cover an imbalance.



For each lifting completed under the COSPA, payment is made by the customer in U.S. Dollars by electronic transfer thirty days after the date of the bill of lading.  For each lifting of oil, the price is determined based on a formula using published Dated Brent prices as well as market differentials plus a fixed contract differential.



Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, we deem this situation to be characterized as a fixed price situation.

 

In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame PSC.  The Etame PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606.  The terms of the Etame PSC includes provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price, a shared portion of “profit oil” determined based on daily production rates, and a carried working interest of 7.5% (increasing to 10% beginning June 20, 2026).  For both royalties and profit oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments.

To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment.  Payments for royalties are reflected as a reduction in revenues from customers.  Should the government elect to take the production attributable to its royalty in-kind, we would no longer have sales to customers associated with production assigned to royalties.

With respect to the government’s share of profit oil, the Etame PSC provides that corporate income tax is satisfied through the payment of profit oil.  In the condensed consolidated statements of operations, the government’s share of revenues from profit oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense.  Prior to February 1, 2018, the government did not take any of its share of profit oil in-kind.  These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract.  For the in-kind sales by the government beginning February 1, 2018, these are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil.  However, consistent with the reporting of profit oil in prior periods, the amount associated with the profit oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported in current income tax expense.  Payments of the income tax expense will be reported in the period in which the government takes its profit oil in-kind, i.e. the period in which it lifts the crude oil.  As of March 31, 2019 and December 31, 2018, the foreign taxes payable attributable to this obligation is $4.5 million and $3.3 million, respectively.  

Certain amounts associated with the carried interest in the Etame PSC discussed above are reported as revenues.  In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs which would otherwise be the obligation of the carried party.  The carrying parties recoup these funds from the carried interest party’s revenues.

The following table presents revenues from contracts with customers as well as revenues associated with the obligations under the Etame PSC.





7.  OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

Extension of Term of Etame PSC

On September 25, 2018, VAALCO together with the other joint owners in the Etame Marin block (the “Consortium”) received an implementing Presidential Decree from the government of Gabon authorizing an extension for additional years (“PSC Extension”) to the Consortium to operate in the Etame Marin block.  Our subsidiary, VAALCO Gabon S.A., has a 33.575% participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.  

The PSC Extension extends the term for each of the three exploitation areas in the Etame Marin block for a period of ten years with effect from September 17, 2018, the effective date of the PSC Extension.  Prior to the PSC Extension, the exploitation periods for the

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three exploitation areas in the Etame Marin block would expire beginning in June 2021.  The PSC Extension also grants the Consortium the right for two additional extension periods of five years each.  The PSC Extension further allows the Consortium to explore the potential for resources within the Exclusive Exploitation Authorization area as defined in the PSC Extension. 

In consideration for the PSC Extension, the Consortium agreed to a signing bonus of $65.0 million ($21.8 million, net to VAALCO) payable to the government of Gabon (the “Signing Bonus”).  The Consortium paid $35.0 million ($11.8 million, net to VAALCO) in cash on September 26, 2018 and paid $25.0 million ($8.4 million, net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the Consortium as of the effective date.  An additional $5.0 million ($1.7 million, net to VAALCO) is to be paid in cash by the Consortium following the end of the drilling activities described below.  We have accrued our $1.7 million share of this remaining payment as of September 30, 2018.  The amount paid through a reduction in VAT has been recorded at $4.2 million which represents the book value of the receivable, net of the valuation allowance as of the effective date.  In addition, we recorded an increase of $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis.  A corresponding $18.6 million deferred tax liability was recorded which reduced our net deferred tax assets.  We have allocated our share of the Signing Bonus between proved and unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas resulting in $22.5 million being attributed to proved leasehold costs and $13.7 million attributed to unproved leasehold costs.

Under the PSC Extension, by September 16, 2020, the Consortium is required to drill two wells and two appraisal well bores.  We estimate the cost of these wells will be approximately $61.2 million ($20.5 million, net to VAALCO).  If the wells are not drilled, then the Consortium must pay the difference between the amounts spent on any wells that were drilled and the estimated costs of the wells as set forth in the Work Program and Budget as approved by the government of Gabon.  The Consortium is planning to commence drilling these wells in the second half of 2019.  The Consortium is also required to complete two technical studies by September 16, 2020 at an estimated cost of $1.3 million gross ($0.4 million, net to VAALCO).

Prior to the PSC Extension, the Consortium was entitled to take up to 70% of production remaining after the 13% royalty (“Cost Recovery Percentage”) to recover its costs so long as there are amounts remaining in the Cost Account.  Under the PSC Extension, the Cost Recovery Percentage is increased to 80% for the ten-year period from September 17, 2018 through September 16, 2028.  After September 16, 2028, the Cost Recovery Percentage returns to 70%.  

Prior to the PSC Extension, the Etame PSC provided for the government of Gabon to take a 7.5% gross working interest carried by the Consortium.  The government of Gabon transferred this interest to a third party.  Pursuant to the PSC Extension, the government of Gabon will acquire from the Consortium an additional 2.5% gross working interest carried by the Consortium effective June 20, 2026.  VAALCO’s share of this interest to be transferred to the government of Gabon is 0.8%.

Depletion and Impairment

We review our oil and natural gas producing properties for impairment quarterly or 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.

There was no triggering event in the first quarter of 2019 that would cause us to believe the value of oil and natural gas producing properties should be impaired.  Factors considered included the fact that we incurred no significant capital expenditures in 2019 related to the fields in the Etame Marin block, the future strip prices for the first quarter of 2019 increased from the fourth quarter of 2018, and there were no indicators that adjustments were needed to the year-end reserve report.

There was no triggering event in the first quarter of 2018 that would cause us to believe the value of oil and natural gas producing properties should be impaired.  Factors considered included the fact that we incurred no significant capital expenditures in 2018 related to the fields in the Etame Marin block, the future strip prices for the first quarter of 2018 modestly increased from the fourth quarter of 2017, and there were no indicators that adjustments were needed to the  year-end reserve report.

Undeveloped Leasehold Costs

We have a 31% working interest in an undeveloped portion of a block offshore Equatorial Guinea that we acquired in 2012 (the “Block P interest”). We are currently awaiting the Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”) to approve our appointment as operator for Block P.  Compania Nacional de Petroleos de Guinea Equatorial (“GEPetrol”) is the state-owned oil company and one of the joint venture owners in Block P.  GEPetrol was required to introduce a new investor or joint venture owner to the EG MMH by March 28, 2019, and it has fulfilled this requirement.  Upon EG MMH approving the new join owner, the Contractor group has one year to drill an exploration well.  We intend to seek a joint venture owner on a promoted basis that will cover all or substantially all of the cost to drill an exploratory well.  If the joint venture owners fail to drill an exploration well, we would lose our interest in the license, and the associated costs would become impaired.  As of March 31, 2019, we had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license.  We and our joint venture owners are evaluating

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the timing and budgeting for development and exploration activities under a development and production area in the block, including the approval of a development and production plan.  The production sharing contract covering this development and production area provides for a development and production period of 25 years from the date of approval of a development and production plan.

As a result of the PSC Extension, the exploitation area was expanded to include previously undeveloped acreage.  We allocated $6.7 million of our share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas.  Exploitation of this additional area is permitted throughout the term of the Etame PSC.

8. DERIVATIVES AND FAIR VALUE

We use derivative financial instruments to achieve a more predictable cash flow from oil production by reducing our exposure to price fluctuations.  See Note 2 for further information.

Commodity swaps - In June 2018, we entered into commodity swaps at a Dated Brent weighted average of $74.00 per barrel for the period from and including June 2018 through June 2019 for a quantity of approximately 400,000 barrels.  These swaps settle on a monthly basis.  At March 31, 2019, our unexpired commodity swaps were for an underlying quantity of 68,000 barrels and had a fair value asset position of $0.5 million reflected in “Prepayments and other” line of our condensed consolidated balance sheet.  These swaps settle on a monthly basis. 

While these commodity swaps 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 are being 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.



The crude oil swaps contracts are measured at fair value using the Black Scholes 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 swap and put contracts 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 loss on derivative instruments on our condensed consolidated statements of operations:



On May 6, 2019, we entered into commodity swaps at a Dated Brent weighted average of $66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels.  These swaps settle on a monthly basis.  If a liability position for these swaps combined with our swaps at March 31, 2019 exceeds $10.0 million, we would be required to provide a bank letter of credit or deposit cash into an escrow account for the amount by which the liability exceeds $10.0 million.



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9.  DEBT

On May 22, 2018, we terminated our amended term loan agreement (“Amended Term Loan Agreement”) we had with the International Finance Corporation (“IFC”) by prepaying the outstanding principal and accrued interest.  We did not incur any termination or prepayment penalties as a result of the termination of the Amended Term Loan Agreement.

Interest 

The table below shows the components of the “Interest income (expense), net” line item of our condensed consolidated statements of operations and the average effective interest rate, excluding commitment fees, on our borrowings:





10.  COMMITMENTS AND CONTINGENCIES

Leases

Under the new leasing standard which became effected January 1, 2019, there are two types of leases: finance and operating.  Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the stream of future lease payments. 



Practical Expedients – The new standard provides a package of three practical expedients to simplify adoption.  At the transition date, the entity may elect not to reassess: (1) whether any expired or existing contracts as of the adoption date are or contain leases under the new definition of a lease, (2) lease classification for expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date.  These three expedients must be elected or not elected as a package.   An entity that elects to apply all three of the practical expedients will, in effect, continue to classify leases that commence before the adoption date in accordance with current GAAP, unless the lease classification is reassessed after the adoption date.  A lessee that elects to apply all of the practical expedients beginning on the adoption date will follow subsequent measurement guidance in ASC 842.  The Company has elected to use these practical expedients, effectively carrying over its previous identification and classification of leases that existed as of January 1, 2019.  Additionally, a lessee may elect not to recognize ROU assets and liabilities arising from short-term leases provided there is no purchase option the entity is likely to exercise. The Company has elected this short-term lease exemption.  The adoption of ASC 842 resulted in a material increase in our total assets and liabilities on our condensed consolidated balance sheet as certain of our operating leases are significant. In addition, adoption resulted in a decrease in working capital as the ROU asset is noncurrent but the lease liability has both long-term and short-term portions.  There was no material overall impact on results of operations or cash flows.  In the statement of cash flows, operating leases remain an operating activity.



The Company has entered into several agreements for the lease of office, warehouse and storage yard space, the FPSO and a hydraulic workover rig (“HWU”).  The duration for these agreements ranges from 21 to 45 months. The FPSO, HWU and office space contracts requires us to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset relate to the lease component and are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities.  For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount which will be funded by the non-operators.  As operator for the Etame Marin block, the ROU asset recorded for the FPSO, HWU and warehouse and storage yard space used in the joint operations includes the gross amount of the lease components. 



The FPSO lease includes an option to extend the term through September 2022. We considered this option reasonably certain of exercise and have included it in the calculation of ROU assets and lease liabilities.



The FPSO and HWU agreements also contain options to purchase the assets during or at the end of the lease term. We do not consider these options reasonably certain of exercise and have excluded the purchase price from the calculation of ROU assets and lease liabilities.

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The FPSO and HWU leases include provisions for variable lease payments, under which we are required to make additional payments based on the level of production or the number of days the asset is deployed. Because we do not know the extent to which we will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities.



The discount rate used to calculate ROU assets and lease liabilities represents our incremental borrowing rate. We determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate we would incur to borrow the lease payments.



For the three months ended March 31, 2019, the components of the lease costs and the supplemental information were as follows:







The table below describes the presentation of the total lease cost on our consolidated statement of operations. As discussed above, our joint venture owners are required to reimburse us for their share of certain expenses, including certain lease costs.







The following table describes the future maturities of our operating lease liabilities at March 31, 2019:





Under the joint operating agreements, other joint owners are obligated to fund $27.7 million of the $40.5 million in future lease liabilities.

Abandonment funding

As part of securing the first of two five-year extensions to the Etame PSC to which we are entitled from the government of Gabon, we agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. The agreement was finalized in the first quarter of 2014 (effective as of 2011) providing for annual funding over a period of ten years in amounts equal to 12.14% of the total abandonment estimate for the first seven years and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable. The abandonment estimate used for this purpose is approximately $61.8 million ($19.2 million net to VAALCO) on an undiscounted basis. Through March 31, 2019,  $36.7 million ($11.4 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheets. Future changes

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to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.   

On March 5, 2019, in accordance with certain foreign currency regulatory requirements, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar denominated account transferred the funds to the Central Bank for “CEMAC” (the Central African Economic and Monetary Community), of which Gabon is one of the six member states.  The U.S. dollars were converted to local currency with a credit back to the Gabonese branch.  Amendment 5 to the Etame PSC provides that in the event that the Gabonese bank fails for any reasons to reimburse all of the principal and interest due, we will no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.

FPSO charter 

In connection with the charter of the FPSO, we, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term, which expires in September 2022. At our election, the charter may be extended for two one-year periods beyond September 2020. We obtained guarantees from each of our joint venture owners for their respective shares of the payments. Our net share of the charter payment is 31.1%, or approximately $9.7 million per year. Although we believe the need for performance under the charter guarantee is remote, we recorded a liability of $0.3 million as of March 31, 2019 and December 31, 2018 representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO charter has $53.9 million in remaining gross minimum obligations as of December 31, 2018.

Estimated future minimum obligations through the end of the FPSO charter which reflects the right of early termination are as follows as of December 31, 2018 (in thousands):



The FPSO charter payment includes a $0.93 per barrel charter fee for production up to 20,000 barrels of oil per day and a $2.50 per barrel charter fee for those barrels produced in excess of 20,000 barrels of oil per day. VAALCO’s net share of payments was $10.8 million for the year ended December 31, 2018. 

Other lease obligations

In addition to the FPSO, we have other operating lease obligations as of December 31, 2018 (in thousands):I

We incurred rent expense of $0.4 million during the three months ended March 31, 2018. 

Regulatory and Joint Interest 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 2016, the government of Gabon conducted an audit of our operations in Gabon, covering the years 2013 through 2014. We received the findings from this audit and responded to the audit findings in January 2017.  Since providing our response, there have been changes in the Gabonese officials responsible for the audit.  We are currently working with the newly appointed representatives to

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resolve the audit findings.  We do not anticipate that the ultimate outcome of this audit will have a material effect on our financial condition, results of operations or liquidity.

At December 31, 2018, we had accrued $1.3 million, net to VAALCO, in “Accrued liabilities and other” on our condensed consolidated balance sheets for potential fees which may result from customs audits.  This matter was fully resolved in January 2019 for $1.3 million, net to VAALCO. 

Drilling Rig

We have contracted a drilling rig to be used to drill two wells, including two appraisal well bores,  for our Etame Marin joint operations beginning in the second half of 2019. The agreement includes options to drill four additional wells at the Etame Marin block.  The drilling rig contract stipulates a day rate of approximately $75,000. We expect the term associated with the drilling rig commitment to be less than one year.

11. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in our asset retirement obligations:



Accretion is recorded in the line item “Depreciation, depletion and amortization” on our condensed consolidated statements of operations.

We are required under the Etame PSC to conduct regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block.  In 2018, we recorded a downward revision of $6.5 million to the ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 10.  The most recently completed abandonment study was in November 2018.   

12.  STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS

Our stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of our Board of Directors to issue various types of incentive compensation. Currently, we have issued stock options, restricted shares and stock appreciation rights from the 2014 Long-Term Incentive Plan (“2014 Plan”). At March 31, 2019, 491,880 shares were authorized for future grants under the 2014 plan.

For each stock option granted, the number of authorized shares under the 2014 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2014 Plan will be reduced by twice the number of restricted shares. We have no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.

We record non-cash compensation expense related to stock-based compensation as general and administrative expense.  For the three months ended March 31, 2019 and 2018, non-cash compensation was $1.7 million and $0.3 million, respectively, related to the issuance of stock options, restricted stock and stock appreciation rights. Because we do not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.

Stock options

Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of our Board of Directors, which in the past has been a five-year 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. There were $47 thousand and zero in cash proceeds from the exercise of stock options in the three months ended March 31, 2019 and 2018, respectively.  During the three months ended March 31, 2019, the Company granted stock options for 622,140 shares to employees; these options vest over a three-year period, vesting in three equal parts on the first, second and third anniversaries after the date of grant with an exercise price of $2.33 per share.  On April 1, 2019, the Company granted stock options for 44,163 shares to an employee with an exercise price of $2.29 per share. 

During the three months ended March 31, 2019, 13,875 shares were added to treasury as a result of tax withholding on options exercised.

We use the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the vesting period of the option. During the three months ended March 31, 2019 and 2018, the weighted average

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assumptions shown below were used to calculate the weighted average grant date fair value of option grants. Because we have not paid cash dividends and do not anticipate paying cash dividends on the common stock in the foreseeable future, no expected dividend yield was input to the Black-Scholes model.









Stock option activity for the three months ended March 31, 2019 is provided below:





Restricted shares

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 anniversaries following the date of the grant. Share grants to directors vest immediately and are not restricted.   During the three months ended March 31, 2019, the Company issued 174,464 shares of service based restricted stock to employees with a grant date fair value of $2.33 per share.  The vesting of these shares is dependent upon the employee’s continued service with the Company.   The shares will vest in three equal parts over three years.  On April 1, 2019, the Company issued 22,926 shares of service based restricted stock to an employee with a grant date fair value of $2.29 per share.  The vesting of these shares is dependent upon the employee’s continued service with the Company.  The shares will vest in three equal parts over three years. 

The following is a summary of activity in unvested restricted stock in the three March 31, 2019

During the three months ended March 31, 2019, 30,573 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.  During the three months ended March 31, 2018, no shares were added to treasury as a result of tax withholding on the vesting of restricted shares.

Stock appreciation rights (“SARs”)

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.

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During the three months ended March 31, 2019, 951,699 SARs were granted which vest over a three-year period with a life of 5 years and have a $2.33 SAR price per share specified in a SAR award on the date of grant.      

SAR activity for the three months ended March 31, 2019 is provided below:



Other Benefit Plans

On May 2, 2019, the Company adopted a form of change in control agreement for its named executive officers and certain other officers of the Company and amended its severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control.  Under the agreements and severance plan, upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, the participant will be entitled to receive a cash amount equal to between 50% and 100% of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months.  In addition, named executive officers will receive 75% of their target bonus. 



13. INCOME TAXES

For 2019, we will determine our tax expense by estimating an annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit.

The income tax provision for VAALCO consists primarily of Gabonese and United States income taxes.  Our operations in other foreign jurisdictions have a 0% effective tax rate because we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.

Provision for income taxes related to income (loss) from continuing operations consists of the following:







Our effective tax rate for the three months ended March 31, 2019 is 77%.   For the three months ended March 31, 2018, we recorded tax expense using the actual tax rate.  For the three months ended March 31, 2019, our overall effective tax rate was impacted by non-deductible items associated with our operations and deducting foreign taxes rather than crediting them for United States tax purposes.   

The Company files income tax returns in all jurisdictions where such requirements exist; however, our primary tax jurisdictions are Gabon and the United States.

As of March 31, 2019, the Company had no material uncertain tax positions.  The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.











































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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 (the “Securities Act”), 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 Annual 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,” the negative of such terms 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, 2018 (“2018 Form 10-K”) 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 uncertainties inherent in the forward-

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looking statements, which are included in this report and the 2018 Form 10-K, 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 reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements are expressly qualified in their entirety by this “Special Note Regarding Forward-Looking Statements,” which constitute cautionary statements.

INTRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration activities in Gabon, West Africa. We have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 to the condensed consolidated financial statements, we have discontinued operations associated with our activities in Angola, West Africa.

Our financial results are heavily dependent upon the margins between prices received for our offshore Gabon oil production and the costs to find and produce such oil. In light of the volatility of oil prices over the past several years, we have focused on maximizing our margins by reducing costs, paying off debt, divesting non-core assets, minimizing capital expenditures and maintaining our existing production at optimal levels.  On September 25, 2018, the term of the Etame PSC with Gabon, related to the Etame Marin block located offshore, was extended through 2028 with options to extend up to an additional ten years. The PSC Extension provides us with the extended time horizon necessary to pursue developing the resources we have identified at Etame. See Note 7 for further discussion.  As a result of these efforts, our financial position has improved, and we believe that we have working capital sufficient to sustain current operations and fund development projects on our Etame license in Gabon. In combination with improved oil pricing and positive production performance, the PSC Extension enabled us to increase proved reserves during 2018 by 76% to 5.4 MMBbls at December 31, 2018 which include reserves for wells we expect to drill in 2019.



CURRENT DEVELOPMENTS 



VAALCO and its joint owners have moved forward with executing a development drilling program for 2019.  We have contracted a drilling rig to be used to drill two wells, including two appraisal well bores, for our Etame Marin joint operations beginning in the second half of 2019. The agreement includes options to drill four additional wells at the Etame Marin block.  We believe that there is significant reserve upside associated with the two appraisal wellbores.  We are forecasting that the 2019 drilling program will be funded by cash on hand and cash generated from operations.

ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of four companies. As of March 31, 2019, production operations in the Etame Marin block included nine platform wells, plus three subsea wells across all fields 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 FPSO anchored to the seabed on the block.  We currently have twelve producing wells.  The FPSO has production limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day. During the three months ended March 31, 2019 and 2018, production from the block was approximately 1,164 MBbls (315 MBbls net) and 1,200 MBbls (325 MBbls net), respectively.  Production was adversely impacted due to work stoppage by non-VAALCO employees onboard the FPSO in late March 2019. The work stoppage did not hinder the completion of VAALCO’s March lifting. 

Equatorial Guinea

VAALCO has a 31% working interest in an undeveloped portion of a block offshore Equatorial Guinea that it acquired in 2012 (the “Block P interest”). We are currently awaiting the Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”) to approve our appointment as operator for Block P.  Compania Nacional de Petroleos de Guinea Equatorial (“GEPetrol”) is the state-owned oil company and one of the joint venture owners in Block P.  GEPetrol was required to introduce a new investor or joint venture owner to the EG MMH by March 28, 2019, and it has fulfilled this requirement.  Upon EG MMH approving the new join owner, the Contractor group has one year to drill an exploration well.  VAALCO intends to seek a joint venture owner on a promoted basis that will cover all or substantially all of the cost to drill an exploratory well.  If the joint venture owners fail to drill an exploration well, VAALCO would lose its interest in the license, and the associated costs would become impaired.  As of March 31, 2019, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license.  VAALCO and its joint

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venture owners are evaluating the timing and budgeting for development and exploration activities under a development and production area in the block, including the approval of a development and production plan.  The production sharing contract covering this development and production area provides for a development and production period of 25 years from the date of approval of a development and production plan.  

Discontinued Operations - Angola

In November 2006, we signed a production sharing contract for the Block 5 PSA. Our working interest is 40%, and it carries Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P., that we were withdrawing from the Block 5 PSA.  Further to our decision to withdraw from Angola, we have closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the condensed consolidated financial statements for all periods presented.

Drilling Obligation

Under the Block 5 PSA, we and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases under the Block 5 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The Block 5 PSA provides a stipulated payment of $10.0 million for each exploration well for which a drilling obligation remains under the terms of the Block 5 PSA, of which our participating interest share would be $5.0 million per well. We reflected an accrual of $15.0 million for a potential payment as of December 31, 2018. The Company and Sonangol E.P. finalized and signed a settlement agreement which allows for the termination of the Company’s rights, liabilities and outstanding obligations for Block 5 in Angola in the first quarter of 2019. The settlement agreement includes a payment of $4.5 million from the Company and elimination of the $3.3 million receivable from Sonangol P&P. The receivable is related to joint interest billings and was reflected as current assets from discontinued operations at year-end 2018.  The cash payment from the Company will become due within 15 days after the execution of an executive decree from the Ministry of Mineral Resources and Petroleum.  As a result, the Company adjusted a previously accrued liability and recognized a net of tax non-cash benefit from discontinued operations of $5.7 million in the first quarter of 2019.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the three months ended March 31, 2019 and 2018 are as follows:



The decrease in net cash provided by our operating activities for the three months ended March 31, 2019 compared to the same period of 2018 was primarily related to a $1.4 million decrease in cash generated by continuing operations before change in operating assets and liabilities, which was mainly due to lower 2019 crude oil volumes.  Net cash provided by our operating assets and liabilities increased by $0.7 million compared to same period of 2018.   The net change in operating assets and liabilities of $4.7 million for the three months ended March 31, 2019 was primarily due to an $8.9 million decrease in trade and other receivables and a $1.0 million increase in foreign taxes payable offset by a decrease in “Accounts payable” of $3.9 million. The net change in operating assets and liabilities of $5.4 million for the three months ended March 31, 2018 included $8.1 million in payments made by joint venture owners partially offset by a pay down of “Accounts payable” and “Accrued liabilities and other” of $1.1 million. 

Property and equipment expenditures have historically been our most significant use of cash in investing activities. During the three months ended March 31, 2019, these expenditures on a cash basis were $0.8 million, primarily related to equipment purchases. This compares to  $0.4 million in property and equipment expenditures included in capital expenditures for the three months ended March 31,

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2018. See “Capital Expenditures” below for further discussion. 

Capital Expenditures

During the three months ended March 31, 2019, we made accrual basis capital expenditures of $0.7 million.  Pursuant to the PSC Extension as discussed in Note 7, we have commitments for capital expenditures related to the drilling of two wells and two appraisal well bores at an estimated cost of approximately $61.2 million ($20.5 million, net to VAALCO), by September 16, 2020.  We anticipate drilling these wells and a possible third well in the second half of 2019 and the first quarter of 2020.  The third well is subject to approval by the joint venture owners and the government of Gabon. 

Contractual Obligations

See Note 10 to the condensed consolidated financial statements as well as our 2018 Form 10-K for discussion of our contractual obligations.

During the three months ended March 31, 2019, we entered into a drilling rig contract.   There were no other material changes in our contractual obligations during the three months ended March 31, 2019.

Regulatory and Joint Interest 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.  See Note 10 to the condensed consolidated financial statements.

Capital Resources

Credit Facility 

Historically, our primary sources of capital have been cash flows from operating activities, borrowings under the Amended Term Loan Agreement with the IFC and cash balances on hand.  On May 22, 2018, we terminated the Amended Term Loan Agreement by prepaying the outstanding principal and accrued interest.  We did not incur any termination or prepayment penalties as a result of the early termination of the Amended Term Loan Agreement. 

Cash on Hand

At March 31, 2019, we had unrestricted cash of $46.2 million. The unrestricted cash balance includes $4.4 million of cash attributable to non-operating joint venture owner advances.  As operator of the Etame Marin block in Gabon, we enter into project related activities on behalf of our working interest joint venture owners. We generally obtain advances from the joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations for the foreseeable future.

We currently sell our crude oil production from Gabon under a term contract that began in February 2019 and ends in January 2020. Pricing under the contract is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Liquidity

As discussed above, our revenues, cash flow, profitability, oil and natural gas reserve values and future rates of growth are substantially dependent upon prevailing prices for oil. Our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil prices.  After a period of low commodity prices, oil and natural gas prices have stabilized at levels which are currently adequate to generate cash from operating activities for our continuing operations. In addition to the impact of oil and natural gas prices on our access to capital markets, the availability of capital resources on attractive terms may be limited due to the geographic location of our primary producing assets. As discussed above, we are committed to drill two wells and two appraisal well bores in the Etame Marin block by September 16, 2020. In addition, the conditions for lifting the suspension for Block P require the drilling of one exploration well in Block P by September 2020, although there is no financial penalty for not meeting this requirement.  We expect any capital expenditures made during 2019 will be funded by cash on hand and cash flow from operations.  We believe that at current prices, cash generated from continuing operations, together with cash on hand at March 31, 2019, are adequate to support our operations and cash requirements during 2019 and through June 30, 2020.

At December 31, 2018, we had 5.4 MMBbls of estimated net proved reserves, all of which are related to the Etame Marin block offshore Gabon.  The current term for exploitation of the reserves in the Etame Marin block ends in September 2028 with rights for two five-year extension periods.  Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. While both short-term and long-term liquidity are impacted by crude oil prices, our long-term liquidity also depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. 

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OFF-BALANCE SHEET ARRANGEMENTS

None.

CRITICAL ACCOUNTING POLICIES

There have been no changes to our critical accounting policies subsequent to December 31, 2018 except for the adoption of a new leasing standard on January 1, 2019.  See Note 1 to the condensed consolidated financial statements. 

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

We reported net income for the three months ended March 31, 2019 of $6.5 million compared to net income of $8.7 million for the same period of 2018. The net income for the three months ended March 31, 2019 is inclusive of the income from discontinued operations for the same period of $5.7 million. The net income for the three months ended March 31, 2018 was inclusive of the loss from discontinued operations for the same period of $0.1 million. Substantially all of our operations are attributable to our Gabon segment.   Further discussion of results by significant line item follows.

Oil and natural gas revenues decreased $7.9 million, or approximately 28.5%, during the three months ended March 31, 2019 compared to the same period of 2018. The decrease in revenue is primarily attributable to lower sales volumes.

The revenue changes in the three months ended March 31, 2019 compared to the three months ended March 31, 2018, identified as related to changes in price or volume, are shown in the table below: 

















Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made three liftings in the first quarter of 2019 and four liftings in the first quarter 2018.  Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 48,668 and 50,400 barrels at March 31, 2019 and 2018, respectively.  Production volumes for the three months ended March 31, 2019 were lower than the comparable 2018 period as a result of production being adversely impacted due to work stoppage by non-VAALCO employees onboard the FPSO in late March 2019. The work stoppage did not hinder the completion of VAALCO’s March lifting.  Sales volumes were lower between the periods because sales volumes for the three months ended March 31, 2018 included 95,525 barrels associated with the last lifting in 2017 which was not completed until January 1, 2018.  Net revenues of $6.5 million associated with these net volumes were reported as revenue in 2018 in the three months ended March 31, 2018.

Production expenses decreased $2.7 million, or approximately 25.0%, in the three months ended March 31, 2019 compared to the same period of 2018. The decrease was primarily a result of lower sales volumes.   

Depreciation, depletion and amortization (“DD&A”) costs increased due to higher depletable costs associated with the PSC Extension as discussed in Note 7 condensed consolidated financial statements. 

General and administrative expenses increased $1.8 million, or approximately 70.5% in the three months ended March 31, 2019 compared to the same period of 2018.  Stock-based compensation expense related to SARs was $1.7 million during the three months ended March 31, 2019 as compared to $0.2 million in the comparable 2018 period.  Because SARs are cash settled, these awards are adjusted to fair value each period, and as a result of the significant increase in our stock price of $0.77 from $1.47 at December 31, 2018 to $2.24 at March 31, 2019, the amount of expense increased significantly.  Legal fees, professional fees and other taxes were also higher during the three months ended March 31, 2019 compared to the same period in 2018.   

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Bad debt recovery and other was substantially unchanged between the three months ended March 31, 2019 and 2018.  

Interest income (expense), net for the three months ended March 31, 2019 relates to interest income on cash balances as comparable to March 31, 2018 which relates to our term loan with the IFC as discussed in Note 9 to the condensed consolidated financial statements and to interest on taxes other than income taxes.     

Derivative instruments loss, net for the three months ended March 31, 2019 is attributable to our swaps as discussed in Notes 8 to the condensed consolidated financial statements and is a result of the increase in the price of Dated Brent crude oil between December 31, 2018 and March 31, 2019.  During the three months ended March 31, 2018, we did not have any derivative gain or loss as we did not have any derivative instruments outstanding during the period.     



Other, net for the three months ended March 31, 2019 primarily consists of $0.2 million of foreign currency losses as discussed in Note 1 to the condensed consolidated financial statements. During the three months ended March 31, 2018, we recognized a  gain on foreign currency transactions of $0.1 million.  

Income tax expense for the three months ended March 31, 2019 includes $1.8 million of deferred tax expense and a current tax provision of $1.0 million. Our effective tax rate for the three months ended March 31, 2019 is 77%. For the three months ended March 31, 2019, our overall effective tax rate was impacted by non-deductible items associated with our operations and deducting foreign taxes rather than crediting them for United States tax purposes. For the three months ended March 31, 2018, we had a current provision of $4.0 million and no amounts related to the deferred provision. The decrease in the current provision is primarily attributable to Gabon income taxes which were impacted by the decline in revenues between periods.  With respect to deferred income tax, for periods prior to the three months ended September 30, 2018, we had full valuation allowances on our net deferred tax assets, and deferred income tax was zero.  See Note 13 to the condensed consolidated financial statements for further discussion.  

Gain (loss) from discontinued operations for the three months ended March 31, 2019 and 2018 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The gain from discontinued operations for the three months ended March 31, 2019 is primarily related to recording a $5.7 million after tax gain on the finalized Angola settlement as discussed in Note 3 to the condensed consolidated financial statements.  The small loss from discontinued operations for the three months ended March 31, 2018 was related to Angola administration costs. 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

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

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. 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. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control.  As of March 31, 2019, we had net monetary assets of $3.1 million (XAF 1,822.9 million) denominated in XAF.  A 10% weakening of the CFA relative to the U.S. dollar would have a $0.3 million reduction in the value of these net assets.  For the three months ended March 31, 2019, we had expenditures of approximately $3.8 million denominated in XAF.

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.

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 may continue. Sustained low oil prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms. If oil sales were to remain constant at the most recent quarterly sales volumes of 297 MBbls, a $5 per Bbl decrease in oil price would be expected to cause a $1.5 million decrease per quarter ($6.0 million annualized) in revenues and operating income and a $0.3 million decrease per quarter ($1.4 million annualized) in net income.

During the three months ended March 31, 2019, we had oil swaps outstanding.  These instruments were intended to be an economic hedge against declines in crude oil prices; however, they were not designated as hedges for accounting purposes. 

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ITEM 4.  CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES



We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on this evaluation, the principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective due to the existence of a previously reported material weakness as of the end of the period covered by this Quarterly Report on Form 10-Q. The material weakness was identified and discussed in “Part II – Item 9A – Disclosure Controls and Procedures” of our Annual Report on Form 10-K for the year ended December 31, 2018.    



Notwithstanding the identified material weakness, management, including our principal executive officer and principal financial officer, believes the consolidated financial statements included in this Quarterly Report on Form 10-Q fairly represent in all material respects our financial condition, results of operations and cash flows at and for the periods presented in accordance with GAAP.

DESCRIPTION OF MATERIAL WEAKNESS

At December 31, 2018, management determined that the effectiveness and timeliness of the performance of the control related to the review and analysis of the impact on income taxes of significant, unusual and infrequent transactions was not operating effectively.

Management’s plan for remediation of THE material weakness

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation of condensed consolidated financial statements for external purposes.

In response to the identified material weakness at December 31, 2018, our management, with oversight from our Audit Committee, has hired an additional permanent employee with tax expertise as well as expertise in accounting for income taxes in order to remediate the material weakness described above.

Management is committed to improving our internal control processes and believes that the additional resources described above should assist in remediating the material weakness identified and strengthen internal control over financial reporting. As we continue to evaluate and improve internal control over financial reporting, additional measures to remediate the material weakness or modification to the remediation procedures described above may be necessary. We expect to complete the required remedial actions during 2019. While senior management and our Audit Committee are closely monitoring the implementation of the remediation plans, we cannot provide any assurance that the 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 existed at December 31, 2018 will continue to exist.



CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING



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 March 31, 2019 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 currently involved in are not likely to have a material adverse effect on our condensed consolidated financial position, cash flows or results of operations.

 ITEM 1A.  RISK FACTORS 

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently 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 2018 Form 10-K. There have been no material changes in our risk factors from those described in our 2018 Form 10-K other than the following:

We have less control over our investments in foreign properties than we would have with respect to domestic investments, and added risk in foreign countries may affect our foreign investments.

Our international assets and operations are subject to various political, economic and other uncertainties, including, among other things, the risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign

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exchange restrictions, changing political conditions, international monetary fluctuations, currency controls, decisions of international financial institutions such as the International Monetary Fund and the Banking Commission of Central Africa, changes in laws and regulations relating to banking institutions and deposit accounts, requirements to hold funds in government-owned banks and the risk of foreign banking institution failure, possible changes in government personnel, the development of new administrative policies, practices and political conditions that may affect the enforcement or administration of laws and regulations, adoption of new or amendments to regulatory regimes for foreign investment, uncertainties as to whether the laws and regulations will be applicable in any particular circumstance, uncertainty as to whether VAALCO will be able to demonstrate to the satisfaction of the applicable governing authorities, compliance with governmental or contractual requirements and foreign governmental regulations that favor or require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction.

For example, the Gabonese government’s oil company may seek to participate in oil and natural gas projects in a manner that could be dilutive to the interest of current license holders and the Gabonese government is under pressure from the Gabonese labor union to require companies to hire a higher percentage of Gabonese citizens. In 2016, the government of Gabon conducted an audit of our operations in Gabon, covering the years 2013 through 2014. We received the findings from this audit and responded to the audit findings in January 2017. Since providing our response, there have been changes in the Gabonese officials responsible for the audit.  We are working with the current representatives to resolve the audit findings. While we do not anticipate that we will be subject to assessments related to this audit that have significant, if any, negative impact on our reported earnings or cash flows, we can make no assurances that this will be the case. In addition, if a dispute arises with our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of the U.S.

On March 5, 2019, in accordance with certain foreign currency regulatory requirements, the Gabonese branch of the international commercial bank holding the abandonment funds in a U.S. dollar denominated account transferred the funds to the Central Bank for “CEMAC” (the Central African Economic and Monetary Community), of which Gabon is one of the six member states.  The U.S. dollars were converted to local currency with a credit back to the Gabonese branch.  Amendment 5 to the Etame PSC provides that in the event that the Gabonese bank fails for any reason to reimburse all of the principal and interest due, the Contractor shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.    See risk factor, “Our results of operations, financial conditions and cash flows could be adversely affected by changes in currency exchange rates and regulations.” 

Private ownership of oil and natural gas reserves under oil and natural gas leases in the U.S. differs distinctly from our rights in foreign reserves where the state generally retains ownership of the minerals, and in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the U.S. may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges.

Beginning in February 2018, Gabon elected to take the portion of their oil attributable to Profit Oil in-kind rather than our continuing to market their share of production on their behalf.  Gabon took their Profit Oil in-kind with the September 2018 lifting.  We anticipate that this will continue to cause fluctuations in the timing of and realized prices for oil sales.

All of our proved reserves are related to the Etame Marin block located offshore Gabon. We have operated in Gabon since 1995 and believe we have good relations with the current Gabonese government.  However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect our operations or cash flows.

Our results of operations, financial condition and cash flows could be adversely affected by changes in currency exchange rates and by currency regulations.

We are exposed to foreign currency risk from our foreign operations. While oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the 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 operating 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 recent years in response to international political conditions, general economic conditions, the European sovereign debt crisis and other factors beyond our control. Our financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk.  In addition, currency devaluation can result in a loss to us for any deposits of that currency, such as our deposits in the Etame PSC abandonment account which have been converted from U.S. dollar to Gabon local currency. See the risk factor “We have less control over our investments in foreign properties than we would have with respect to domestic investments, and added risk in foreign countries may affect our foreign investments.”  Hedging foreign currencies can be difficult, especially if the currency is not actively traded.



We are also subject to risks relating to governmental regulation of foreign currency, which may limit our ability to:

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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: May 8, 2019

 











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