UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2018



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

For the transition period from _______ to _______

Commission file number 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)





(713) 623-0801

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No   ☐ 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 October 31, 2018 there were outstanding 59,538,878 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 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 (continued)

(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 as a non-operator 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 to be expected for the full year.

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017, which includes a summary of the significant accounting policies.

Reclassifications – Certain reclassifications have been made to prior period amounts to conform to the current period presentation related to the adoption of  Accounting Standards Update (“ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”).  These reclassifications did not affect our consolidated financial results.  See Note 2 – New Accounting Standards for further information associated with ASU 2016-18.

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 September 30, 2018 and December 31, 2017 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long term amounts at September 30, 2018 and December 31, 2017 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 9.  We invest restricted and excess cash in readily redeemable money market funds.

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 “PSC”) for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in January 2016.  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 9 for further discussion. 

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.

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.  Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain.  At September 30, 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 Marin PSC was extended to at least September 16, 2028 as discussed further in Note 7.

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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 expense 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 September 30, 2018, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF 6.9 billion (XAF 2.3 billion, net to VAALCO).  The VAT receivable balance was reduced by XAF14.1 billion (XAF 4.7 billion, net to VAALCO or $4.2 million) associated with a signing bonus as part of the Sixth Amendment to the PSC executed on September 17, 2018.  See Note 7 to the financial statements for further discussion.   As of September 30, 2018, the exchange rate was XAF 565.129 = $1.00.

For the three and nine months ended September 30, 2018, we recorded a net recovery of $0.2 million and  $0.1 million, respectively, related to the allowance for bad debt for VAT for which the government of Gabon has not reimbursed us.   For the three and nine months ended September 30, 2017, we recorded an allowance of $ (0.1) million and $0.2 million, respectively.  The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and 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 rollforward of the aggregate allowance:









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 current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, liabilities for stock appreciation rights (“SARs”) and a guarantee. Derivative assets and liabilities are measured and reported at fair value using level 2 inputs each period with changes in fair value recognized in net income. SARs liabilities are measured and reported at fair value using level 3 inputs 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 during the three and nine months ended September 30, 2018 or 2017.

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As of September 30, 2018, the fair value of our SARs liability awards and derivative liability swaps of $2.1 million and $2.1 million, respectively, were included accrued liabilities.  As of September 30, 2018, the fair value of our long-term SARs of $1.0 million were include in other long-term liabilities.  As of December 31, 2017, the fair value of our SARs liability awards were included in accrued liabilities. 

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 losses on foreign currency transactions of $0.0 thousand and $0.1 million during the three and nine months ended September 30, 2018, respectively.  Within the condensed consolidated statements of operations line item “Other income (expense)—Other, net,” we recognized gains on foreign currency transactions of $0.2 million and $0.5 million during the three and nine months ended September 30, 2017, respectively.    

2.  NEW ACCOUNTING STANDARDS

Adopted

In March 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-05, “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118” (“ASU 2018-05”). ASU 2018-05 adds the Securities and Exchange Commission’s (“SEC”) guidance released on December 22, 2017 in Staff Accounting Bulletin number 118 “(SAB 118”) regarding the Tax Reform Act to the FASB Accounting Standards Codification. The Company adopted ASU 2018-05 in March 2018. The income tax effects recorded in the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2017 as well as for the three and nine months ended September 30, 2018 as a result of the Tax Reform Act are provisional in accordance with ASU 2018-05 as discussed further in Note 12.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”).   Beginning January 1, 2018, we adopted ASU No. 2014-09, and the related additional guidance provided under ASU No. 2016-10, 2016-11 and 2016-12 (together with ASU 2014-09, “Revenue Recognition ASU”). This new standard replaced most existing revenue recognition guidance in U.S. GAAP. The core principle of the Revenue Recognition ASU requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. We adopted the Revenue Recognition ASU via the modified retrospective transition method, taking advantage of the allowed practical expedient that states we are 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. This standard applies to revenues from contracts with customers.  In addition, we recognize other items from carried interest recoupment and royalties paid which are reported in revenues but are not considered to be revenues from contracts with customers.  For revenues from contracts with customers, adoption of this standard did not result in a change in the timing or amount of revenue recognized, and therefore the adoption of this standard did not have a material impact on our financial position, results of operations, debt covenants or business practices.  The adoption did result in expanded disclosures related to the nature of our sales contracts and other matters related to revenues and the accounting for revenues, which are reflected in Note 6.  In addition, we implemented new internal controls and procedures associated with revenue recognition and disclosures related to revenues.

In November 2016, the FASB issued ASU No. 2016-18, which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents.

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Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted ASU 2016-18 beginning January 1, 2018 with retroactive application to prior periods. Due to the nature of this accounting standards update, this had an impact on items reported in our statements of cash flows and related disclosures, but no impact on our financial position and results of operations.

The following tables 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:







In May 2017, the FASB issued ASU No. 2017-09, Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting (“ASU 2017-09”) to clarify when to account for a change to the terms or conditions of a share-based payment award as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments in ASU 2017-09 are effective for all entities for interim and annual reporting periods beginning after December 15, 2017.  The amendments in this update are to be applied prospectively to an award modified on or after the adoption date. The adoption of ASU 2017-09 has not had a material impact on our financial position, results of operations, cash flows and related disclosures.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The purpose of the amendment is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, the amendments in ASU 2017-01 are effective for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to acquisitions and disposals completed on or after the effective date, with no disclosures required at transition. The adoption of ASU 2017-01 has not had a material impact on our financial position, results of operations, cash flows and related disclosures.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) related to how certain cash receipts and payments are presented and classified in the statement of cash flows. These cash flow issues include debt prepayment or extinguishment costs, settlement of zero-coupon debt, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of ASU 2016-15 has not had a material impact on our financial position, results of operations, cash flows and related disclosures.

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 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 July 2018, the FASB issued ASU 2018-09, Codification Improvements (“ASU 2018-09”). ASU 2018-09 amends a variety of topics in the FASB’s Accounting Standards Codification. The transition and effective date of the guidance are based on the facts and circumstances of each amendment. Some of the amendments in ASU 2018-09 do not require transition guidance and were effective

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upon issuance of ASU 2018-09. However, many of the amendments include transition guidance with effective dates for annual periods beginning after December 15, 2018. We do not believe the adoption of ASU 2018-09 will have a material impact 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.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“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 (Topic 842): Targeted Improvements, both of which were issued in July 2018.  ASU 2016-02 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Certain aspects of lease accounting have been simplified 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 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 intend to use the prospective approach when we adopt the new standard.  Leases with terms greater than 12 months, which are currently treated as operating leases, will be capitalized. The adoption of this standard will result in the recording of a right of use asset related to certain of our operating leases with a corresponding lease liability. This will result in an increase in total assets and liabilities and a decrease in working capital.  In connection with our implementation plan, we have reviewed our lease contracts and have been evaluating other contracts to identify embedded leases to determine the appropriate accounting treatment.  We are revising our processes and procedures as well as the internal controls related to the proper accounting for leases under the new standard.







3.  DISPOSITIONS

Discontinued Operations - Angola

In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“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 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 September 30, 2018 and December 31, 2017 and its results of operations for the three and nine months ended September 30, 2018 and 2017.

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Summarized Results of Discontinued Operations



Assets and Liabilities Attributable to Discontinued Operations



Drilling Obligation

Under the 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 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of $10.0 million for each of the three exploration wells for which a drilling obligation remains unfulfilled under the terms of the PSA, of which our participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of September 30, 2018 and December 31, 2017, respectively, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA. We are currently engaged in discussions with recently appointed representatives from Sonangol E.P. regarding a possible resolution to this potential payment.



4.  SEGMENT INFORMATION

Our operations are based in Gabon and 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.

Segment activity of continuing operations for the three and nine months ended September 30, 2018 and 2017 as well as long-lived assets and segment assets at September 30, 2018 and December 31, 2017 are as follows:





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Information about our most significant customers

For the period from August of 2015 through September 2018, we sold our crude oil production from Gabon under a term contract with Glencore Energy UK Ltd. (“Glencore”) with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.  The contract with Glencore ends in January 2019. Sales of oil to Glencore were approximately 100% of total revenues for the three and nine months ended September 30, 2018 and 2017.    We expect to be able to enter into a new contract with Glencore or other third party on competitive terms prior to the expiration of the current contract.

















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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 of reported net income (loss) to net income (loss) used in calculating EPS as well as 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.  Beginning February 1, 2018 through January 31, 2019, a new COSPA was entered into with this same customer.

   

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

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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. 



Previously, we followed the sales method of accounting to account for crude oil production imbalances.  In conjunction with our adoption of Accounting Standards Codification (“ASC”) Topic 606 on January 1, 2018, we will continue to account for production imbalances as a reduction in reserves.  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 Marin block PSC.  This contract is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606.  The terms of the 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 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 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 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.  The in-kind payment related to the September lifting was $9.4 million.  As of September 30, 2018, the foreign taxes payable attributable to this obligation is $1.8 million.



Certain amounts associated with the carried interest in the Etame Marin block 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 PSC.

















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7.  OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

Extension of Term of Etame Marin Block 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 a Sixth Amendment (the “PSC Extension”) to the Etame Marin block PSC.  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 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 area of each Exclusive Exploitation Authorization 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.    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 $10.9 million being attributed to proved leasehold costs and $6.7 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 drill these wells in the second and third quarters 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 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

Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are calculated on a field basis under the unit-of-production method based upon estimates of total proved reserves.  Support equipment and leasehold improvements related to oil and natural gas producing activities, as well as property, plant and equipment unrelated to oil and natural gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically five years for office and miscellaneous equipment and five to seven years for leasehold improvements.

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 third quarter of 2018 that would cause us to believe the value of oil and natural gas producing properties should be impaired.  While there were capital expenditures during the quarter related to the signing bonus for the PSC Extension, the value of the extended exploitation period and the increase in the Cost Recovery Percentage exceeded the consideration given.  Other factors considered included the fact that the future strip prices for the third quarter of 2018 modestly increased from the second quarter of 2018, and there were no indicators that downward adjustments were needed to the 2017 year-end reserve report. 

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With respect to current reserve estimates, we estimate that reserves have increased as a result of the PSC extension and the wells planned for 2019.

There was no triggering event in the third quarter of 2017 that caused us to believe the value of oil and natural gas producing properties should be impaired.  During the third quarter of 2017, prices remained stable and we incurred no significant capital spending.  We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for all of our fields.

8.  DEBT

On May 22, 2018, we terminated an amended term loan agreement we had with the International Finance Corporation (the “IFC”) (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 termination of the Amended Term Loan Agreement.

We entered into the Amended Term Loan Agreement on June 29, 2016 through the execution of a Supplemental Agreement with the IFC which, among other things, amended and restated our existing loan agreement to convert $20.0 million of the revolving portion of the credit facility, to a term loan (the “Term Loan”) with $15.0 million outstanding at that date. The Amended Term Loan Agreement was secured by the assets of our Gabon subsidiary, VAALCO Gabon S.A. and was guaranteed by VAALCO as the parent company. The Amended Term Loan Agreement provided for quarterly principal and interest payments on the amounts outstanding, with interest accruing at a rate of LIBOR plus 5.75%.

The Amended Term Loan Agreement also provided for an additional borrowing of up to $5.0 million, which could be requested in a single draw, subject to the IFC’s approval, through March 15, 2017. On March 14, 2017, we borrowed $4.2 million under this provision of the Amended Term Loan Agreement. The additional borrowings were to be repaid in five quarterly principal installments commencing June 30, 2017, together with interest accruing at LIBOR plus 5.75%.

 

Interest 

With the execution of the Supplemental Agreement with the IFC in June 2016, beginning June 29, 2016 and continuing through March 14, 2017, commitment fees were equal to 2.3% of the undrawn term loan amount of $5.0 million. There are no further commitment fees owing after March 14, 2017.

We capitalize interest and commitment fees related to expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use.

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











9.  COMMITMENTS AND CONTINGENCIES

Drilling and other commitments  

In connection with the PSC Extension, the Etame Marin block joint owners are committed to drill two wells and two appraisal well bores by September 16, 2020.    The estimated cost for these wells is approximately $61.2 million ($20.5 million, net to VAALCO). In addition to the drilling commitment, the Etame Marin block joint owners are required to pay $5.0 million ($1.7 million, net to VAALCO) in cash to the government of Gabon following the end of the drilling activities for the two wells.   As the payment is not contingent on the success of these wells and at least $5.0 million would be paid if no wells are drilled, we have accrued a liability for our net $1.7 million share as of September 30, 2018.  The joint owners are also obligated to perform two technical studies estimated to

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cost $1.3 million ($0.4 million, net to VAALCO).  The costs related to these studies will be recognized in future periods when the studies are performed.

Abandonment funding

As part of securing the first of two five-year extensions to the Etame field production license to which we are entitled from the government of Gabon, we agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. The agreement was finalized in the first quarter of 2014 (effective 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 $61.1 million ($19.0 million net to VAALCO) on an undiscounted basis. Through September 30, 2018,  $34.8 million ($10.8 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 to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.   

FPSO charter 

In connection with the charter of the FPSO, we, as operator of the Etame Marin block, guaranteed all of the lease payments under the charter through its contract term, which expires in September 2020. At our election, the charter may be extended for two one-year periods beyond September 2020. We obtained guarantees from each of the 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 $0.4 million as of  September 30, 2018 and $0.5 million as of December 31, 2017 representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO lease has $61.8 million and $85.2 million in remaining gross minimum obligations as of September 30, 2018 and December 31, 2017, respectively.

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 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.

In 2017, the government of Gabon conducted a tax audit of our Gabon subsidiary covering the years 2013 through 2016, and in December 2017, we received a report on their findings.  In April 2018, we reached a final settlement of the audit resulting in a payment for taxes of $0.2 million and penalties of $0.2 million, net to VAALCO.  At December 31, 2017, we had an accrual of $0.5 million, net to VAALCO, for the estimated additional taxes along with penalties in the “Accrued liabilities and other” line item of our consolidated balance sheets.

At September 30, 2018 and December 31, 2017, 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 a customs audit. 

10.  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.

Commodity Swaps - In June 2018, we entered into commodity swaps at a Dated Brent weighted average of $74 per barrel for the period from and including June 2018 through June 2019 for a quantity of approximately 400,000 barrels.  If a liability position 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. These swaps settle on a monthly basis.  At September 30, 2018, our unexpired commodity swaps were for an underlying quantity of 285,000 barrels and had a fair value liability position of $2.1 million reflected in “Accrued liabilities and other” line of our condensed consolidated balance sheet.

Put options - During 2016, we executed crude oil put contracts as market conditions allowed in order to economically hedge anticipated 2016 and 2017 cash flows from crude oil producing activities.  At December 31, 2017, our crude oil put contracts expired. 

While these commodity swaps and crude oil puts are intended to be an economic hedge to mitigate the impact of a decline in oil prices, we have not elected hedge accounting. The contracts 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.

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

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settlements on commodity derivatives are presented in the “Other, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations. 



















11.  STOCK-BASED COMPENSATION



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 September 30, 2018,  1,112,527 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 compensation expense related to stock-based compensation as general and administrative expense.  For the three months ended September 30, 2018 and 2017, stock-based compensation was $1.1 million and $0.2 million, respectively, related to the issuance of stock options, restricted stock and SARs.  For the nine months ended September 30, 2018 and 2017, stock-based compensation was $3.8 million and $0.9 million, respectively, related to the issuance of stock options, restricted stock and SARs. 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 $0.5 million and $38 thousand in cash proceeds from the exercise of stock options in the nine months ended September 30, 2018 and 2017, respectively.  During the nine months ended September 30, 2018, options for 494,941 shares were granted 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 and have an exercise price of $0.86 per share.  During the nine months ended September 30, 2018, options for 175,644 shares were granted to directors; these options vested immediately on the date of grant and have an exercise price of $1.60 per share.

Stock option activity for the nine months ended September 30, 2018 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 first three anniversaries following the date of the grant. Share grants to directors vest immediately and are not restricted.   During the nine months ended September 30, 2018, the Company issued 323,474 shares of service based restricted stock to employees with a grant date fair value of $0.86 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 from the date of the grant.  The following is a summary of activity in unvested restricted stock in the nine months ended September 30, 2018.  During

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the nine months ended September 30, 2018, restricted stock for 75,000 shares were granted to directors; these shares vested immediately on the date of grant and had a grant date fair value of $1.60 per share.

During the three and nine months ended September 30, 2018,  8,117 shares were added to treasury as a result of tax withholding on vestings of restricted shares.  During the three and nine months ended September 30, 2017,  9,117 shares were added to treasury as a result of tax withholding on vestings of restricted shares.

Stock appreciation rights

SARs are granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR price per share specified in a SAR award on the date of grant (which may not be less than the fair market value of our common stock on the date of grant) and the fair market value per share on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of our Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of our Board of Directors.

During the nine months ended September 30, 2018,  2,373,411 SARs were granted to employees which vest over a three-year period with a life of 5 years and have a $0.86 SAR price per share specified in a SAR award on the date of grant.  With respect to SARs granted in 2017, one-third of the SARs are to vest on or after the first anniversary of the grant date at such time when the market price per share of our common stock exceeds $1.30; one-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds $1.50; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds $1.75.   The vesting requirements for two-thirds of the SARs granted in 2017 have been met. 

SAR activity for the nine months ended September 30, 2018 is provided below:















12. INCOME TAXES

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

On December 22, 2017, the United States government enacted the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act includes significant changes to the U.S. income tax system including but not limited to: a federal corporate rate reduction from 35% to 21%; limitations on the deductibility of interest expense and executive compensation; repeal of the Alternative Minimum Tax (“AMT”); full expensing provisions related to business assets; creation of new minimum taxes such as the base erosion anti-abuse tax (“BEAT”) and Global Intangible Low Taxed Income (“GILTI”) tax; and the transition of U.S. international taxation from a worldwide tax system to a modified territorial tax system, which will result in a one time U.S. tax liability on those earnings which have not previously been repatriated to the U.S. (the “Transition Tax”).  The provisional impacts of this legislation are outlined below:

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Other provisions in the legislation, such as interest deductibility and changes to executive compensation plans are not expected to have material implications to the Company’s financial statements.  The income tax effects recorded in the Company’s financial statements as a result of the Tax Reform Act are provisional in accordance with ASU 2018-05 as the Company has not yet completed its evaluation of the impact of the new law. ASU 2018-05 allows for a measurement period of up to one year after the enactment date of the Tax Reform Act to finalize the recording of the related tax impacts. The Company does not believe potential adjustments in future periods would materially impact the Company’s financial condition or results of operations. 

Additionally, the Tax Reform Act may further limit the Company’s ability to utilize foreign tax credits in the future. The Tax Reform Act introduces a new credit limitation basket for foreign branch income. Income from foreign branches would now be allocated to this specific tax credit limitation basket which cannot offset income in other baskets of foreign income. Under the Tax Reform Act, foreign taxes imposed on the foreign branch profits will not offset U.S. non-branch related foreign source income. Additional guidance is needed to determine how this will impact the Company and any future utilization of foreign tax credit carryforwards.

Income taxes attributable to continuing operations for the three months ended September 30, 2018 and 2017 are attributable to foreign taxes payable in Gabon.  The Company has not recorded any measurement period adjustments under ASU 2018-05 during the three and nine months ended September 30, 2018.    

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



As of December 31, 2017, the Company had deferred tax assets of $154.5 million primarily attributable to U.S. federal taxes related to basis differences in fixed assets, foreign tax credit carryforwards, and net operating loss carryforwards as well as foreign net operating losses for foreign jurisdictions.  Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. As of December 31, 2017, the Company was in a cumulative three year pre-tax loss position for both the U.S. and Gabon jurisdictions.  As of December 31, 2017, we did not anticipate utilization of the foreign tax credits prior to expiration nor did we expect to generate sufficient taxable income to utilize other deferred tax assets. On the basis of this evaluation, valuation allowances of $153.2 million were recorded as of December 31, 2017. Valuation allowances reduce the deferred tax assets to the amount that is more likely than not to be realized. 

Taxes paid in Gabon with respect to earnings from the Etame Marin block are determined under the provisions of the Etame Marin PSC.  In accordance with the Etame Marin PSC, the consortium maintains a “Cost Account” which accumulates capital costs and

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operating expenses (“Recoverable Costs”) that are deductible against revenues, net of royalties, in determining taxable profits.  For each calendar year, the consortium is entitled to receive a percentage of the production (“Cost Recovery Percentage”) remaining after deducting royalties so long as there are amounts remaining in the Cost Account. Prior to the PSC Extension, the Cost Recovery Percentage was 70%.  As a result of the PSC Extension, the Cost Recovery Percentage has been increased to 80% for the period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%.  The difference between revenues, net of royalties, and the costs recovered for the period is “Profit Oil.” As payment of corporate income taxes, the consortium pays the government an allocation of the remaining Profit Oil production from the contract area ranging from 50% to 60%.  The percentage of Profit Oil paid to the government as tax is a function of production rates. When the Cost Account is less than the entitled recovery percentage (either 70% or 80%, depending on the period), Profit Oil as a percentage of revenues increases and Gabon taxes paid increase as a percentage of revenues.  At December 31, 2017, there was $97.6 million remaining in the portion of the Cost Account associated with our interest.

Prior to the PSC Extension, the Cost Recovery Percentage was 70%, and the exploitation periods ended beginning in June 2021.  Future proved reserves did not extend beyond 2021.  Opportunities for increasing reserves by drilling wells were limited, and while oil prices had improved since 2016, they were not at the levels needed to recover VAALCO’s Cost Account.  As a result of these factors, the ability to recognize the benefit from the potential deferred tax asset related to the difference between VAALCO’s Cost Account and the book basis of the Etame Marin block assets was deemed to be remote, and the deferred tax asset was not recognized.  As a result of the PSC Extension during the three months ended September 30, 2018, the Cost Recovery Percentage increased to 80% and the exploitation periods were extended to at least September 16, 2028, and if the two five-year option periods are elected the period would extend to September 16, 2038.  In addition to the benefits under the PSC Extension, we expect higher future oil prices based on current Brent futures strip pricing over the next few years and we expect future production from the planned drilling of two to three wells in 2019.  Given these factors, we determined that the potential for a recovery of our Cost Account was no longer remote, and therefore we recorded a deferred tax asset of $46.5 million related to the excess of the Cost Account over the book basis of the Etame Marin block assets.  In addition, as a result of recording the deferred tax asset of $46.5 million related to our Cost Account, we recorded the corresponding deferred tax liability of $9.8 million attributable to the U.S. federal income tax impact.

We also evaluated the amount of the valuation allowance needed related to deferred tax assets recognized related to U.S. federal  income taxes.  In making this evaluation, we considered the impact on future taxable income of increased earnings as a result of the PSC Extension as well as increases in oil prices during the year, including current oil prices as well as Brent futures strip pricing over the next few years and the future production from the planned drilling of two to three wells in 2019.  We also considered the pattern of earnings over the past three years.  On the basis of these factors, we determined that it is more likely than not that we will realize a portion of the benefit from the deferred tax assets related to the fixed asset basis differences as well as the net operating losses.  Accordingly, we reversed $29.9 million of the valuation allowance recorded in prior periods.     

As a result of the 2017 tax legislation enacted in the U.S., we expect to realize the benefit from our AMT credit carryforwards.  The valuation allowance recorded related to AMT credits in previous periods was reversed in 2017 with the exception for a reserve for the possible sequestration of the credits.  The $1.3 million reversal was recorded as a deferred income tax benefit during the fourth quarter of 2017. 

The Company recognizes the financial statement benefit of a tax position only after determining that they are more likely than not to sustain the position following an audit.  The Company believes that its income tax positions and deductions will be sustained on audit and therefore no reserves for uncertain tax positions have been established.  Accordingly, no interest or penalties have been accrued as of December 31, 2017 and 2016.  The Company’s policy is to include 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, and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, taxes, the amount and nature of capital expenditures and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” “probably” or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

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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, 2017 (“2017 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-looking statements which are included in this report and the 2017 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 as a non-operator 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.

A significant component of our results of operations is dependent upon the difference between prices received for our offshore Gabon oil production and the costs to find and produce such oil. Oil and natural gas prices have been volatile and subject to fluctuations based on a number of factors beyond our control.  Current prices are significantly higher than those in early 2016.  A decline in oil and natural gas prices and a sustained period of low oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms.

CURRENT DEVELOPMENTS 

During 2017 and the first three quarters of 2018, the global oil supply and demand were close to being balanced; however, no assurances can be made that this trend will continue. ICE Dated Brent crude oil prices fluctuated between $44 and $67 per barrel (“Bbl”) from January 2017 through December 2017.  During the nine months ended September 30, 2018, ICE Dated Brent crude oil prices have fluctuated between $62 and $83 per Bbl. 

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 termination of the Amended Term Loan Agreement. 

On September 17, 2018, the Sixth Amendment (“PSC Extension”) to the Exploration and Production Sharing Contract entitled “Etame Marin No. G4-160”, dated as of July 7, 1995, (“PSC”) providing for the extension of our three Exclusive Exploitation Authorizations for the Etame Marin block through September 16, 2028, with the right for two additional five-year extension periods, was executed.  See “PSC Extension” below for further information. 

As of the third quarter of 2018, we are preparing for a drilling program for the second and third quarters of 2019 on the Etame Marin block which will include two to three wells and two appraisal well bores.

ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

PSC Extension

As described further in Note 7, on September 25, 2018, the consortium received an implementing Presidential Decree from the government of Gabon authorizing the PSC Extension.  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 period for the three Exclusive Exploitation Authorizations for a period of ten years from September 17, 2018, the effective date of the PSC Extension.  Prior to the PSC Extension, the exploitation periods for the three exploitation areas in the Etame Marin block expired beginning in June 2021.  The PSC Extension also grants the consortium the right for two additional

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extension periods of five years each.  The PSC Extension further allows the consortium to explore the potential for resources in the three exploitation areas 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 $25.0 million ($8.4 million, net to VAALCO) was paid 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 for our $1.7 million share of the $5.0 million 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. 

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.  The consortium is planning to drill these wells in the second and third quarters 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 to recover its costs (“Cost Recovery Percentage”) so long as there are amounts remaining in the Cost Account.  Under the PSC Extension, the Cost Recovery Percentage was 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%.  

Development and Production

We operate the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of the consortium. As of September 30, 2018, 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 floating, production, storage and offloading vessel (“FPSO”) anchored to the seabed on the block. The FPSO has production limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day.  During the nine months ended September 30, 2018 and 2017, production from the block was approximately 3,804 MBbls (1,027 MBbls net) and 4,268 MBbls (1,154 MBbls net), respectively.

In October 2017 we began workover operations to replace failed electrical submersible pumps (“ESPs”) in the South Tchibala 1-HB and South Tchibala 2-H wells.  While production from the South Tchibala 1-HB well was not restored, the workover operation on the South Tchibala 2-H well was successfully completed in November 2017.  Following demobilization of the workover unit in late 2017, the Avouma 2-H well experienced an ESP failure.  In May 2018 we mobilized a hydraulic workover unit to the Avouma platform to replace the ESP systems in the Avouma 2-H and the South Tchibala 1-HB wells and restored production to both wells in June 2018. While the hydraulic workover unit was on location, we decided to pro-actively replace the ESPs in the South Tchibala 2-H well to upgrade the systems to those just installed in the other two wells.  Excluding the Avouma platform wells, the wells with ESPs on our three other platforms have operated without incident for up to four years.  As a result of these workover operations approximately 1,100 BOPD of net production has been restored. 

As discussed above, the PSC Extension requires the consortium to drill two wells and two appraisal well bores by September 16, 2020. We are planning to drill these wells and a possible third well during the second and third quarters of 2019. 

Equatorial Guinea

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”).  The Block P interest is currently in suspension, and we are working with the Ministry of Mines and Hydrocarbons to lift the suspension by the end of 2018.  We and our joint 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.  Preparation for these activities could begin as early as 2019.  Expenditures related to such activities are not expected to be significant in 2019.    Our 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.  We are in continued discussions with the Ministry of Mines and Hydrocarbons regarding these plans. 

Discontinued Operations - Angola

In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“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 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.

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Drilling Obligation

Under the 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 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of $10.0 million for each exploration well for which a drilling obligation remains under the terms of the PSA, of which our participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of September 30, 2018 and December 31, 2017, which represents what we believe to be the maximum potential amount attributable to our interest under the PSA.  We are currently engaged in discussions with recently appointed representatives from Sonangol E.P. regarding this potential payment and other possible solutions and believe that the ultimate amount paid will be less than the accrued amount

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the nine months ended September 30, 2018 and 2017 are as follows:



The increase in net cash provided by our operating activities for the nine months ended September 30, 2018 compared to the same period of 2017 includes a $16.1 million increase in cash generated by continuing operations before change in operating assets and liabilities which in large part was the result of higher 2018 crude oil prices partially offset by higher operating costs and expenses.  Net cash provided by our operating assets and liabilities increased by $13.5 million compared to same period of 2017.  The net change in operating assets and liabilities of $6.7 million for the nine months ended September 30, 2018 included $8.0 million in payments made by joint venture owners, a $1.8 million increase in foreign taxes payable, a $3.6 million decrease in trade receivables and a $1.0 million decrease in crude oil inventory offset by payments made in “Accounts payable” of $4.3 million and a reduction in “Accrued liabilities and other” of $1.0 million.  The net change in operating assets and liabilities of $ (6.8) million for the nine months ended September 30, 2017 included a pay down of “Accounts payable” and “Accrued liabilities and other” of $5.7 million and an increase in VAT receivable of $2.8 million partially offset by a reduction in prepayments and other of $1.6 million.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. During the nine months ended September 30, 2018, these expenditures on a cash basis were $13.2 million, primarily related to the $11.8 million signing bonus paid in connection with  the PSC Extension and $1.4 million paid for equipment and other property. This compares to  $1.3 million in property and equipment expenditures included in capital expenditures for the nine months ended September 30, 2017. See “Capital Expenditures” below for further discussion. 

Net cash used in financing activities during the nine months ended September 30, 2018 included $9.2 million in principal payments on debt which was extinguished in May 2018. Net cash used in financing activities during the nine months ended September 30, 2017 included principal payments of $7.9 million offset by borrowings of $4.2 million.

Capital Expenditures

During the nine months ended September 30, 2018, we made accrual basis capital expenditures of $19.0 million which includes $17.6 million attributable to the PSC Extension signing bonus.  The remaining $1.4 million is primarily related to equipment and other.  At September 30, 2018, pursuant to the PSC Extension, we had 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 and third quarters of 2019.  The third well is subject to

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approval by the joint venture owners and the government of Gabon.  We expect any capital expenditures made during the remainder of 2018 and during 2019 will be funded by cash on hand and cash flow from operations.

Contractual Obligations

We have an agreed cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. Based upon the abandonment study completed in January 2016, the abandonment cost estimate used for this purpose is approximately $61.1 million ($19.0 million net to VAALCO) on an undiscounted basis. The obligation for abandonment of the Gabon offshore facilities is included in the “Asset retirement obligations” line item on our condensed consolidated balance sheets. Through September 30, 2018, $34.8 million ($10.8 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of our condensed consolidated balance sheet. The next funding is expected to be $7.4 million ($2.3 million net to VAALCO) and to be paid in December 2018; however, future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments. 

In connection with the PSC Extension, the consortium is committed to drill two wells and two appraisal well bores by September 16, 2020.  The estimated cost for these wells is approximately $61.2 million ($20.5 million, net to VAALCO).  In addition to the drilling commitment, the consortium is required to pay $5.0 million ($1.7 million, net to VAALCO) in cash to the government of Gabon following the end of these drilling activities. We have accrued for our $1.7 million share of this obligation as of September 30, 2018.  See Activities by Asset – Gabon from above for further discussion.    

Under the 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 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The 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 PSA, of which our participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of September 30, 2018 and December 31, 2017, which represents what we believe to be the maximum potential amount attributable to our interest under the PSA.  We are currently engaged in discussions with recently appointed representatives from Sonangol E.P. regarding this potential payment and other possible solutions and believe that the ultimate amount paid will be less than the accrued amount.

Except for the obligations under the PSC Extension, the early extinguishment of the Term Loan (defined below) with the International Finance Corporation (the “IFC”) and entering into the commodity swap contracts, there have been no significant changes to our commitments and contractual obligations subsequent to December 31, 2017.

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.

As of September 30, 2018, we had accrued $1.3 million net to VAALCO in “Accrued liabilities and other” on our condensed consolidated balance sheet for these various audits by governmental agencies in Gabon.  See Note 9 to the financial statements for further discussion.    

Commodity Price Hedging

The price we receive for our oil significantly influences our revenue, profitability, liquidity, access to capital and prospects for future growth.  Oil commodities and, therefore their prices can be subject to wide fluctuations in response to relatively minor changes in supply and demand. We believe these prices will likely continue to be volatile in the future. 

Due to the inherent volatility in oil and natural gas prices, we use commodity derivative instruments such as swaps to hedge price risk associated with a significant portion of our anticipated oil, natural gas and NGL production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in oil and natural gas prices and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. The counterparty to our derivative transactions is a major oil company’s trading subsidiary, and our derivative positions are generally reviewed on a monthly basis. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in net income. We record such derivative instruments as assets or liabilities in the condensed consolidated balance sheet. We do not anticipate any substantial changes in our hedging policy.

For the period from October 2018 to June 30, 2019 we have commodity swap contracts for approximately 285,000 barrels of oil.  As of September 30, 2018, the estimated mark-to-market value of our commodity price swaps in 2018 and 2019 was a liability of $2.1 million, which is recorded on the “Accrued liabilities and other” line item on our condensed consolidated balance sheet. 

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Capital Resources

Credit Facility 

On June 29, 2016, we executed a Supplemental Agreement with the IFC which, among other things, amended and restated our existing loan agreement to convert $20.0 million of the revolving portion of the credit facility, to a term loan (the “Term Loan”) with $15.0 million outstanding at that date.  Historically, our primary sources of capital have been cash flows from operating activities, borrowings under the Term Loan 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.  The Company did not incur any termination or prepayment penalties as a result of the termination of the amended term loan agreement. 

Cash on Hand

At September 30, 2018, we had unrestricted cash of $33.7 million.    The unrestricted cash balance included $5.5 million of cash attributable to non-operating joint venture owner advances.    As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, we enter into project related activities on behalf of the working interest owners. We generally obtain advances from 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 ends in January 2019. We expect to be able to extend the contract or enter into a new contract on comparable terms.  Pricing under the current 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 and natural gas. Our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and natural gas prices. 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 which has had a favorable impact on our access to capital markets.  However, the availability of capital resources on attractive terms may be impacted by the geographic location of our primary producing assets. As discussed above, we are planning to drill two or three wells and two appraisal well bores during the second and third quarters of 2019.  Drilling of the third well would require approval of the joint venture owners and the government of Gabon.  We expect any capital expenditures made during the remainder of 2018 and during 2019 will be primarily funded by cash on hand, cash flow from operations and, if necessary, cash raised from debt and/or equity issuances.  We believe that at current prices, cash generated from continuing operations together with cash on hand at September 30, 2018 are adequate to support our operations and cash requirements during 2018 and through December 31, 2019.

All of our proved reserves are related to the Etame Marin block offshore Gabon.  As a result of the PSC Extension, the current term for exploitation of the reserves in the Etame Marin block ends in September 2028 with two options to extend the period for an additional five years each.  The PSC Extension as well as a successful drilling program in 2019 could favorably improve our long-term liquidity. 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 our 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.

OFF-BALANCE SHEET ARRANGEMENTS

In connection with the charter of the FPSO (see “— Activities by Asset — Gabon — Offshore-Etame Marin Block”), we, as operator of the Etame Marin block, guaranteed all of the lease payments under the charter through its contract term, which expires in September 2020. At our election, the charter may be extended for two one-year periods beyond September 2020. We obtained guarantees from each of 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 $0.4 million as of September 30, 2018 and $0.5 million as of December 31, 2017 representing the guarantee’s fair value. The guarantee of the offshore Gabon FPSO lease has $61.8 million in remaining gross minimum obligations for the total amount of charter payments at September 30, 2018. There have been no other material off-balance sheet arrangements entered into since December 31, 2017.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We have added “Income Taxes” as discussed below to our critical accounting policies and estimates.  There have been no other significant changes to our critical accounting policies subsequent to December 31, 2017.

Income Taxes

Our annual 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 annual 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.

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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 carryovers. As of December 31, 2017, the Company had deferred tax assets of $154.5 million primarily attributable to U.S. federal taxes related to basis differences in fixed assets, foreign tax credit carryforwards, and net operating loss carryforwards as well as foreign net operating losses for foreign jurisdictions for which a valuation allowance of $153.2 million had been recorded.  During the three months ended September 30, 2018, management determined that it was more-likely-than-not that a portion of the deferred tax assets related to basis differences in fixed assets and net operating loss carryforwards would be realized, and therefore $29.9 million of the valuation allowance recorded in prior periods was reversed.

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.  As of December 31, 2017, we had not recognized deferred tax assets related to our Cost Account in the Gabon jurisdiction.  As discussed in Note 12 to the condensed consolidated financial statements, as a result of the benefits under the PSC Extension which was granted during the three months ended September 30, 2018, we determined that it was now more-likely-than-not we would recover our Cost Account, and therefore we recorded a deferred tax asset of $46.5 million related to the excess of the Cost Account over the book basis of the Etame Marin block assets. 

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

We reported net income for the three months ended September 30, 2018 of $78.6 million compared to net loss of $0.3 million for the same period of 2017. The net income for the three months ended September 30, 2018 is inclusive of the loss from discontinued operations for the same period of $21 thousand. The net loss for the three months ended September 30, 2017 was inclusive of the loss from discontinued operations for the same period of $0.2 million. Significantly all of our operations are attributable to our Gabon segment.   Further discussion of results by significant line item follows.

Oil and natural gas revenues increased $7.1 million, or approximately 39.0%, during the three months ended September 30, 2018 compared to the same period of 2017. The increase in revenue is primarily attributable to higher realized oil prices due to increases in the Dated Brent market partially offset by lower sales volumes.

The revenue changes in the three months ended September 30, 2018 compared to the three months ended September 30, 2017, 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 both of the third quarters of 2018 and

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2017.  Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 99,400 and 42,000 barrels at September 30, 2018 and 2017, respectively.  The sales volumes were lower in the three months ended September 30, 2018 as the volumes lifted by the government of Gabon in September were less than the volumes available to be lifted and lower than the normal monthly lifting volumes.     

Production expenses decreased $2.9 million, or approximately 27.6%, in the three months ended September 30, 2018 compared to the same period of 2017.  The third quarter 2018 costs were lower as a result of revised estimates of contractual obligation costs.  In addition, the decrease in expense between quarters was also impacted by a planned maintenance turnaround and asset integrity work that occurred in third quarter 2017.    

Depreciation, depletion and amortization (“DD&A”) costs decreased due to the favorable impact of depleting our costs over a higher reserve bases as a result of improvements in estimated reserves identified at December 31, 2017. 

Gain on revision of asset retirement obligations for the three months ended September 30, 2018 resulted from the downward revisions of $6.5 million to the liability for asset retirement obligations which exceeded the net book value of the related assets by $3.3 million.  

General and administrative expenses increased $0.3 million, or approximately 14.1% in the three months ended September 30, 2018 compared to the same period of 2017.  Stock-based compensation expense increased by $0.8 million during the three months ended September 30, 2018 as compared to comparable 2017 period.  This increase was primarily related to SARs.  The increase was offset by lower corporate personnel costs.   

Bad debt expense (recovery) and other -  Recoveries increased for the three months ended September 30, 2018 and 2017 primarily as a result of bad debt recovery related to VAT as a result of payments received during the quarter.    

Other operating loss, net for three months ended September 30, 2018 increased compared to the same period in 2017 related to a change in inventory obsolescence.

Interest income (expense) for the three months ended September 30, 2018 primarily relates to interest earned on the investment of excess cash.  For the three months ended September 30, 2017, we had interest expense which primarily relates to our term loan with the IFC (see Note 8 to the condensed consolidated financial statements) and to interest on taxes other than income taxes.  On May 22, 2018, we terminated the Amended Term Loan Agreement by prepaying the outstanding principle and accrued interest.     

Other, net for the three months ended September 30, 2018 increased $0.2 million as compared to the same period in 2017 related primarily to derivative losses as discussed in Note 10 to the condensed consolidated financial statements and by foreign currency losses in the 2018 and 2017 periods.

Income tax expense (benefit) for the three months ended September 30, 2018 includes a $66.6 million deferred tax benefit related to the recognition of deferred tax assets and the reversal of valuation allowances on deferred tax assets as discussed in Note 12 to the condensed consolidated financial statements.  There were no amounts related to deferred taxes in the comparable prior year period.  In addition to the deferred tax benefit, we had a current tax provision of $4.0 million during the three months ended September 30, 2018 which compares to a current tax provision of $2.7 million for the comparable prior year period.  The current tax provision in both periods is primarily attributable to our operations in Gabon and is higher in 2018 than income tax for the comparable 2017 period as a result of higher revenues.

Loss from discontinued operations for the three months ended September 30, 2018 and 2017 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The losses from discontinued operations for the three months ended September 30, 2018 and 2017 were primarily related to ongoing administration costs. 

Nine months ended September 30, 2018 compared to the nine months ended September 30, 2017

We reported net income for the nine months ended September 30, 2018 of $87.8 million, compared to a net income of $6.2 million for the same period of 2017. These amounts were inclusive of our loss from discontinued operations for the nine months ended September 30, 2018 of $0.4 million, and loss from discontinued operations for the nine months ended September 30, 2017 of $0.5 million. Further discussion of results by significant line item follows.

Oil and natural gas revenues increased $17.5 million, or approximately 29.2%, during the nine months ended September 30, 2018 compared to the same period of 2017. Based on the average realized oil prices in the table below, a substantial portion of the increase in revenue is related to realized oil prices, which are due to increases in the Dated Brent market price.

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The revenue changes in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 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 ten liftings for the nine months ended September 30, 2018 as compared to nine liftings for the nine months ended September 30, 2017.  Although there were more liftings during the period, the size of the liftings was less because the volumes lifted by the government of Gabon in September were less than the volumes available to be lifted and lower than the normal monthly lifting volumes and due to lower production during the period.  Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 99,400 and 42,000 barrels at September 30, 2018 and 2017, respectively.

Production expenses increased $3.1 million, or approximately 11.0%, in the nine months ended September 30, 2018 compared to the same period of 2017,  primarily as a result of $4.7 million for workovers performed during the nine months ended September 30, 2018 on three Avouma field wells as well as increases in fuel costs offset by lower customs fees. 

Depreciation, depletion and amortization (“DD&A”) decreased $2.3 million, or approximately 40.6%, in the nine months ended September 30, 2018 compared to the same period of 2017  due to the favorable impact of depleting our costs over a higher reserve base as a result of improvements in estimated reserves identified at December 31, 2017 as well as lower sales volumes.    

Gain on revision of asset retirement obligations for the nine months ended September 30, 2018 resulted from the downward revisions of $6.5 million to the liability for asset retirement obligations which exceeded the net book value of the related assets by $3.3 million.  

General and administrative expenses increased $1.8 million, or approximately 20.4% in the nine months ended September 30, 2018 compared to the same period of 2017. Stock-based compensation expense increased by $2.8 million during the nine months ended September 30, 2018 as compared to comparable 2017 period.  This increase was primarily related to SARs.  Corporate personnel costs, professional services, computer and office equipment and other taxes were lower in 2018 compared to the 2017 period.

Bad debt expense (recovery) and other decreased for the nine months ended September 30, 2018 and 2017 primarily as a result of bad debt recovery related to VAT as a result of payments received during the period.

Other operating income, net for the nine months ended September 30, 2018 increased $0.2 million as compared to the same period in 2017 related to a change in inventory obsolescence.

Interest income (expense) for the nine months ended September 30, 2017 relates to our term loan with the IFC as discussed in Note 8 to the condensed consolidated financial statements and to interest on taxes other than income taxes.  On May 22, 2018, we terminated the Amended Term Loan Agreement by prepaying the outstanding principle and accrued interest. The nine months ended September 30, 2018 includes interest expense related to the IFC loan prior to the May 2018 prepayment offset by interest income on the investment of excess cash.      

Other, net for the nine months ended September 30, 2018 and 2017 consists primarily of derivative instrument losses in both 2018 and 2017 as well as foreign currency losses in 2018 and foreign currency gains in 2017.

Income tax expense (benefit) for the nine months ended September 30, 2018 includes a $66.6 million deferred tax benefit related to the recognition of deferred tax assets and the reversal of valuation allowances on deferred tax assets as discussed in Note 12 to the condensed consolidated financial statements.  There were no amounts related to deferred taxes in the comparable prior year period.  In addition to the deferred tax benefit, we had a current tax provision of $11.6 million during the nine months ended September 30, 2018 which compares to a current tax provision of $9.0 million for the comparable prior year period.  The current tax provision in both periods is primarily attributable to our operations in Gabon and is higher in 2018 than income tax for the comparable 2017 period as a result of higher revenues. 

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Loss from discontinued operations for the nine months ended September 30, 2018 and 2017 are attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The small losses from these discontinued operations for the 2018 and 2017 periods are primarily related to ongoing administrative 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 foreign exchange rates, commodity prices and counterparty risk 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 in Gabon is 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.

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. Current prices are significantly higher than those in early 2016. A decline in oil and natural gas prices and a sustained period of low oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and 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 329 MBbls, a $5 per Bbl decrease in oil price would be expected to cause a $1.6 million decrease per quarter ($6.4 million annualized) in revenues and operating income and a $1.4 million decrease per quarter ($5.4 million annualized) in net income.  We engage in commodity swaps and crude oil puts as an economic hedge to mitigate the impact of a decline in oil prices. See Note 10 to the condensed consolidated financial statements.

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 credit worthy financial institutions or major oil companies deemed by management as competent and competitive market makers. 

ITEM 4.  CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES



We have established disclosure controls and procedures designed to ensure that the disclosure requirement in the reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and effectively communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

  

Management of the Company, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act). Based on their evaluation as of September 30, 2018, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at such time.

 

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING



There were no changes in our internal control over financial reporting that occurred during the three months ended September 30, 2018 that have materially affected, or are 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 consolidated financial position, cash flows or results of operations.

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 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.

We could incur substantial penalties for not fulfilling our work commitment under the terms of the PSC Extension. 

We are required within a period of two years from September 17, 2018, to drill two wells and two appraisal well bores and commit to pay an estimated $61.2 million ($20.5 million net to VAALCO) for this work commitment.  If we are unable to do so, we will be required to pay within thirty days of the expiration date of such period, an indemnity equal to the cost of works not carried out, as required with the work commitment. 

Commodity derivatives transactions we enter into may fail to protect us from declines in commodity prices.

In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into derivatives arrangements with respect to a portion of our expected production. Our derivative contracts consist of a series of commodity swap contracts and are limited in duration. Our derivatives program may be inadequate to protect us from significant and prolonged declines in the price of crude oil.

The distressed financial conditions of one or more hedge providers could have an adverse impact on us in the event these hedge providers are unable to pay us amounts owed to us under one or more financial hedge transactions by which we have hedged our exposure to commodity price volatility.

From time to time, we may enter into financial hedge transactions to hedge or mitigate our exposure to the risks of commodity price volatility with respect to the crude oil or natural gas we produce and sell.  In such instances, the hedge provider will be obligated to make payments to us under such financial hedge transactions to the extent that the floating (market) price is below an agreed fixed (strike) price. Hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations. This risk of counterparty performance is of particular concern given the disruptions that have occurred in the financial markets that led to sudden changes in counterparty’s liquidity and hence their ability to perform under their hedging contracts with us. We are unable to predict sudden changes in counterparty’s creditworthiness or ability to perform.  Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

For further discussion of our potential risks and uncertainties, see the information in Item 1A “Risk Factors” in our 2017 Form 10-K. There have been no material changes in our risk factors from those described in our 2017 Form 10-K.

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ITEM 6.  EXHIBITS

(a) Exhibits 

(a)  Filed herewith

(b)  Furnished herewith

 

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SIGNATURE

In accordance with the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VAALCO ENERGY, INC.

(Registrant)

 



Dated: November 7, 2018

 













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