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: