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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________

FORM 10-Q

________________________________

(Mark One)

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

For the quarterly period ended September 30, 2020

¨ 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)

________________________________

Delaware |  | 76-0274813
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
9800 Richmond Avenue Suite 700 Houston, Texas |  | 77042
(Address of principal executive offices) |  | (Zip code)

(713) 623-0801

(Registrant’s telephone number, including area code)

________________________________

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

Title of each class | Trading symbol(s) | Name of each exchange on which registered
Common Stock | EGY | New York Stock Exchange
Common Stock | EGY | London Stock Exchange

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x 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.

Large accelerated filer | ¨ |  | Accelerated filer | x
Non-accelerated filer | ¨ | (Do not check if a smaller reporting company) | Smaller reporting company Emerging growth company | x ¨

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 x

As of October 30, 2020, there were outstanding 57,456,139 shares of common stock, $0.10 par value per share, of the registrant.

Table of Contents

VAA LCO ENERGY, INC. AND SUBSIDIARIES

Table of Contents

PART I. FINANCIAL INFORMATION |
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited) |
Condensed Consolidated Balance Sheets |
September 30, 2020 and December 31, 201 9 | 3
Condensed Consolidated Statements of Operations |
Three and N ine Months Ended September 30, 2020 and 2019 | 4
Condensed Consolidated Statements of Shareholders’ Equity |
Three and Nine Months Ended September 30, 2020 and 2019 | 5
Condensed Consolidated Statements of Cash Flows |
Nine Months Ended September 30, 2020 and 2019 | 6
Notes to Condensed Consolidated Financial Statements | 8
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 28
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 38
ITEM 4. CONTROLS AND PROCEDURES | 38
PART II. OTHER INFORMATION | 39
ITEM 1. LEGAL PROCEEDINGS | 39
ITEM 1A. RISK FACTORS | 39
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES | 41
ITEM 6. EXHIBITS | 42

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

‎

2

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAA LCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

|  | September 30, 2020 |  | December 31, 2019
ASSETS |  | (in thousands)
Current assets: |  |  |  |  |  |
Cash and cash equivalents |  | $ | 41,986 |  | $ | 45,917
Restricted cash |  |  | 82 |  |  | 911
Receivables: |  |  |  |  |  |
Trade |  |  | 6,080 |  |  | 14,335
Accounts with joint venture owners, net of allowance of $0.0 million and $0.5 million, respectively |  |  | — |  |  | 2,714
Foreign income taxes receivable |  |  | 1,124 |  |  | —
Other |  |  | 81 |  |  | 1,517
Crude oil inventory |  |  | 781 |  |  | 1,072
Prepayments and other |  |  | 4,264 |  |  | 3,292
Total current assets |  |  | 54,398 |  |  | 69,758
Crude oil and natural gas properties, equipment and other - successful efforts method, net |  |  | 38,845 |  |  | 68,258
Other noncurrent assets: |  |  |  |  |  |
Restricted cash |  |  | 925 |  |  | 925
Value added tax and other receivables, net of allowance of $2.1 million and $1.0 million, respectively |  |  | 3,684 |  |  | 3,683
Right of use operating lease assets |  |  | 25,700 |  |  | 33,383
Deferred tax assets |  |  | — |  |  | 24,159
Abandonment funding |  |  | 11,885 |  |  | 11,371
Total assets |  | $ | 135,437 |  | $ | 211,537
LIABILITIES AND SHAREHOLDERS' EQUITY |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |
Accounts payable |  | $ | 4,702 |  | $ | 15,897
Accounts with joint venture owners |  |  | 5,984 |  |  | —
Accrued liabilities and other |  |  | 14,426 |  |  | 29,773
Operating lease liabilities - current portion |  |  | 12,696 |  |  | 11,990
Foreign income taxes payable |  |  | — |  |  | 5,740
Current liabilities - discontinued operations |  |  | 15 |  |  | 350
Total current liabilities |  |  | 37,823 |  |  | 63,750
Asset retirement obligations |  |  | 17,105 |  |  | 15,844
Operating lease liabilities - net of current portion |  |  | 12,993 |  |  | 21,371
Deferred tax liabilities |  |  | 2,802 |  |  | —
Other long term liabilities |  |  | 43 |  |  | 852
Total liabilities |  |  | 70,766 |  |  | 101,817
Commitments and contingencies (Note 10) |  |  |  |  |  |
Shareholders’ equity: |  |  |  |  |  |
Preferred stock, $25 par value; 500,000 shares authorized, none issued |  |  | — |  |  | —
Common stock, $0.10 par value; 100,000,000 shares authorized, 67,819,242 and 67,673,787 shares issued, 57,456,139 and 58,024,571 shares outstanding, respectively |  |  | 6,782 |  |  | 6,767
Additional paid-in capital |  |  | 74,061 |  |  | 73,549
Less treasury stock, 10,363,103 and 9,649,216 shares, respectively, at cost |  |  | (42,419) |  |  | (41,429)
Retained earnings |  |  | 26,247 |  |  | 70,833
Total shareholders' equity |  |  | 64,671 |  |  | 109,720
Total liabilities and shareholders' equity |  | $ | 135,437 |  | $ | 211,537

See notes to condensed consolidated financial statements.
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VA ALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2020 |  | 2019 |  | 2020 |  | 2019
|  | (in thousands, except per share amounts)
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Crude oil and natural gas sales |  | $ | 18,256 |  | $ | 17,603 |  | $ | 54,619 |  | $ | 62,598
Operating costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Production expense |  |  | 8,984 |  |  | 9,836 |  |  | 30,859 |  |  | 27,874
Exploration expense |  |  | 16 |  |  | — |  |  | 16 |  |  | —
Depreciation, depletion and amortization |  |  | 2,212 |  |  | 1,509 |  |  | 8,116 |  |  | 4,971
Impairment of proved crude oil and natural gas properties |  |  | — |  |  | — |  |  | 30,625 |  |  | —
General and administrative expense |  |  | 2,178 |  |  | 4,738 |  |  | 5,951 |  |  | 11,905
Bad debt expense and other |  |  | 151 |  |  | 54 |  |  | 1,140 |  |  | 30
Total operating costs and expenses |  |  | 13,541 |  |  | 16,137 |  |  | 76,707 |  |  | 44,780
Other operating income (expense), net |  |  | (37) |  |  | 35 |  |  | (883) |  |  | (4,401)
Operating income (loss) |  |  | 4,678 |  |  | 1,501 |  |  | (22,971) |  |  | 13,417
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |
Derivative instruments gain, net |  |  | — |  |  | 2,267 |  |  | 6,583 |  |  | 2,266
Interest income, net |  |  | 23 |  |  | 193 |  |  | 150 |  |  | 581
Other, net |  |  | 147 |  |  | (138) |  |  | 163 |  |  | (521)
Total other income, net |  |  | 170 |  |  | 2,322 |  |  | 6,896 |  |  | 2,326
Income (loss) from continuing operations before income taxes |  |  | 4,848 |  |  | 3,823 |  |  | (16,075) |  |  | 15,743
Income tax expense (benefit) |  |  | (2,759) |  |  | 7,681 |  |  | 28,470 |  |  | 19,642
Income (loss) from continuing operations |  |  | 7,607 |  |  | (3,858) |  |  | (44,545) |  |  | (3,899)
Income (loss) from discontinued operations, net of tax |  |  | 11 |  |  | (61) |  |  | (41) |  |  | 5,448
Net income (loss) |  | $ | 7,618 |  | $ | (3,919) |  | $ | (44,586) |  | $ | 1,549
Basic net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Income (loss) from continuing operations |  | $ | 0.13 |  | $ | (0.07) |  | $ | (0.77) |  | $ | (0.07)
Income (loss) from discontinued operations, net of tax |  |  | 0.00 |  |  | 0.00 |  |  | 0.00 |  |  | 0.09
Net income (loss) per share |  | $ | 0.13 |  | $ | (0.07) |  | $ | (0.77) |  | $ | 0.02
Basic weighted average shares outstanding |  |  | 57,456 |  |  | 58,953 |  |  | 57,628 |  |  | 59,457
Diluted net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Income (loss) from continuing operations |  | $ | 0.13 |  | $ | (0.07) |  | $ | (0.77) |  | $ | (0.07)
Income (loss) from discontinued operations, net of tax |  |  | 0.00 |  |  | 0.00 |  |  | 0.00 |  |  | 0.09
Net income (loss) per share |  | $ | 0.13 |  | $ | (0.07) |  | $ | (0.77) |  | $ | 0.02
Diluted weighted average shares outstanding |  |  | 57,741 |  |  | 58,953 |  |  | 57,628 |  |  | 59,457

See notes to condensed consolidated financial statements.
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VAA LCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)

|  | Common Shares Issued |  | Treasury Shares |  | Common Stock |  | Additional Paid-In Capital |  | Treasury Stock |  | Retained Earnings |  | Total
|  | (in thousands)
Balance at January 1, 2020 |  | 67,674 |  | (9,649) |  | $ | 6,767 |  | $ | 73,549 |  | $ | (41,429) |  | $ | 70,833 |  | $ | 109,720
Shares issued - stock-based compensation |  | 125 |  | — |  |  | 13 |  |  | (13) |  |  | — |  |  | — |  |  | —
Stock-based compensation expense |  | — |  | — |  |  | — |  |  | 145 |  |  | — |  |  | — |  |  | 145
Treasury stock |  | — |  | (517) |  |  | — |  |  | — |  |  | (652) |  |  | — |  |  | (652)
Net loss |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (52,800) |  |  | (52,800)
Balance at March 31, 2020 |  | 67,799 |  | (10,166) |  |  | 6,780 |  |  | 73,681 |  |  | (42,081) |  |  | 18,033 |  |  | 56,413
Shares issued - stock-based compensation |  | 20 |  | — |  |  | 2 |  |  | (2) |  |  | — |  |  | — |  |  | —
Stock-based compensation expense |  | — |  | — |  |  | — |  |  | 60 |  |  | — |  |  | — |  |  | 60
Treasury stock |  | — |  | (197) |  |  | — |  |  | — |  |  | (338) |  |  | — |  |  | (338)
Net income |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | 596 |  |  | 596
Balance at June 30, 2020 |  | 67,819 |  | (10,363) |  |  | 6,782 |  |  | 73,739 |  |  | (42,419) |  |  | 18,629 |  |  | 56,731
Shares issued - stock-based compensation |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | —
Stock-based compensation expense |  | — |  | — |  |  | — |  |  | 322 |  |  | — |  |  | — |  |  | 322
Treasury stock |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | —
Net income |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | 7,618 |  |  | 7,618
Balance at September 30, 2020 |  | 67,819 |  | (10,363) |  | $ | 6,782 |  | $ | 74,061 |  | $ | (42,419) |  | $ | 26,247 |  | $ | 64,671

|  | Common Shares Issued |  | Treasury Shares |  | Common Stock |  | Additional Paid-In Capital |  | Treasury Stock |  | Retained Earnings |  | Total
|  | (in thousands)
Balance at January 1, 2019 |  | 67,168 |  | (7,572) |  | $ | 6,717 |  | $ | 72,358 |  | $ | (37,827) |  | $ | 68,579 |  | $ | 109,827
Shares issued - stock-based compensation |  | 160 |  | — |  |  | 16 |  |  | 31 |  |  | — |  |  | — |  |  | 47
Stock-based compensation expense |  | — |  | — |  |  | — |  |  | 28 |  |  | — |  |  | — |  |  | 28
Treasury stock |  | — |  | (45) |  |  | — |  |  | — |  |  | (105) |  |  | — |  |  | (105)
Net income |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | 6,501 |  |  | 6,501
Balance at March 31, 2019 |  | 67,328 |  | (7,617) |  |  | 6,733 |  |  | 72,417 |  |  | (37,932) |  |  | 75,080 |  |  | 116,298
Shares issued - stock-based compensation |  | 124 |  | — |  |  | 12 |  |  | 48 |  |  | — |  |  | — |  |  | 60
Stock-based compensation expense |  | — |  | — |  |  | — |  |  | 594 |  |  | — |  |  | — |  |  | 594
Treasury stock |  | — |  | (79) |  |  | — |  |  | — |  |  | 62 |  |  | (309) |  |  | (247)
Net loss |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,033) |  |  | (1,033)
Balance at June 30, 2019 |  | 67,452 |  | (7,696) |  |  | 6,745 |  |  | 73,059 |  |  | (37,870) |  |  | 73,738 |  |  | 115,672
Shares issued - stock-based compensation |  | 27 |  | — |  |  | 3 |  |  | 23 |  |  | — |  |  | — |  |  | 26
Stock-based compensation expense |  | — |  | — |  |  | — |  |  | 181 |  |  | — |  |  | — |  |  | 181
Treasury stock acquired |  | — |  | (1,190) |  |  | — |  |  | — |  |  | (2,073) |  |  | — |  |  | (2,073)
Net loss |  | — |  | — |  |  | — |  |  | — |  |  | — |  |  | (3,919) |  |  | (3,919)
Balance at September 30, 2019 |  | 67,479 |  | (8,886) |  | $ | 6,748 |  | $ | 73,263 |  | $ | (39,943) |  | $ | 69,819 |  | $ | 109,887

See notes to condensed consolidated financial statements.
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VA ALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

|  | Nine Months Ended September 30,
|  | 2020 |  | 2019
|  | (in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |  |  |
Net income (loss) |  | $ | (44,586) |  | $ | 1,549
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |  |  |
(Income) loss from discontinued operations |  |  | 41 |  |  | (5,448)
Depreciation, depletion and amortization |  |  | 8,116 |  |  | 4,971
Impairment of proved crude oil and natural gas properties |  |  | 30,625 |  |  | —
Other amortization |  |  | 181 |  |  | 181
Deferred taxes |  |  | 26,972 |  |  | 12,725
Unrealized foreign exchange gain |  |  | (60) |  |  | (46)
Stock-based compensation |  |  | (2,097) |  |  | 2,770
Cash settlements paid on exercised stock appreciation rights |  |  | — |  |  | (261)
Derivatives instruments gain |  |  | (6,583) |  |  | (2,266)
Cash settlements received on matured derivative contracts, net |  |  | 7,216 |  |  | 2,056
Bad debt expense and other |  |  | 1,140 |  |  | 30
Other operating loss, net |  |  | 83 |  |  | 37
Operational expenses associated with equipment and other |  |  | 1,418 |  |  | (62)
Change in operating assets and liabilities: |  |  |  |  |  |
Trade receivables |  |  | 8,255 |  |  | 4,404
Accounts with joint venture owners |  |  | 8,642 |  |  | 12,354
Other receivables |  |  | 1,333 |  |  | 219
Crude oil inventory |  |  | 291 |  |  | 10
Prepayments and other |  |  | (1,153) |  |  | (1,979)
Value added tax and other receivables |  |  | (919) |  |  | 664
Accounts payable |  |  | (9,318) |  |  | (2,154)
Foreign income taxes receivable/payable |  |  | (6,875) |  |  | (122)
Accrued liabilities and other |  |  | (3,285) |  |  | 4,092
Net cash provided by continuing operating activities |  |  | 19,437 |  |  | 33,724
Net cash used in discontinued operating activities |  |  | (376) |  |  | (4,673)
Net cash provided by operating activities |  |  | 19,061 |  |  | 29,051
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |  |  |
Property and equipment expenditures |  |  | (22,317) |  |  | (3,382)
Net cash used in continuing investing activities |  |  | (22,317) |  |  | (3,382)
Net cash used in discontinued investing activities |  |  | — |  |  | —
Net cash used in investing activities |  |  | (22,317) |  |  | (3,382)
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |  |  |
Proceeds from the issuances of common stock |  |  | — |  |  | 133
Treasury shares |  |  | (990) |  |  | (2,425)
Net cash used in continuing financing activities |  |  | (990) |  |  | (2,292)
Net cash used in discontinued financing activities |  |  | — |  |  | —
Net cash used in financing activities |  |  | (990) |  |  | (2,292)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH |  |  | (4,246) |  |  | 23,377
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD |  |  | 59,124 |  |  | 46,655
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD |  | $ | 54,878 |  | $ | 70,032

See notes to condensed consolidated financial statements.
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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)

|  | Nine Months Ended September 30,
|  | 2020 |  | 2019
|  | (in thousands)
Supplemental disclosure of cash flow information: |  |  |  |  |  |
Interest expense paid in cash |  | $ | — |  | $ | —
Income taxes paid in cash |  | $ | — |  | $ | —
Income taxes paid in-kind with crude oil |  | $ | 8,738 |  | $ | 7,347
Supplemental disclosure of non-cash investing and financing activities: |  |  |  |  |  |
Property and equipment additions incurred but not paid at end of period |  | $ | 1,360 |  | $ | 7,042
Recognition of right-of-use operating lease assets and liabilities |  | $ | 1,478 |  | $ | 44,681
Recognition of right-of-use operating lease liabilities |  | $ | 1,478 |  | $ | 44,656
Asset retirement obligations |  | $ | 359 |  | $ | 292

See notes to condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE 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, the Company has production operations and conducts exploration activities in Gabon, West Africa. The Company also has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, the Company has discontinued operations associated with activities in Angola, West Africa.

VAALCO’s consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited and VAALCO Energy (USA), Inc.

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

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the condensed consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, which includes a summary of the significant accounting policies.

A novel strain of coronavirus (“COVID-19”) was first identified in December 2019, and subsequently declared a global pandemic by the World Health Organization on March 11, 2020. As a result of the outbreak, many companies have experienced disruptions in their operations and in markets served. The Company has instituted some and may take additional temporary precautionary measures intended to help ensure the well-being of its employees and minimize business disruption. Such measures include social distancing measures and actively screening and monitoring employees and contractors that come on to the Company’s facilities. The adverse economic effects of the COVID-19 outbreak have materially decreased demand for crude oil based on the restrictions in place by governments trying to curb the outbreak and changes in consumer behavior. This has led to a significant global oversupply of oil and consequently a substantial decrease in crude oil prices.

While global oil producers, including the Organization of Petroleum Exporting Countries and other oil producing nations (“OPEC+”), reached agreement in April 2020 to cut oil production, downward pressure on commodity prices has remained and could continue for the foreseeable future, particularly given concerns over available storage capacity for crude oil. In response to the reduction in crude oil prices, VAALCO has instituted cost reduction measures that include negotiated cost reductions with vendors, cost sharing with operators and elimination or deferral of certain discretionary capital spending. Further, in connection with the OPEC+ agreement, the Minister of Hydrocarbons in Gabon requested that the Company reduce its production through December 2020. In response to such request from the Minister of Hydrocarbons, beginning in July 2020 and continuing through September 30, 2020, the Company temporarily reduced production from the Etame Marin block. With respect to requests related to the three months ended December 31, 2020, the Company plans to comply with such requests primarily through natural declines in production.

The Company considered the impact of the COVID-19 pandemic and the substantial decline in crude oil prices on the assumptions and estimates used for preparation of the financial statements. As a result, the Company recognized a number of material charges during the three months ended March 31, 2020, including impairments to its capitalized costs for proved crude oil and natural gas properties and valuation allowances on its deferred tax assets. These are discussed further in the following notes. Crude oil prices improved somewhat by September 30, 2020, and therefore no additional charges or impairments were required in the three months ended September 30, 2020. The full extent of the future impacts of COVID-19 on the Company’s operations is uncertain. A prolonged outbreak may have a material adverse impact on financial results and business operations of the Company, including the timing and ability of the Company to complete future drilling campaigns and other efforts required to advance the development of its crude oil and natural gas properties.

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, 2020 and 2019, respectively, each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long- term amounts at September 30, 2020 and 2019 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 10. The Company invests restricted and excess cash in readily redeemable money market funds.

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

|  | As of September 30,
|  | 2020 |  | 2019
|  | (in thousands)
Cash and cash equivalents |  | $ | 41,986 |  | $ | 57,227
Restricted cash - current |  |  | 82 |  |  | 769
Restricted cash - non-current |  |  | 925 |  |  | 924
Abandonment funding |  |  | 11,885 |  |  | 11,112
Total cash, cash equivalents and restricted cash |  | $ | 54,878 |  | $ | 70,032

The Company conducts regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” in the condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. See Note 12 for further discussion.

On February 28, 2019, the Gabonese branch of an international commercial bank holding the abandonment funds in a U.S. dollar denominated account advised that the bank regulator required transfer of the funds to the Central Bank (“Central Bank”) for the Economic and Monetary Community of Central Africa (“CEMAC”), of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Company’s production sharing contract related to the Etame Marin block located offshore Gabon (“Etame Marin block PSC”) provides these payments must be denominated in U.S. dollars. The new CEMAC foreign currency regulations provide for establishment of a U.S. dollar account with the Central Bank. Although we have requested establishment of such account, the necessary procedures have not been issued by the Central Bank and the relevant Gabon government agencies. As a result, we were not able to make the annual abandonment funding payment in 2019. In July 2020, the Central Bank’s board of directors authorized the opening of foreign exchange escrow accounts at the Central Bank, which progresses our request for such an account; however, the timeframe for completion of the process of establishing the account remains unclear. Amendment No. 5 to the Etame Marin block PSC also provides that in the event that the Gabonese bank fails for any reason to reimburse all of the principal and interest due, the Company and other joint interest owners shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.

Accounts Receivable and Allowance for Doubtful Accounts – The Company’s accounts receivable results from sales of crude oil production and joint interest billings to its joint interest owners for their share of expenses on joint venture projects for which the Company is the operator as well as from 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 the Company. Portions of the Company’s costs in Gabon (including the Company’s VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). Most of these receivables have payment terms of 30 days or less. The Company monitors the creditworthiness of the counterparties, and it has obtained credit enhancements from some parties in the form of parental guarantees or letters of credit. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements.

The Company routinely assesses the recoverability of all material receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. When collectability is in doubt, the Company records an allowance against the accounts receivable 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.

As of September 30, 2020, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $12.2 million ($4.1 million, net to VAALCO). As of September 30, 2020, the exchange rate was XAF 560.3 = $1.00. As of December 31, 2019, the exchange rate was XAF 585.7 = $1.00. 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 the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.

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

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2020 |  |  | 2019 |  | 2020 |  | 2019
|  | (in thousands)
Allowance for bad debt |  |  |  |  |  |  |  |  |  |  |  |
Balance at beginning of period |  | $ | (1,904) |  | $ | (1,876) |  | $ | (1,508) |  | $ | (2,535)
Bad debt charge |  |  | (151) |  |  | (54) |  |  | (1,140) |  |  | (30)
Adjustment associated with reversal of allowance on Mutamba receivable |  |  | — |  |  | — |  |  | 593 |  |  | —
Adjustment associated with settlement of customs audit |  |  | — |  |  | — |  |  | — |  |  | 623
Foreign currency gain |  |  | — |  |  | 53 |  |  | — |  |  | 65
Balance at end of period |  | $ | (2,055) |  | $ | (1,877) |  | $ | (2,055) |  | $ | (1,877)

Derivative Instruments and Hedging Activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.

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

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

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

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

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

Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.

Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.

For restricted stock, grant date fair value is determined using the market value of the common stock on the date of grant.

The stock-based compensation expense for equity awards is recognized over the requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.

Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 14 for further discussion.

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Fair value of financial instruments – T he Company’s assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets, accounts payable, SARs and guarantees. As discussed above, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. With respect to the Company’s other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. There were no transfers between levels for the three and nine months ended September 30, 2020 and 2019.

|  |  |  |  | As of September 30, 2020
|  | Balance Sheet Line |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
|  |  |  |  | (in thousands)
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
SARs liability |  |  | Accrued liabilities |  | $ | — |  | $ | 823 |  | $ | — |  | $ | 823
SARs liability |  |  | Other long-term liabilities |  |  | — |  |  | 43 |  |  | — |  |  | 43
|  |  |  |  | $ | — |  | $ | 866 |  | $ | — |  | $ | 866
|  |  |  |  | As of December 31, 2019
|  | Balance Sheet Line |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
|  |  |  |  | (in thousands)
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivative asset commodity swaps |  |  | Prepayments and other |  | $ | — |  | $ | 636 |  | $ | — |  | $ | 636
|  |  |  |  | $ | — |  | $ | 636 |  | $ | — |  | $ | 636
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
SARs liability |  |  | Accrued liabilities |  | $ | — |  | $ | 2,638 |  | $ | — |  | $ | 2,638
SARs liability |  |  | Other long-term liabilities |  |  | — |  |  | 852 |  |  | — |  |  | 852
|  |  |  |  | $ | — |  | $ | 3,490 |  | $ | — |  | $ | 3,490

Crude Oil and natural gas properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil and natural gas producing activities. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by drilling results. See Note 7 for further discussion.

Capitalizati on – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a field-by-field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a field-by-field basis under the unit-of-production method based upon estimates of proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil and natural gas producing activities, as well as property, plant and equipment unrelated to crude 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.

Impairment – The Company reviews the crude oil and natural gas producing properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum

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of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil and natural gas leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and in Block P in Equatorial Guinea.

Lease commitments – The Company leases office space, marine vessels and helicopters, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expire at various times. All leases are characterized as operating leases and the expense is included in either “production expense” or “general and administrative expense” in the condensed consolidated financial statements. See Note 11 for further discussion.

Asset retirement obligations (“ARO”) – T he Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. T he removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore crude 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 the crude oil and natural gas properties. T he Company uses 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 asset recorded to crude 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 is adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of the capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil and natural gas production facilities, while accretion escalates over the lives of the assets to reach the settlement value. See Note 12 for disclosures regarding the asset retirement obligations. 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.

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

Income taxes – T he Company’s tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the Company’s tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the Company’s level of operations or profitability in each jurisdiction impacts the Company’s tax liability in any given year. T he Company also operates in foreign jurisdictions where the tax laws relating to the crude oil and natural gas industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the Company’s income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax

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liabilities in the various jurisdictions are determined. We also record as income tax expense the increase or decrease in the value of the government of Gabon’s allocation of Profit Oil, which results due to change in value from the time the allocation is originally produced to the time the allocation is actually lifted.

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

In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects 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, the Company has not recognized deferred tax assets. Should the Company’s expectations change regarding the expected future tax consequences, i t may be required to record additional deferred taxes that could have a material effect on the Company’s condensed consolidated financial position and results of operations. See Note 15 for further discussion.

Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 5 for further discussion.

2. NEW ACCOUNTING STANDARDS

Not Yet Adopted

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2019-12, Income Taxes (Topic 740: Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which removes certain exceptions to the general principles in Topic 740. ASU 2019-12 is effective for the fiscal years beginning after December 15, 2020, with early adoption permitted. The Company is currently evaluating this guidance to determine the impact it may have on its condensed consolidated financial statements.

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 the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was 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. The FASB subsequently issued ASU No. 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU No. 2019-05 (“ASU 2019-05”): Financial Instruments-Credit Losses (Topic 326) - Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU No. 2019-10, Financial Instruments—Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU No. 2016-13 from January 1, 2020 to January 1, 2023 for calendar year end smaller reporting companies, which includes the Company. T he Company plans to defer the implementation of ASU 2016-13, and related updates, until January 2023.

In March 2020, the FASB issued ASU No. 2020-03 - Codification Improvements to Financial Instruments (“ASU 2020-03”). ASU 2020-03 improves and clarifies various financial instruments topics, including the CECL standard. ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. The amendments in ASU 2020-03 have different effective dates. The adoption of this guidance is not expected to have a material impact on the Company's financial statements.

Adopted

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in Accounting

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Standards Codification (“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. The Company’s adoption of this guidance on January 1, 2020 did not have an impact on its financial position, results of operations, cash flows and related disclosures.

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. ASU 2018-13 applies to all entities and is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. The Company’s adoption of this guidance on January 1, 2020 did not have an impact on its financial position, results of operations, cash flows and related disclosures.

In March 2020, the FASB issued ASU No. 2020-04 - Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying generally accepted accounting principles to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. In response to the concerns about structural risks of interbank offered rates (IBORs) and, particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR), regulators in several jurisdictions around the world have undertaken reference rate reform initiatives to identify alternative reference rates that are more observable or transaction based and less susceptible to manipulation. ASU 2020-04 provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates that are expected to be discontinued. The amendments in ASU 2020-04 are available to be adopted for all entities as of March 12, 2020, the date of issuance of Topic 848, and the relief provided within Topic 848 lasts until December 31, 2022. As the Company currently has no debt instruments or contracts where LIBOR is a material provision of contracts, the adoption of this guidance did not have a material impact on the Company's financial statements.

3. DISPOSITIONS

Discontinued Operations - Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was 40%, and the Company carried Sonangol P&P, for 10% of the work program. On September 30, 2016, the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, the Company notified the national concessionaire, Sonangol E.P., that it was withdrawing from the Block 5 PSA. Further to the decision to withdraw from Angola, the Company closed its office in Angola and reduced its activities in Angola. As a result of this strategic shift, the Company 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 the Company’s condensed consolidated statements of operations. The Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in the Company’s 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, 2020 and December 31, 2019 and its results of operations for the three and nine months ended September 30, 2020 and 2019.

Summarized Results of Discontinued Operations

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2020 |  | 2019 |  | 2020 |  | 2019
| (in thousands)
Operating costs and expenses: |  |  |  |  |  |  |  |  |  |  |
Gain on settlement of drilling obligation | $ | — |  | $ | — |  | $ | — |  | $ | (7,193)
General and administrative expense |  | (14) |  |  | 77 |  |  | 47 |  |  | 297
Total operating costs, expenses and (recovery) |  | (14) |  |  | 77 |  |  | 47 |  |  | (6,896)
Operating income (loss) |  | 14 |  |  | (77) |  |  | (47) |  |  | 6,896
Other expense: |  |  |  |  |  |  |  |  |  |  |
Other, net |  | — |  |  | — |  |  | (5) |  |  | —
Total other expense |  | — |  |  | — |  |  | (5) |  |  | —
Income (loss) from discontinued operations before income taxes |  | 14 |  |  | (77) |  |  | (52) |  |  | 6,896
Income tax expense (benefit) |  | 3 |  |  | (16) |  |  | (11) |  |  | 1,448
Income (loss) from discontinued operations | $ | 11 |  | $ | (61) |  | $ | (41) |  | $ | 5,448

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Assets and Liabilities Attributable to Discontinued Operations

|  | As of September 30, 2020 |  | As of December 31, 2019
|  | (in thousands)
ASSETS |  |  |  |  |  |
Accounts with joint venture owners |  | $ | — |  | $ | —
Total current assets |  |  | — |  |  | —
Total assets |  | $ | — |  | $ | —
LIABILITIES |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |
Accounts payable |  | $ | 7 |  | $ | 8
Accrued liabilities and other |  |  | 8 |  |  | 342
Total current liabilities |  |  | 15 |  |  | 350
Total liabilities |  | $ | 15 |  | $ | 350

Drilling Obligation

Under the Block 5 PSA, the Company and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases identified in the Block 5 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The Block 5 PSA provided for a stipulated payment of $10.0 million for each of the three exploration wells that a drilling obligation remained under the terms of the Block 5 PSA, of which the Company’s participating interest share would be $5.0 million per well. The Company reflected an accrual of $15.0 million for a potential payment as of December 31, 2018. In the first quarter of 2019, the Company and Sonangol E.P. entered into a settlement agreement finalizing the Company’s rights, liabilities and outstanding obligations for Block 5 in Angola. Pursuant to the settlement agreement, the Company agreed to pay $4.5 million to Angola National Agency of Petroleum, Gas, and Biofuels, as National Concessionaire, and to eliminate the $3.3 million receivable from Sonangol P&P. The receivable was related to joint interest billings and was reflected as a current asset from discontinued operations at year-end 2018. As a result, the Company adjusted a previously accrued liability and recognized a net of tax non-cash benefit from discontinued operations of $5.7 million in the first quarter of 2019. In July 2019, subsequent to the publication of an executive decree from the Ministry of Mineral Resources and Petroleum, the Company paid the $4.5 million due under the settlement agreement.

4. SEGMENT INFORMATION

The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s two reportable operating segments is organized and managed based upon geographic location. T he Company’s 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 that are not allocated to the reportable operating segments.

Segment activity of continuing operations for the three and nine months ended September 30, 2020 and 2019 as well as long-lived assets and segment assets at September 30, 2020 and December 31, 2019 are as follows:

|  | Three Months Ended September 30, 2020
(in thousands) |  | Gabon |  | Equatorial Guinea |  | Corporate and Other |  | Total
Revenues-crude oil and natural gas sales |  | $ | 18,256 |  | $ | — |  | $ | — |  | $ | 18,256
Depreciation, depletion and amortization |  |  | 1,946 |  |  | — |  |  | 266 |  |  | 2,212
Operating income (loss) |  |  | 6,957 |  |  | (95) |  |  | (2,184) |  |  | 4,678
Income tax expense (benefit) |  |  | (2,464) |  |  | 1 |  |  | (296) |  |  | (2,759)
Additions to crude oil and natural gas properties and equipment – accrual |  |  | (306) |  |  | — |  |  | (9) |  |  | (315)

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|  | Nine Months Ended September 30, 2020
(in thousands) |  | Gabon |  | Equatorial Guinea |  | Corporate and Other |  | Total
Revenues-crude oil and natural gas sales |  | $ | 54,619 |  | $ | — |  | $ | — |  | $ | 54,619
Depreciation, depletion and amortization |  |  | 7,790 |  |  | — |  |  | 326 |  |  | 8,116
Impairment of proved crude oil and natural gas properties |  |  | 30,625 |  |  | — |  |  | — |  |  | 30,625
Bad debt expense and other |  |  | 1,140 |  |  | — |  |  | — |  |  | 1,140
Other operating expense, net |  |  | (883) |  |  | — |  |  | — |  |  | (883)
Operating loss |  |  | (17,622) |  |  | (289) |  |  | (5,060) |  |  | (22,971)
Derivative instruments gain, net |  |  | — |  |  | — |  |  | 6,583 |  |  | 6,583
Income tax expense |  |  | 19,302 |  |  | 1 |  |  | 9,167 |  |  | 28,470
Additions to crude oil and natural gas properties and equipment – accrual |  |  | 10,305 |  |  | — |  |  | (9) |  |  | 10,296

|  | Three Months Ended September 30, 2019
(in thousands) |  | Gabon |  | Equatorial Guinea |  | Corporate and Other |  | Total
Revenues-crude oil and natural gas sales |  | $ | 17,603 |  | $ | — |  | $ | — |  | $ | 17,603
Depreciation, depletion and amortization |  |  | 1,437 |  |  | — |  |  | 72 |  |  | 1,509
Operating income (loss) |  |  | 6,048 |  |  | (54) |  |  | (4,493) |  |  | 1,501
Derivative instruments gain, net |  |  | — |  |  | — |  |  | 2,267 |  |  | 2,267
Income tax expense |  |  | 4,774 |  |  | — |  |  | 2,907 |  |  | 7,681
Additions to crude oil and natural gas properties and equipment – accrual |  |  | 6,112 |  |  | — |  |  | — |  |  | 6,112

|  | Nine Months Ended September 30, 2019
(in thousands) |  | Gabon |  | Equatorial Guinea |  | Corporate and Other |  | Total
Revenues-crude oil and natural gas sales |  | $ | 62,598 |  | $ | — |  | $ | — |  | $ | 62,598
Depreciation, depletion and amortization |  |  | 4,751 |  |  | — |  |  | 220 |  |  | 4,971
Other operating expense, net |  |  | (4,436) |  |  | — |  |  | 35 |  |  | (4,401)
Operating income (loss) |  |  | 24,541 |  |  | (370) |  |  | (10,754) |  |  | 13,417
Derivative instruments gain, net |  |  | — |  |  | — |  |  | 2,266 |  |  | 2,266
Interest income, net |  |  | 4 |  |  | — |  |  | 577 |  |  | 581
Other, net |  |  | (333) |  |  | (4) |  |  | (184) |  |  | (521)
Income tax expense |  |  | 15,134 |  |  | 12 |  |  | 4,496 |  |  | 19,642
Additions to crude oil and natural gas properties and equipment – accrual |  |  | 8,386 |  |  | (187) |  |  | 220 |  |  | 8,419

(in thousands) |  | Gabon |  | Equatorial Guinea |  | Corporate and Other |  | Total
Long-lived assets from continuing operations: |  |  |  |  |  |  |  |  |  |  |  |
As of September 30, 2020 |  | $ | 28,614 |  | $ | 10,000 |  | $ | 231 |  | $ | 38,845
As of December 31, 2019 |  | $ | 57,930 |  | $ | 10,000 |  | $ | 328 |  | $ | 68,258

(in thousands) |  | Gabon |  | Equatorial Guinea |  | Corporate and Other |  | Total
Total assets from continuing operations: |  |  |  |  |  |  |  |  |  |  |  |
As of September 30, 2020 |  | $ | 87,954 |  | $ | 10,116 |  | $ | 37,367 |  | $ | 135,437
As of December 31, 2019 |  | $ | 151,686 |  | $ | 10,087 |  | $ | 49,764 |  | $ | 211,537

Information about the Company’s most significant customers

The Company currently sells crude oil production from Gabon under term contracts with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. From August 2015 through January 2019, the Company sold its crude oil to Glencore Energy UK Ltd. (“Glencore”) and from February 2019 to January 2020, crude oil sales were to Mercuria Energy Trading SA (“Mercuria”). Sales of crude oil to Glencore and Mercuria were approximately 100% of total revenues for the period during the terms of their contracts. The Company signed a new contract with ExxonMobil Sales and Supply LLC (“Exxon”) that covers sales from February 2020 through January 2021 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. During the nine months ended September 30, 2020, revenues from sales of crude oil to Mercuria and Exxon were approximately 18% and 82%, respectively, of the Company’s total revenues from customers.

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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, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes 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:

| Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2020 |  |  | 2019 |  |  | 2020 |  |  | 2019
| (in thousands)
Net income (loss) (numerator): |  |  |  |  |  |  |  |  |  |  |
Income (loss) from continuing operations | $ | 7,607 |  | $ | (3,858) |  | $ | (44,545) |  | $ | (3,899)
(Income) loss from continuing operations attributable to unvested shares |  | (121) |  |  | — |  |  | — |  |  | 29
Numerator for basic |  | 7,486 |  |  | (3,858) |  |  | (44,545) |  |  | (3,870)
(Income) loss from continuing operations attributable to unvested shares |  | — |  |  | — |  |  | — |  |  | (29)
Numerator for dilutive | $ | 7,486 |  | $ | (3,858) |  | $ | (44,545) |  | $ | (3,899)
Income (loss) from discontinued operations, net of tax | $ | 11 |  | $ | (61) |  | $ | (41) |  | $ | 5,448
(Income) loss from discontinued operations attributable to unvested shares |  | — |  |  | — |  |  | — |  |  | (41)
Numerator for basic |  | 11 |  |  | (61) |  |  | (41) |  |  | 5,407
(Income) loss from discontinued operations attributable to unvested shares |  | — |  |  | — |  |  | — |  |  | 41
Numerator for dilutive | $ | 11 |  | $ | (61) |  | $ | (41) |  | $ | 5,448
Net income (loss) | $ | 7,618 |  | $ | (3,919) |  | $ | (44,586) |  | $ | 1,549
Net (income) loss attributable to unvested shares |  | (121) |  |  | — |  |  | — |  |  | (12)
Numerator for basic |  | 7,497 |  |  | (3,919) |  |  | (44,586) |  |  | 1,537
Net (income) loss attributable to unvested shares |  | — |  |  | — |  |  | — |  |  | 12
Numerator for dilutive | $ | 7,497 |  | $ | (3,919) |  | $ | (44,586) |  | $ | 1,549
Weighted average shares (denominator): |  |  |  |  |  |  |  |  |  |  |
Basic weighted average shares outstanding |  | 57,456 |  |  | 58,953 |  |  | 57,628 |  |  | 59,457
Effect of dilutive securities |  | 285 |  |  | — |  |  | — |  |  | —
Diluted weighted average shares outstanding |  | 57,741 |  |  | 58,953 |  |  | 57,628 |  |  | 59,457
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive |  | 1,801 |  |  | 324 |  |  | 3,465 |  |  | 548

6. REVENUE

Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs. The COSPAs have been and will be renewed or replaced from time to time either with the current buyer or another buyer. See Note 4 under Information about the Company’s most significant customers for further discussion.

COSPAs with customers are renegotiated near the end of the contract term and may be entered into with a different customer or the same customer 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 crude 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 that 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. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

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The Company accounts for production imbalances as a reduction in reserves. The volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the existing proved reserves were not adequate to cover an imbalance.

For each lifting completed under a COSPA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

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, the Company deemed 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. The Etame Marin block PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. The terms of the Etame Marin block PSC include 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% (increas ing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame Marin block 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, the Company would no longer have sales to customers associated with production assigned to royalties.

With respect to the government’s share of Profit Oil, the Etame Marin block PSC provides that the corporate income tax liability 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 as current income tax expense. These sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the Etame Marin block PSC is reflected as revenue with an offsetting amount reported as a current income tax expense. Payments of the income tax expense will be reported in the period that the government takes its Profit Oil in-kind, i.e. the period in which it lifts the crude oil. In-kind payments were $1.9 million with the April 2020 lifting and $6.9 million with the August 2020 lifting. With the August lifting, the government lifted more oil in-kind than what was owed to it in foreign taxes; therefore, the Company has a $1.1 million foreign income tax receivable as of September 30, 2020. As of December 31, 2019, the foreign income taxes payable attributable to this obligation was $5.7 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 that would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues.

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2020 |  | 2019 |  | 2020 |  | 2019
Revenue from customer contracts: | (in thousands)
Sales under the COSPA | $ | 13,797 |  | $ | 19,660 |  | $ | 53,057 |  | $ | 62,420
Other items reported in revenue not associated with customer contracts: |  |  |  |  |  |  |  |  |  |  |
Gabonese government share of Profit Oil taken in-kind |  | 6,883 |  |  | — |  |  | 8,738 |  |  | 7,347
Carried interest recoupment |  | 280 |  |  | 511 |  |  | 1,273 |  |  | 1,951
Royalties |  | (2,704) |  |  | (2,568) |  |  | (8,449) |  |  | (9,120)
Total revenue, net | $ | 18,256 |  | $ | 17,603 |  | $ | 54,619 |  | $ | 62,598

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7. CRUDE OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

The Company’s crude oil and natural gas properties and equipment is comprised of the following:

|  | As of September 30, 2020 |  | As of December 31, 2019
|  | (in thousands)
Crude oil and natural gas properties and equipment - successful efforts method: |  |  |  |  |  |
Wells, platforms and other production facilities |  | $ | 441,915 |  | $ | 422,651
Work-in-progress |  |  | — |  |  | 7,378
Undeveloped acreage |  |  | 21,476 |  |  | 23,771
Equipment and other |  |  | 10,181 |  |  | 11,157
|  |  | 473,572 |  |  | 464,957
Accumulated depreciation, depletion, amortization and impairment |  |  | (434,727) |  |  | (396,699)
Net crude oil and natural gas properties, equipment and other |  | $ | 38,845 |  | $ | 68,258

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 an extension for additional years (“PSC Extension”) to the Consortium to operate in the Etame Marin block. T he Company’s 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) was paid in cash by the Consortium following the end of the drilling activities described below. T he Company accrued the $1.7 million share of this remaining payment as of December 31, 2019. This payment was made in February 2020. The amount paid through a reduction in VAT has been recorded at $4.2 million, which represents the book value of the receivable, net of the valuation allowance as of the effective date. In addition, the Company recorded an increase of $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis. A corresponding $18.6 million deferred tax liability was recorded, which reduced the net deferred tax assets. T he Company has allocated the share of the signing bonus between proved and unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas resulting in $22.5 million being attributed to proved leasehold costs and $13.7 million attributed to unproved leasehold costs.

Under the PSC Extension, the Consortium was required to drill two wells and two appraisal wellbores as well as conduct two technical studies by September 16, 2020. The Consortium completed drilling two development wells and two appraisal wellbores during the 2019/2020 drilling campaign with the last appraisal wellbore completed in February 2020. During September 2020, the Consortium completed the two technical studies at a cost of $1.5 million gross ($0.5 million, net to VAALCO).

In accordance with the Etame Marin block PSC, the Consortium maintains a “Cost Account,” which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. Prior to the PSC Extension, the Consortium was entitled to take up to 70% of production remaining after the 13% royalty (“Cost Recovery Percentage”) to recover its costs so long as there are amounts remaining in the Cost Account. Under the PSC Extension, the Cost Recovery Percentage is increased to 80% for the ten-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%.

Prior to the PSC Extension, the Etame Marin block 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%.

Proved Properties

The Company reviews the crude 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 a crude oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is

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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 the 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 2020 that would cause us to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included slightly higher future strip prices for the third quarter of 2020 compared to the second quarter of 2020, and that the Company incurred no significant capital expenditures in the period related to the fields in the Etame Marin block. During the first quarter of 2020, d eclining forecasted oil prices caused the Company to perform an impairment review. The impairment test was performed using the year end 2019 independently prepared reserve report, estimated reserves for the South East Etame 4H well completed in March 2020 and forward price curves. The Company performed a recoverability test as defined under ASC 932 and ASC 360, noting that the undiscounted cash flows related to the Etame, Avouma, Ebouri, Southeast Etame and North Tchibala fields were less than the book values for these fields resulting in the Company recording a $30.6 million impairment loss to write down the Company’s investment in each field to their fair value of $15.6 million during the three months ended March 31, 2020.

With respect to the third quarter of 2019, as a result of lower future strip prices for the third quarter of 2019 compared to the second quarter of 2019, VAALCO compared the undiscounted estimated future net cash flows to the carrying value of the crude oil and natural gas properties. Based on this analysis, no impairment was identified and there were no indicators that adjustments were needed to the year-end reserve report.

Undeveloped Leasehold Costs

VAALCO acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The Ministry of Mines and Hydrocarbons (“EG MMH”) approved our appointment as operator for Block P interest on November 12, 2019. The Company acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing its working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million in the event that there is commercial production from Block P, and the EG MMH has approved this assignment. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. VAALCO is in commercial discussions with Levene Hydro c arbon Limited (“Levene”) regarding a potential transaction whereby VAALCO would assign a portion of its working interest in Block P to Levene in exchange for Levene carrying VAALCO’s cost to drill an exploratory well. Levene and VAALCO have executed a non-binding Memorandum of Understanding regarding these commercial discussions; however, neither have executed any binding agreements and there can be no certainty a transaction will be completed. Further, approval of the assignment to Levene by the EG MMH must be obtained prior to any transaction being completed. As of September 30, 2020, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. VAALCO and its current and potential future 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. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.

As a result of the PSC Extension, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame Marin block PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, $2.3 million of costs were transferred to proved leasehold costs leaving a remaining $11.5 million in unproved leasehold costs.

Capitalized Equipment Inventory

Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded on “Other operating expense, net” line item of the condensed consolidated statements of operations but were not material for the three and nine months ended September 30, 2020 and 2019.

8. DERIVATIVES AND FAIR VALUE

The Company uses derivative financial instruments from time to time to achieve a more predictable cash flow from crude oil production by reducing the Company’s exposure to price fluctuations.

Commodity swaps - In June 2018, the Company entered into commodity swaps at a Dated Brent weighted average of $74.00 per barrel for the period from and including June 2018 through June 2019 for a quantity of approximately 400,000 barrels. On May 6, 2019, the Company entered into commodity swaps at a Dated Brent weighted average of $66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. During the three months ended September 30, 2020, the Company did not have any unexpired commodity swaps or other derivative instruments.

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While these commodity swaps are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, the Company has not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. T he Company does not enter into derivative instruments for speculative or trading proposes.

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

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

The following table sets forth the gain (loss) on derivative instruments on the Company’s condensed consolidated statements of operations:

|  |  |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
Derivative Item |  | Statement of Operations Line |  | 2020 |  | 2019 |  | 2020 |  | 2019
|  |  |  | (in thousands)
Crude oil swaps |  | Realized gain - contract settlements |  | $ | — |  | $ | 493 |  | $ | 7,216 |  | $ | 2,056
|  | Unrealized gain (loss) |  |  | — |  |  | 1,774 |  |  | (633) |  |  | 210
|  | Derivative instruments gain, net |  | $ | — |  | $ | 2,267 |  | $ | 6,583 |  | $ | 2,266

9. ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:

|  | As of September 30, 2020 |  | As of December 31, 2019
|  | (in thousands)
Accrued accounts payable invoices |  | $ | 3,947 |  | $ | 4,650
Joint venture audit settlement |  |  | — |  |  | 3,322
Gabon DMO, PID and PIH obligations |  |  | 4,762 |  |  | 3,314
Capital expenditures |  |  | 1,325 |  |  | 11,792
Stock appreciation rights |  |  | 823 |  |  | 2,638
Accrued wages and other compensation |  |  | 1,797 |  |  | 1,731
Other |  |  | 1,772 |  |  | 2,326
Total accrued liabilities and other |  | $ | 14,426 |  | $ | 29,773

10. COMMITMENTS AND CONTINGENCIES

Abandonment funding

Under the terms of the Etame Marin block PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028. The amounts paid will be reimbursed through the Cost Account and are non-refundable. The abandonment estimate used for this purpose is approximately $61.8 million ($19.2 million net to VAALCO) on an undiscounted basis. Through September 30, 2020, $38.3 million ($11.9 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 the condensed consolidated balance sheet. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.

On March 5, 2019, in accordance with certain foreign currency regulatory requirements, the Gabonese branch of an international commercial bank holding the abandonment funds in a U.S. dollar denominated account transferred the funds to the Central Bank for CEMAC, of which Gabon is one of the six member states. The U.S. dollars were con verted to local currency with a credit back to the Gabonese branch. Amendment No. 5 to the Etame Marin block PSC provides that in the event that the Gabonese bank fails for any reasons to reimburse all of the principal and interest due, the Company and the other joint venture owners shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.

FPSO charter

In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter may be extended for two one-year periods beyond September 2020. These elections have been made, and the charter has been extended through September 2022. T he Company obtained guarantees from each of the Company’s joint venture owners for their respective shares of the payments. T he Company’s net share of the charter payment is 31.1%, or approximately $9.7 million per year. Although the Company believes the need for performance under the charter guarantee is remote, the Company recorded a liability of $0.4 million as of September 30,

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2020 and $0.4 million as of December 31, 2019 representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO charter has $65.1 million in remaining gross minimum obligations as of September 30, 2020.

Regulatory and Joint Interest Audits and Related Matters

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

In 2016, the government of Gabon conducted an audit of the Company’s operations in Gabon, covering the years 2013 through 2014. T he Company received the findings from this audit and responded to the audit findings in January 2017. Since providing the Company’s response, there have been changes in the Gabonese officials responsible for the audit. T he Company is working with the newly appointed representatives to resolve the audit findings. T he Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.

In July 2019, the Company reached an agreement in principle to resolve a legacy issue related to findings from the Etame Marin block joint venture owners’ audits for the periods from 2007 through 2016 for $4.4 million net to VAALCO. Accordingly, the Company has accrued $4.4 million that is reflected in the “Accrued liabilities and other” line item of the Company’s condensed consolidated balance sheet and is recorded as a second quarter 2019 expense in the condensed consolidated statements of operations in the line item “Other operating expense, net”. The final settlement agreements were executed by all the joint venture owners effective September 9, 2019. In October 2019, the Company paid $1.1 million of the $4.4 million. The remaining balance of the amount due was paid in February 2020.

In 2019, the Etame joint venture owners conducted audits for the years 2017 and 2018. In June 2020, the Company agreed to a $0.8 million payment to resolve claims made by one of the Etame Marin block joint venture owners, Addax Petroleum Gabon S.A. There are now no unresolved matters related to the joint venture owner audits.

Other contractual commitments

In August 2020, the Company entered into an agreement to acquire 742 square kilometers of three-dimensional seismic data in the Company’s Etame Marin block. The acquisition is expected to begin in the fourth quarter of 2020 and take approximately 2 to 3 months from the start of operations. The cost, net to VAALCO, is estimated to be approximately $4.0 million to $5.0 million.

11. LEASES

Under ASC 842, Leases, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a Right-of-Use (“ROU”) asset and a lease liability at the present value of the future lease payments.

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

The Company is currently a party to several lease agreements for the rental of marine vessels and helicopters, warehouse and storage facilities, equipment and the FPSO. The duration for these agreements range from 21 to 45 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for the FPSO, the marine vessels, helicopter, certain equipment and warehouse and storage facilities used in the joint operations includes the gross amount of the lease components.

The FPSO lease includes options to extend the term through September 2022. T he Company considered these options reasonably certain of exercise and included them in the calculation of ROU assets and lease liabilities. For all other leases that contain an option

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to extend, the Company has concluded that it is not reasonably certain it will exercise the renewal option and the renewal periods have been excluded in the calculation for the ROU assets and liabilities. During the third quarter 2019, the Company notified the lessor of the FPSO of its intent to extend the lease term by the first option that extends the FPSO lease to September 2021. Similarly, during the third quarter of 2020, the Company gave notification to extend the FPSO lease to September 2022.

The FPSO agreement also contains options to purchase the assets during or at the end of the lease term. T he Company does not consider these options reasonably certain of exercise and has excluded the purchase price from the calculation of ROU assets and lease liabilities.

The FPSO, helicopter, marine vessels and certain equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the level of production or the number of days or hours the asset is deployed, or the number of persons onboard the vessel. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the initial calculation of ROU assets and lease liabilities.

The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. T he Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.

For the three and nine months ended September 30, 2020, the components of the lease costs and the supplemental information were as follows:

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2020 |  | 2019 |  | 2020 |  | 2019
Lease cost: |  | (in thousands)
Operating lease cost |  | $ | 4,519 |  | $ | 4,820 |  | $ | 13,044 |  | $ | 12,154
Short-term lease cost |  |  | 457 |  |  | 166 |  |  | 908 |  |  | 570
Variable lease cost |  |  | 1,715 |  |  | 1,652 |  |  | 5,779 |  |  | 4,390
Total lease expense |  |  | 6,691 |  |  | 6,638 |  |  | 19,731 |  |  | 17,114
Lease costs capitalized |  |  | 11 |  |  | 99 |  |  | 3,470 |  |  | 99
Total lease costs |  | $ | 6,702 |  | $ | 6,737 |  | $ | 23,201 |  | $ | 17,213
Other information: |  |  |  |  |  |  |  |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Operating cash flows to operating leases |  |  |  |  |  |  |  |  |  |  | $ | 20,564
Weighted-average remaining lease term |  |  |  |  |  |  |  |  |  |  |  | 2.0 years
Weighted-average discount rate |  |  |  |  |  |  |  |  |  |  |  | 6.09%

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

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2020 |  | 2019 |  | 2020 |  | 2019
|  | (in thousands)
Production expense |  | $ | 2,063 |  | $ | 1,979 |  | $ | 6,082 |  | $ | 5,202
General and administrative expense |  |  | 49 |  |  | 49 |  |  | 147 |  |  | 147
Lease costs billed to the joint venture owners |  |  | 4,586 |  |  | 4,610 |  |  | 15,807 |  |  | 11,765
Total lease expense |  |  | 6,698 |  |  | 6,638 |  |  | 22,036 |  |  | 17,114
Lease costs capitalized |  |  | 4 |  |  | 99 |  |  | 1,165 |  |  | 99
Total lease costs |  | $ | 6,702 |  | $ | 6,737 |  | $ | 23,201 |  | $ | 17,213

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The following table describes the future maturities of the Company’s operating lease liabilities at September 30, 2020:

|  | Lease Obligation
Year |  | (in thousands)
2020 |  | $ | 3,489
2021 |  |  | 13,864
2022 |  |  | 9,685
2023 |  |  | 179
2024 |  |  | —
|  |  | 27,217
Less: imputed interest |  |  | 1,528
Total lease liabilities |  | $ | 25,689

Under the joint operating agreements, other joint owners are obligated to fund $18.8 million of the $27.2 million in future lease liabilities.

12. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations:

(in thousands) |  | Nine Months Ended September 30, 2020 |  | Year Ended December 31, 2019
Beginning balance |  | $ | 15,844 |  | $ | 14,816
Accretion |  |  | 664 |  |  | 812
Additions |  |  | 359 |  |  | 595
Revisions |  |  | 238 |  |  | (379)
Ending balance |  | $ | 17,105 |  | $ | 15,844

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

The Company is required under the Etame Marin block PSC to conduct regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in November 2018. In the second half of 2019, the Company recorded $0.6 million in additions associated with the Etame 9H and Etame 11H development wells. Du ring the first half of 2020, the Company recorded $0.4 million in additions associated with the South East Etame 4H development well.

13. SHAREHOLDERS’ EQUITY

Preferred stock – Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. No shares of preferred stock were issued and outstanding as of September 30, 2020 or December 31, 2019.

Treasury stock – On June 20, 2019, the Board of Directors authorized and approved a share repurchase program for up to $10.0 million of the currently outstanding shares of the Company’s common stock over a period of 12 months. Under the stock repurchase program, the Company could repurchase shares through open market purchases, privately-negotiated transactions, block purchases or otherwise in accordance with applicable federal securities laws, including Rule 10b-18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”).﻿ The Board of Directors also authorized the Company to enter into written trading plans under Rule 10b5-1 of the Exchange Act.

From commencement of the plan in June 2019 through April 13, 2020, the Company purchased 2,740,643 shares of common stock at an average price of $1.70 per share for an aggregate purchase price of $4.7 million under the plan. On April 13, 2020, the Board of Directors approved the termination of the share repurchase program; consequently, no further shares can be repurchased pursuant to the plan.

For the majority of restricted stock awards granted by the Company, the number of shares issued on the date the restricted stock
‎awards vest is net of shares withheld to meet applicable tax withholding requirements. Although these withheld shares are
‎not issued or considered common stock repurchases under the Company’s stock repurchase program, they are treated as common stock repurchases in our financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 14 for further discussion.

14. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS

The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Board of Directors to issue various types of incentive compensation. T he Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan (“2014 Plan”) and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s shareholders approved the 2020

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Long-Term Incentive Plan (“2020 Plan”) under which 5,500,000 shares are authorized for future grants. At September 30, 2020, 3,388,505 shares were available for future grants.

For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under both the 2014 Plan and 2020 Plan will be reduced by twice the number of restricted shares. T he Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.

As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the nine months ended September 30, 2020, the Company did not settle any stock-based compensation. During the nine months ended September 30, 2019, the Company settled in cash $0.3 million for stock appreciation rights and received $0.1 million for stock option exercises. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2020 |  | 2019 |  | 2020 |  | 2019
|  | (in thousands)
Stock-based compensation - equity awards |  | $ | 322 |  | $ | 180 |  | $ | 527 |  | $ | 802
Stock-based compensation - liability awards |  |  | (570) |  |  | 970 |  |  | (2,624) |  |  | 1,968
Total stock-based compensation |  | $ | (248) |  | $ | 1,150 |  | $ | (2,097) |  | $ | 2,770

Stock options and performance shares

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 the Company’s Board of Directors, which generally vest over a service period of up to five years and expire from five to ten years from the date of grant.

In June 2020, the Company granted options that are considered performance stock options to purchase an aggregate of 644,758 shares at an exercise price of $1.23 per share and a life of ten years were granted to employees of the Company. For each option award, options with respect to one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $1.42 per share; options with respect to one-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $1.63 per share; and options with respect to the remaining one-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $1.88 per share. These awards are option awards that contain a market condition. Compensation cost for such awards is recognized ratably over the derived service period and compensation cost related to awards with a market condition will not be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such performance criteria.

The Company used the Monte Carlo simulation to calculate the grant date fair value of performance stock option awards. The fair value of these awards will be amortized to expense over the derived service period of the option. During the nine months ended September 30, 2020, the assumptions shown below were used to calculate the weighted average grant date fair value of performance stock option awards issued under the 2020 Plan.

For options that do not contain a market or performance condition, the Company uses the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the service period of the option.

Because the Company has not paid cash dividends and does not anticipate paying cash dividends on the common stock in the foreseeable future, no expected dividend yield was input to the Black-Scholes or Monte Carlo models. During the nine months ended September 30, 2020 and 2019, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants.

| Nine Months Ended September 30, |
| 2020 |  | 2019 |
Weighted average exercise price - ($/share) | $ | 1.23 |  | $ | 2.08 |
Expected life in years |  | 6.0 |  |  | 3.2 |
Average expected volatility |  | 74.16 | % |  | 72.53 | %
Risk-free interest rate |  | 0.42 | % |  | 2.33 | %
Weighted average grant date fair value - ($/share) | $ | 0.79 |  | $ | 1.06 |

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Stock option activity for the nine months ended September 30, 2020 is provided below:

|  | Number of Shares Underlying Options |  | Weighted Average Exercise Price Per Share |  |  | Weighted Average Remaining Contractual Term |  |  | Aggregate Intrinsic Value
|  | (in thousands) |  |  |  |  |  | (in years) |  |  | (in thousands)
Outstanding at January 1, 2020 |  | 2,834 |  | $ | 1.55 |  |  |  |  |  |
Granted |  | 644 |  |  | 1.23 |  |  |  |  |  |
Exercised |  | — |  |  | — |  |  |  |  |  |
Unvested shares forfeited |  | (60) |  |  | 1.83 |  |  |  |  |  |
Vested shares expired |  | (347) |  |  | 2.90 |  |  |  |  |  |
Outstanding at September 30, 2020 |  | 3,071 |  |  | 1.32 |  |  | 3.38 |  | $ | 60
Exercisable at September 30, 2020 |  | 1,960 |  |  | 1.22 |  |  | 1.36 |  | $ | 42

During the nine months ended September 30, 2020, no shares were added to treasury as a result of tax withholding on options exercised. During the nine months ended September 30, 2019, 13,875 shares were added to treasury as a result of tax withholding on options exercised. During the nine months ended September 30, 2019, 62,235 shares that had been granted from treasury were exercised and taken from treasury.

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). In June 2020, the Company issued 710,851 and 260,164 shares of service based restricted stock to employees and directors, respectively, with a grant date fair value of $1.23 per share. The vesting of these shares is dependent upon the employees’ and directors’ continued service with the Company.

The following is a summary of activity for the nine months ended September 30, 2020:

|  | Restricted Stock |  | Weighted Average Grant Date Fair Value
|  | (in thousands) |  |  |
Non-vested shares outstanding at January 1, 2020 |  | 343 |  | $ | 1.52
Awards granted |  | 971 |  |  | 1.23
Awards vested |  | (145) |  |  | 1.39
Awards forfeited |  | — |  |  | —
Non-vested shares outstanding at September 30, 2020 |  | 1,169 |  |  | 1.30

During the nine months ended September 30, 2020, 40,432 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the nine months ended September 30, 2019, 30,573 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.

Stock appreciation rights (“SARs”)

SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 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 exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s Board of Directors.

During the nine months ended September 30, 2020, the Company did not grant SARs to employees or directors.

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SAR activity for the nine months ended September 30, 2020 is provided below:

|  | Number of Shares Underlying SARs |  | Weighted Average Exercise Price Per Share |  |  | Term |  | Aggregate Intrinsic Value
|  | (in thousands) |  |  |  |  |  | (in years) |  |  | (in thousands)
Outstanding at January 1, 2020 |  | 3,418 |  | $ | 1.30 |  |  |  |  |  |
Granted |  | — |  |  | — |  |  |  |  |  |
Exercised |  | — |  |  | — |  |  |  |  |  |
Unvested SARs forfeited |  | (60) |  |  | 1.83 |  |  |  |  |  |
Vested SARs expired |  | (61) |  |  | 1.34 |  |  |  |  |  |
Outstanding at September 30, 2020 |  | 3,297 |  |  | 1.29 |  |  | 2.44 |  | $ | 234
Exercisable at September 30, 2020 |  | 2,117 |  |  | 1.15 |  |  | 2.17 |  | $ | 151

Other Benefit Plans

The Company has adopted forms of change in control agreements for its named executive officers and certain other officers of the Company as well as a severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements and participants in the severance plan will be entitled to receive 100% and 50%, respectively, of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months. In addition, certain named executive officers will receive 75% of their target bonus.

15. INCOME TAXES

The income tax provision for VAALCO consists primarily of Gabonese and United States income taxes. The Company’s operations in other foreign jurisdictions have a 0% effective tax rate because the Company has incurred losses in those countries and has full valuation allowances against the corresponding net deferred tax assets. The Company files income tax returns in all jurisdictions where such requirements exist, with Gabon and the United States being its primary tax jurisdictions.

For interim reporting periods, the Company determines its tax expense by estimating an annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and applies this tax rate to the Company’s ordinary income or loss to calculate its estimated tax expense or benefit. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory tax rate.

In March 2020, the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) became law. The CARES Act, among other things, includes provisions to obtain alternative minimum tax credit refunds for which the company qualifies for. The Company has analyzed the different aspects of the CARES Act and implemented the applicable provisions, which had no material impact on the Company.

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

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2020 |  | 2019 |  | 2020 |  | 2019
U.S. Federal: |  | (in thousands)
Current |  | $ | 147 |  | $ | (135) |  | $ | (378) |  | $ | (300)
Deferred |  |  | (442) |  |  | 3,042 |  |  | 9,546 |  |  | 4,808
Foreign: |  |  |  |  |  |  |  |  |  |  |  |
Current |  |  | 2,393 |  |  | 2,758 |  |  | 1,876 |  |  | 7,217
Deferred |  |  | (4,857) |  |  | 2,016 |  |  | 17,426 |  |  | 7,917
Total |  | $ | (2,759) |  | $ | 7,681 |  | $ | 28,470 |  | $ | 19,642

The Company’s effective tax rate for the nine months ended September 30, 2020 and 2019, excluding the impact of discrete items, was (53%) and 101%, respectively. For the three and nine months ended September 30, 2020, the Company’s overall effective tax rate was impacted by non-deductible items associated with operations, the impact of deducting foreign taxes rather than crediting them, and a change in valuation allowance. The valuation allowance was necessary due to the decline in crude oil prices caused by declining global economic activity and excess oil supply. The total change in valuation allowances for the three and nine months ended September 30, 2020 was $(5.4) million and $37.4 million, respectively. For the nine months ended September 30, 2020 the current tax expense of $1.5 million includes a $3.8 million favorable oil price adjustment as a result of the change in value of the government’s allocation between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $5.3 million for the period.

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As of September 30, 2020, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

the impact of the COVID-19 pandemic, including the sharp decline in the global demand for crude oil, which resulted in a significant global oversupply of crude oil and steep decline in crude oil prices, potential difficulties in obtaining additional liquidity when and if needed, disruptions in global supply chains, quarantines of our workforce or workforce reductions and other matters related to the pandemic;

the impact of production quotas imposed by Gabon, as a member of the Organization of the Petroleum Exporting Countries, (“OPEC”), as a result of agreements among OPEC, Russia and other allied producing countries (collectively, “OPEC+”) with respect to crude oil production levels;

volatility of, and declines and weaknesses in crude oil and natural gas prices, as well as our ability to offset volatility in prices through the use of hedging transactions;

the discovery, acquisition, development and replacement of crude oil and natural gas reserves;

impairments in the value of our crude oil and natural gas assets;

future capital requirements;

our ability to maintain sufficient liquidity in order to fully implement our business plan;

our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements;

our ability to attract capital or obtain debt financing arrangements;

our ability to pay the expenditures required in order to develop certain of our properties;

operating hazards inherent in the exploration for and production of crude oil and natural gas;

difficulties encountered during the exploration for and production of crude oil and natural gas;

the impact of competition;

our ability to identify and complete complementary opportunistic acquisitions;

our ability to effectively integrate assets and properties that we acquire into our operations;

weather conditions;

the uncertainty of estimates of crude oil and natural gas reserves;

currency exchange rates and regulations;

unanticipated issues and liabilities arising from non-compliance with environmental regulations;

the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon;

the availability and cost of seismic, drilling and other equipment;

difficulties encountered in measuring, transporting and delivering crude oil to commercial markets;

timing and amount of future production of crude oil and natural gas;

hedging decisions, including whether or not to enter into derivative financial instruments;

general economic conditions, including any future economic downturn, disruption in financial markets and the availability of credit;

our ability to enter into new customer contracts;

changes in customer demand and producers’ supply;

actions by the governments of and events occurring in the countries in which we operate;

actions by our joint venture owners;

‎

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compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;

the outcome of any governmental audit; and

actions of operators of our crude oil and natural gas properties.

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, 2019 (“2019 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 2019 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 the statements are 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, express or implied, are expressly qualified in their entirety by this “Special Note Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this report.

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 also have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 to the condensed consolidated financial statements included in this Quarterly Report on Form 10-Q, 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 crude oil production and the costs to find and produce such crude oil. Historically, crude oil and natural gas prices have been volatile and subject to fluctuations based on a number of factors beyond our control. More recently, crude oil and natural gas prices have been in the midst of an unprecedented decline due to a combination of factors, including a substantial decline in global demand for oil caused by the COVID-19 pandemic and subsequent mitigation efforts. Despite these challenges, we remain committed to generating long-term value for our stockholders by focusing on capital efficiency, controlling costs and optimizing production.

RECENT DEVELOPMENTS

Impact on Operations of COVID-19 Pandemic and the Current Crude Oil Pricing Environment

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus (referred to as COVID-19) originating in Wuhan, China and the risks to the international community as the virus spreads globally beyond its point of origin. On March 11, 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.

The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the oil and gas industry, and the full impact of the outbreak continues to evolve. The adverse economic effects of the COVID-19 outbreak have materially decreased demand for crude oil based on the restrictions in place by governments trying to curb the outbreak and changes in consumer behavior. This has led to a significant global oversupply of oil and consequently a substantial decrease in crude oil prices. In April 2020, countries within OPEC+, which includes Gabon, reached an agreement to cut oil production to reduce the gap between excess supply and demand, in an effort to stabilize the international oil market. Gabon has undertaken measures to comply with such OPEC+ production quota agreement and, as a result, the Minister of Hydrocarbons in Gabon requested that we reduce our production. In response to such request from the Minister of Hydrocarbons, in July 2020 we temporarily reduced production from the Etame Marin block through September 30, 2020. With respect to requests related to the three months ended December 31, 2020, the Company plans to comply with such requests primarily through natural declines in production. Despite the recent actions taken by OPEC+, downward pressure on commodity prices has remained and could continue for the foreseeable future, particularly given concerns over available storage capacity for crude oil. The Company does not currently have any commodity derivative instruments in place to mitigate the effects of such price declines, but the Company will consider entering into new commodity derivative instruments from time to time. However, there can be no assurance when, or upon what terms, the Company may enter into any future commodity derivative instruments.

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While we did not incur significant disruptions to operations during the nine months ended September 30, 2020 as a result of the COVID-19 pandemic, we are unable to predict the impact that the COVID-19 pandemic will have on us in the future, including our financial position, operating results, liquidity and ability to obtain financing in future reporting periods, due to numerous uncertainties. These uncertainties include the severity of the virus, the duration of the outbreak, governmental or other actions taken to combat the virus (which could include limitations on our operations or the operations of our customers and vendors), and the effect that the COVID-19 pandemic and the current crude oil price wars among global suppliers will have on the demand for crude oil. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations.

Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, and we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.

In response to the COVID-19 outbreak and the current pricing environment, we have taken the following measures:

put in place social distancing measures at our work sites;

actively screened and monitored employees and contractors that come on to our facilities including testing and quarantines with onsite medical supervision;

engaged in regular company-wide COVID-19 updates to keep employees informed of key developments;

implemented cost cutting measures with vendors;

implemented sharing certain costs, such as shipping vessels, helicopter, and personnel with other operators in the region and

ceased or deferred certain discretionary capital spending.

We expect to continue to take proactive steps to manage any disruption in our business caused by COVID-19 and to protect the health and safety of our employees. However, the health and safety measures we and our vendors have taken have resulted in us incurring higher costs. As a result of these factors and the conditions described above, we currently expect 2020 may be one of the most uncertain and disruptive years that the industry has ever seen. Accordingly, the results presented herein are not necessarily indicative of future operating results, and our results in future quarters this year may not be comparable to the same quarters in prior years.

Recent Operational Updates

In September 2019, VAALCO commenced its 2019/2020 drilling campaign. During the remainder of 2019, the Company drilled one development well and one appraisal wellbore, and during the first quarter of 2020, we drilled the remaining development well and appraisal wellbore required under the PSC Extension. In addition, we successfully completed drilling the South East Etame 4H development well and brought the well onto production on March 21, 2020.

On September 30, 2020, we began acquiring and processing new three-dimensional (“3-D”) seismic data. We expect the full field 3-D survey will optimize future drilling locations, provide better imaging of existing satellite and infill locations, as well as identify additional upside opportunities. We project the gross cost of both the acquisition and processing of the seismic survey to be between $12.0 million and $15.0 million, or $4.0 million to $5.0 million, net to VAALCO. We plan to fund the costs with cash on hand and through cash from operations

In September 2020, we implemented a planned full-field shutdown that took five days to complete. With the exception of this planned shutdown, we maintained field integrity and our crude oil production schedule in the third quarter without any operational disruptions or reportable accidents despite the challenges presented by the COVID-19 pandemic.

NYSE Noncompliance Notice

On April 22, 2020, we were notified by the New York Stock Exchange (the “NYSE”) that the average closing price of our common stock over the prior 30 consecutive trading days was below $1.00 per share, which is the minimum average closing price required to maintain listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual. On July 1, 2020, we received notification that we regained full compliance with all NYSE continued listing standards.

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ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of four companies. As of September 30, 2020, production operations in the Etame Marin block included ten platform wells, plus three subsea wells across all fields tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the crude oil from a leased FPSO anchored to the seabed on the block. We currently have thirteen producing wells. The FPSO has production limitations of approximately 25,000 barrels of oil per day and 30,000 barrels of total fluids per day. During the three months ended September 30, 2020 and 2019, production from the block was 1,500 MBbls (405 MBbls net) and 1,049 MBbls (283 MBbls net), respectively. During the nine months ended September 30, 2020 and 2019, production from the block was approximately 4,987 MBbls (1,347 MBbls net) and 3,448 MBbls (932 MBbls net), respectively, as discussed below in “Results of Operations”.

Equatorial Guinea

VAALCO acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”) approved our appointment as operator for the Block P interest on November 12, 2019. The Company acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing its working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million to Atlas Petroleum in the event that there is commercial production from Block P, and the EG MMH has approved this assignment. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. VAALCO is in commercial discussions with Levene Hydro c arbon Limited (“Levene”) where VAALCO would assign a portion of its working interest in Block P to Levene and Levene would potentially cover all or substantially all of VAALCO’s cost to drill an exploratory well on Block P. Levene and VAALCO have executed a non-binding Memorandum of Understanding regarding these commercial discussions; however, neither have executed any binding agreements and there can be no certainty a transaction will be completed. Further, approval of the assignment to Levene by the EG MMH must be obtained prior to any transaction being completed. As of September 30, 2020, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. VAALCO and its current and potential future 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. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.

Discontinued Operations - Angola

The Angola segment has been classified as discontinued operations in the condensed consolidated financial statements for all periods presented. See Note 3 to the condensed consolidated financial statements for further discussion.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the nine months ended September 30, 2020 and 2019 are as follows:

|  | Nine Months Ended September 30, |  |
|  | 2020 |  | 2019 |  | Increase (Decrease) in 2020 over 2019
|  | (in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities |  | $ | 22,466 |  | $ | 16,236 |  | $ | 6,230
Net change in operating assets and liabilities |  |  | (3,029) |  |  | 17,488 |  |  | (20,517)
Net cash provided by continuing operating activities |  |  | 19,437 |  |  | 33,724 |  |  | (14,287)
Net cash used in discontinued operating activities |  |  | (376) |  |  | (4,673) |  |  | 4,297
Net cash provided by operating activities |  |  | 19,061 |  |  | 29,051 |  |  | (9,990)
Net cash used in investing activities |  |  | (22,317) |  |  | (3,382) |  |  | (18,935)
Net cash used in financing activities |  |  | (990) |  |  | (2,292) |  |  | 1,302
Net change in cash, cash equivalents and restricted cash |  | $ | (4,246) |  | $ | 23,377 |  | $ | (27,623)

The $6.2 million increase in net cash provided by our operating activities before changes in operating assets and liabilities for the nine months ended September 30, 2020 compared to the same period of 2019 was mainly due to cash settlements received on matured derivative contracts during the nine months ended September 30, 2020 offset by lower revenue between the 2020 and 2019 periods as discussed below in “Results of Operations”. Net decrease of $20.5 million in operating assets and liabilities for the nine months

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ended September 30, 2020 compared to the same period of 2019 was primarily related to decreases in accounts payable, accrued liabilities and foreign income taxes receivable/payable. The decrease of $4.2 million in net cash used in discontinued operating activities is primarily due to the settlement reached in the first quarter of 2019 related to our Angola operations. See Note 3 for further details.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. During the nine months ended September 30, 2020, these expenditures on a cash basis were $22.3 million, primarily related to the 2019/2020 drilling campaign and equipment purchases. This compares to $3.4 million, primarily related to equipment purchases, for the nine months ended September 30, 2019. See “Capital Expenditures” below for further discussion.

Net cash used in financing activities during the nine months ended September 30, 2020 included $1.0 million for treasury stock purchases primarily made under the Company’s stock repurchase plan. Net cash used in financing activities during the nine months ended September 30, 2019 included $2.4 million for treasury stock purchases primarily made under the Company’s stock repurchase plan.

Capital Expenditures

During the nine months ended September 30, 2020, we incurred accrual basis capital expenditures of $10.3 million. These expenditures were primarily related to drilling the South East Etame 4P appraisal wellbore and drilling and completing the South East Etame 4H development well. The Consortium (VAALCO together with the other joint venture owners in the Etame Marin block) completed drilling two development wells and two appraisal wellbores required under the terms of the PSC Extension during the 2019/2020 drilling campaign with the last appraisal wellbore being completed in February 2020.

As a result of the current crude oil price environment and the significant economic disruptions caused by COVID-19, we have ceased or deferred a significant amount of discretionary capital spending; however, as discussed in “Recent Operational Updates” above, we began acquiring and processing 3-D seismic data during the fourth quarter of 2020. We expect any capital expenditures made during the remainder of 2020, including with respect to the seismic data acquisition, will be funded by cash on hand and cash flow from operations. We intend to manage any future capital expenditure levels in view of the existing and expected pricing environment. Under the PSC extension, t he Consortium was required to complete two technical studies by September 16, 2020, which were completed on a timely basis, and at a cost of $1.5 million gross ($0.5 million, net to VAALCO).

Contractual Obligations

See Notes 10 and 11 to the condensed consolidated financial statements as well as Notes 12 and 13 to our 2019 Form 10-K for discussion of our contractual obligations. There were no other material changes in our contractual obligations during the nine months ended September 30, 2020.

Regulatory and Joint Interest Audits

We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Note 10 for further discussion.

Capital Resources

Cash on Hand

At September 30, 2020, we had unrestricted cash of $42.0 million. The unrestricted cash balance includes $6.0 million of cash attributable to non-operating joint venture owner advances. As operator of the Etame Marin block in Gabon, we enter into project related activities on behalf of our working interest joint venture owners. We generally obtain advances from the joint venture owners prior to significant funding commitments.

We currently sell our crude oil production from Gabon under a term contract that began in February 2020 and ends in January 2021. Pricing under the contract is based upon an average of Dated Brent in the month of lifting, adjusted by a fixed differential.

Liquidity

In early March 2020, crude oil prices declined significantly ending at approximately $15 per barrel for Brent crude, as of March 31, 2020, as a result of market concerns about the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. While OPEC and Russia were able to reach an agreement to cut production in April 2020, crude oil prices continued to decline below $20 per barrel for Brent crude as a result of the substantial decline in the global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts. The concerns related to COVID-19 have led to a substantial surplus in the global supply of crude oil, with physical markets showing signs of distress as spot prices were negatively impacted by the lack of available storage capacity. Brent crude prices were approximately $40 per barrel as of September 30, 2020. At September 30, 2020, we did not have c ommodity derivative instruments in place to mitigate the effects of such price declines. This period of extreme economic disruption and low crude oil prices may have a significant adverse impact on our access to sources of liquidity and financial condition.

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Historically, our primary source of liquidity has been cash flows from operations. Despite the lower Brent crude oil prices, based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations to support our other cash requirements through December 2021. We are continuing to evaluate all uses of cash and whether to pursue growth opportunities or preserve our resources in light of ongoing economic conditions. For instance, as discussed above in “Recent Developments”, we have ceased or deferred a significant amount of discretionary capital spending, and we have undertaken certain cost cutting and cost sharing measures. With respect to the acquisition and processing of the seismic survey as discussed above, we estimate the cost to be between $4.0 million to $5.0 million, net to VAALCO. However, the current market environment is highly unpredictable and our future liquidity needs may change suddenly and dramatically.

If we require additional capital funding for capital expenditures, acquisitions or other reasons, we may seek such capital through borrowings under new credit facilities, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. In the current oil price environment, we may experience a substantial decline in our future cash flows and our ability to borrow funds and to obtain additional capital on attractive terms may be severely limited. Further, the availability of capital resources to us on attractive terms may be limited due to the geographic location of our primary producing assets. If we are unable to obtain funds when needed or on acceptable terms or generate sufficient cash from operations, we may be required to severely curtail our operating activities, furlough or lay off employees and take other actions to reduce our operating expenses. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

At December 31, 2019, we had 5.0 MMBbls of estimated net proved reserves, all of which are related to the Etame Marin block offshore Gabon. The current term for exploitation of the reserves in the Etame Marin block ends in September 2028 with rights for two five-year extension periods. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. While both short-term and long-term liquidity are impacted by crude oil prices, our long-term liquidity also depends upon our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable.

OFF-BALANCE SHEET ARRANGEMENTS

None.

CRITICAL ACCOUNTING POLICIES

There have been no changes to our critical accounting policies subsequent to December 31, 2019.

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2020 Compared to the Three Months Ended September 30, 2019

Net income for the three months ended September 30, 2020 of $7.6 million, compares to net loss of $3.9 million for the same period of 2019.

|  | Three Months Ended September 30, |  |  |
|  | 2020 |  | 2019 |  | Increase/(Decrease)
|  | (in thousands except per bbl information)
Net crude oil sales volume (MBbls) |  |  | 412 |  |  | 279 |  |  | 133
Average crude oil sales price (per Bbl) |  | $ | 43.63 |  | $ | 61.26 |  | $ | (17.63)
Net crude oil revenue |  | $ | 18,256 |  | $ | 17,603 |  | $ | 653
Operating costs and expenses: |  |  |  |  |  |  |  |  |
Production expense |  |  | 8,984 |  |  | 9,836 |  |  | (852)
Exploration expense |  |  | 16 |  |  | — |  |  | 16
Depreciation, depletion and amortization |  |  | 2,212 |  |  | 1,509 |  |  | 703
General and administrative expense |  |  | 2,178 |  |  | 4,738 |  |  | (2,560)
Bad debt expense |  |  | 151 |  |  | 54 |  |  | 97
Total operating costs and expenses |  |  | 13,541 |  |  | 16,137 |  |  | (2,596)
Other operating income (expense), net |  |  | (37) |  |  | 35 |  |  | (72)
Operating income |  | $ | 4,678 |  | $ | 1,501 |  | $ | 3,177

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Crude oil and natural gas revenues increased $0.7 million, or approximately 3.7%, during the three months ended September 30, 2020 compared to the same period of 2019. The increase in revenue is attributable to higher volumes as described below partially offset by lower sales prices.

The revenue changes in the three months ended September 30, 2020 compared to the same period in 2019 identified as related to changes in price or volume, are shown in the table below:

(in thousands) |  |  |  |  |  |
Price |  |  |  |  | $ | (7,264)
Volume |  |  |  |  |  | 8,148
Other |  |  |  |  |  | (231)
|  |  |  |  | $ | 653

|  | Three Months Ended September 30,
|  | 2020 |  | 2019
Gabon net crude oil production (MBbls) |  |  | 405 |  |  | 283
Gabon net crude oil sales (MBbls) |  |  | 412 |  |  | 279
Average realized crude oil price ($/Bbl) |  | $ | 43.63 |  | $ | 61.26
Average Dated Brent spot price* ($/Bbl) |  |  | 42.91 |  |  | 61.95
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

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 during each of the three-month periods ended September 30, 2020 and 2019. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 36,299 and 23,000 barrels at September 30, 2020 and 2019, respectively. The average realized price for the three months ended September 30, 2020 reflects the impact from the significant decline in crude oil prices as discussed above in “Recent Developments.” Production volumes for the three months ended September 30, 2020 were higher than the comparable 2019 period primarily due to the new development wells brought onto production.

Production expenses decreased $0.9 million, or approximately 8.7%, in the three months ended September 30, 2020 compared to the same period of 2019. The decrease in expense was primarily related to a lower workover expense during the third quarter of 2020 compared to the third quarter of 2019. On a per barrel basis, production expense, excluding workover expense, for the three months ended September 30, 2020 decreased to $22.21 per barrel from $34.01 per barrel for the three months ended September 30, 2019 primarily as a result of an increase in sales volumes. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic we have incurred approximately $0.4 million in higher costs related to the proactive measures taken in response to the pandemic.

Depreciation, depletion and amortization costs increased $0.7 million, or approximately 46.6% due to higher depletable costs associated with new wells brought online during the fourth quarter of 2019 and first quarter of 2020.

General and administrative expenses decreased $2.6 million, or approximately 54.0% in the three months ended September 30, 2020 compared to the same period of 2019. The decrease in expense was primarily related to a $1.5 million decrease in SARs expense. SARs liability awards are measured at fair value. The primary driver of changes in the fair value of these awards is changes in the Company’s stock price. See Note 14 to our condensed consolidated financial statements for further discussion. Professional, legal and accounting and auditing fees were also lower in the three months ended September 30, 2020 compared to the same period of 2019, which included fees related to the Company’s listing on the London Stock Exchange.

Bad debt (recovery) expense was higher between the three months ended September 30, 2020 and 2019 primarily due to bad debt expense associated with the VAT allowance.

Other operating expense, net increased $0.1 million in the three months ended September 30, 2020 compared to the same period of 2019.

Interest income, net for the three months ended September 30, 2020 and 2019 both relate to interest income on cash balances.

Derivative instruments gain, net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. We did not have in place any derivative instruments to hedge against declining crude oil prices after June 2020. The $2.3 million gain during the three months ended September 30, 2019 was a result of the decrease in the price of Dated Brent crude oil during the period.

Other, net for the three months ended September 30, 2020 and 2019 primarily consists of foreign currency gains (losses) as discussed in Note 1 to the condensed consolidated financial statements.

Income tax expense (benefit) for the three months ended September 30, 2020 was $(2.8) million. This is comprised of $(5.3) million of deferred tax benefit and a current tax expense of $2.5 million. The deferred income tax expense for the three months ended September 30, 2020 included a $5.4 million decrease to the valuation allowances on U.S. and Gabonese deferred tax assets offset by a

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$0.1 million deferred tax expense. Income tax expense for the three months ended September 30, 2019, includes $5.1 million of deferred tax expense and a current tax expense of $2.6 million. For both the three months ended September 30, 2020 and 2019, our overall effective tax rate was impacted by non-deductible items associated with operations and deducting foreign taxes rather than crediting them for United States tax purposes.

Income (loss) from discontinued operations for the three months ended September 30, 2020 and 2019 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The income (loss) from discontinued operations for the three months ended September 30, 2020 and 2019 was primarily related to Angola administration costs.

Nine Months Ended September 30, 2020 Compared to the Nine Months Ended September 30, 2019

Net loss for the nine months ended September 30, 2020 of $44.6 million, compares to net income of $1.5 million for the same period of 2019. The decrease in operating results for the nine months ended September 30, 2020 compared to the same period in 2019 was primarily due to $30.6 million in impairment of proved crude oil and natural gas properties and a $37.4 million increase in the valuation allowance on deferred tax assets. Also contributing to the decrease were lower revenues as a result of receiving lower crude oil prices partially offset by higher sales volumes. The net income for the nine months ended September 30, 2019 was inclusive of income from discontinued operations of $5.4 million.

million

|  | Nine Months Ended September 30, |  |  |
|  | 2020 |  | 2019 |  | Increase/(Decrease)
|  | (in thousands except per bbl information)
Net crude oil sales volume (MBbls) |  |  | 1,337 |  |  | 933 |  |  | 404
Average crude oil sales price (per Bbl) |  | $ | 39.90 |  | $ | 65.00 |  | $ | (25.10)
Net crude oil revenue |  | $ | 54,619 |  | $ | 62,598 |  | $ | (7,979)
Operating costs and expenses: |  |  |  |  |  |  |  |  |
Production expense |  |  | 30,859 |  |  | 27,874 |  |  | 2,985
Exploration expense |  |  | 16 |  |  | — |  |  | 16
Depreciation, depletion and amortization |  |  | 8,116 |  |  | 4,971 |  |  | 3,145
Impairment of proved crude oil and natural gas properties |  |  | 30,625 |  |  | — |  |  | 30,625
General and administrative expense |  |  | 5,951 |  |  | 11,905 |  |  | (5,954)
Bad debt expense |  |  | 1,140 |  |  | 30 |  |  | 1,110
Total operating costs and expenses |  |  | 76,707 |  |  | 44,780 |  |  | 31,927
Other operating expense, net |  |  | (883) |  |  | (4,401) |  |  | 3,518
Operating income (loss) |  | $ | (22,971) |  | $ | 13,417 |  | $ | (36,388)

Crude oil and natural gas revenues decreased $8.0 million, or approximately 12.7%, during the nine months ended September 30, 2020 compared to the same period of 2019. The decrease in revenue is attributable to lower sales prices as described below partially offset by higher volumes.

The revenue changes in the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, identified as related to changes in price or volume, are shown in the table below:

(in thousands) |  |  |  |  |  |
Price |  |  |  |  | $ | (33,559)
Volume |  |  |  |  |  | 26,260
Other |  |  |  |  |  | (680)
|  |  |  |  | $ | (7,979)

|  | Nine Months Ended September 30,
|  | 2020 |  | 2019
Gabon net crude oil production (MBbls) |  |  | 1,347 |  |  | 932
Gabon net crude oil sales (MBbls) |  |  | 1,337 |  |  | 933
Average realized crude oil price ($/Bbl) |  | $ | 39.90 |  | $ | 65.00
Average Dated Brent spot price* ($/Bbl) |  |  | 41.15 |  |  | 64.65
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

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 nine and ten liftings during the nine months ended September 30, 2020 and 2019, respectively. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 36,299 and 23,000 barrels at September 30, 2020 and 2019, respectively. The average realized price for the nine

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months ended September 30, 2020 reflects the impact from the significant decline in crude oil prices as discussed above in “Recent Developments.” Production volumes for the nine months ended September 30, 2020 were higher than the comparable 2019 period primarily due to the new development wells brought onto production.

Production expenses increased $3.0 million, or approximately 10.7%, in the nine months ended September 30, 2020 compared to the same period of 2019. The increase in expense was primarily related to higher workover expense of $2.2 million during the nine months ended September 30, 2020 related to two workovers and to a lesser extent higher FPSO and personnel costs in 2020 compared to 2019. On a per barrel basis, production expense, excluding workover expense, for the nine months ended September 30, 2020 decreased to $21.10 per barrel from $29.36 per barrel for the nine months ended September 30, 2019 primarily as a result of an increase in sales volumes. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $1.2 million in higher costs related to the proactive measures taken in response to the pandemic.

Depreciation, depletion and amortization costs increased $3.1 million, or approximately 63.3% due to higher depletable costs associated with new wells brought online during the fourth quarter of 2019 and first quarter of 2020.

Impairment of proved crude oil and natural gas properties for the nine months ended September 30, 2020 of $30.6 million was the result of declining forecasted crude oil prices. See Note 7 for further discussion.

General and administrative expenses decreased $6.0 million, or approximately 50.0% in the nine months ended September 30, 2020 compared to the same period of 2019. The decrease in expense was primarily related to a $4.6 million decrease in SARs expense and $0.3 million decrease in stock-based compensation from equity awards. SARs liability awards are measured at fair value. The primary driver of changes in the fair value of these awards is changes in the Company’s stock price. Professional fees were also lower in the nine months ended September 30, 2020 compared to the same period in 2019, which included 2019 legal fees related to the Company’s listing on the London Stock Exchange. See Note 14 to our condensed consolidated financial statements for further discussion.

Bad debt (recovery) expense was higher between the nine months ended September 30, 2020 and 2019 primarily due to bad debt expense associated with the VAT allowance.

Other operating expense, net decreased $3.5 million in the nine months ended September 30, 2020 compared to the same period of 2019. The decrease in expense was primarily related to a $4.4 million charge that was recorded during the second quarter of 2019 for an agreement in principle to resolve a legacy issue related to findings from Etame joint ventures owners’ audits for the periods from 2007 through 2016.

Interest income (expense), net for the nine months ended September 30, 2020 and 2019 both relate to interest income on cash balances.

Derivative instruments gain, net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. The $6.6 million gain for the nine months ended September 30, 2020 is a result of the decrease in the price of Dated Brent crude oil during the nine months ended September 30, 2020 as compared to lower decrease in the price of Dated Brent crude oil that resulted in a $2.3 million gain during the comparable prior year period. Our derivative instruments only covered a portion of our production through June 2020. We do not have in place any derivative instruments to hedge against declining crude oil prices.

Other, net for the nine months ended September 30, 2020 and 2019 primarily consists of foreign currency gains (losses) as discussed in Note 1 to the condensed consolidated financial statements.

Income tax expense for the nine months ended September 30, 2020 was $28.5 million. This is comprised of $27.0 million of deferred tax expense and a current tax expense of $1.5 million. The deferred income tax expense for the nine months ended September 30, 2020 included a $37.4 million charge to increase the valuation allowances on U.S. and Gabonese deferred tax assets offset by a $(10.5) million deferred tax benefit. The current tax expense of $1.5 million includes a $3.8 million favorable crude oil price adjustment as a result of the change in value of the government’s allocation between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $5.3 million for the period. Income tax expense for the nine months ended September 30, 2019, includes $12.7 million of deferred tax expense and a current tax provision of $6.9 million. The deferred income tax expense for the nine months ended September 30, 2019 included a $4.8 million charge to increase the valuation allowances on U.S. deferred tax assets due to a decrease in future estimated taxable earnings primarily as a result of lower crude oil prices. For the nine months ended September 30, 2019, our overall effective tax rate was impacted by non-deductible items associated with operations and deducting foreign taxes rather than crediting them for United States tax purposes. Additionally, the $4.4 million charge for settlement of joint venture owners’ audits that was recorded during second quarter 2019 was treated as discrete to the quarter and for which only an income tax benefit at the U.S. tax rate of 21% was provided.

Gain (loss) from discontinued operations for the nine months ended September 30, 2020 and 2019 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The gain from discontinued operations for the nine months ended September 30, 2019 was related to recording a $5.7 million after-tax gain on the finalized Angola settlement as discussed in Note 3 to the condensed consolidated financial statements.

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ITE M 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

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

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the “Central African CFA Franc”, or “XAF”), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of September 30, 2020, we had net monetary assets of $6.8 million (XAF 3,800 million) (net to VAALCO) denominated in XAF. A 10% weakening of the CFA Franc relative to the U.S. dollar would have a $0.6 million reduction in the value of these net assets. For the three and nine months ended September 30, 2020, we had expenditures of approximately $2.9 million and $8.8 million, respectively, (net to VAALCO), denominated in XAF.

Commodity Price Risk

Our major market risk exposure continues to be the prices received for our crude oil production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and unpredictable in recent years, and this volatility may continue. More recently, crude oil and natural gas prices have been in the midst of an unprecedented decline due to a combination of factors, including a substantial decline in global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts. We cannot predict the ultimate long-term impact on crude oil prices as a result of these factors.

Sustained low crude oil prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms. If crude oil sales were to remain constant at the most recent quarterly sales volumes of 412 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $2.1 million decrease per quarter ($8.4 million annualized) in revenues and operating income and a $1.9 million decrease per quarter ($7.5 million annualized) in net income.

As of September 30, 2020, we did not have any crude oil swaps outstanding. In the past, we have used derivative instruments as an economic hedge against declines in crude oil prices; however, such instruments were not designated as hedges for accounting purposes. Our derivative instruments only covered a portion of our production through June 2020 and have expired.

ITEM 4. CO NTRO LS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of September 30, 2020, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective.﻿

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

The internal control environment was impacted by the stay-at-home requirements for our Houston and Gabon staff which began in mid-March and continues through the date of this report. While modifications were made to the manner in which controls were performed, these changes did not have a material effect on our internal control over financial reporting, and there were no changes in our internal control over financial reporting that occurred during the three months ended September 30, 2020 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

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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 material to our business.

ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report on 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.

The following risk factors represent material changes to the risk factors disclosed under Item 1A. “Risk Factors” in our 2019 Form 10-K. For additional information concerning of our potential risks and uncertainties, see the information in Item 1A “Risk Factors” in our 2019 Form 10-K.

Production cuts mandated by the government of Gabon, a member of OPEC, could adversely affect our revenues, cash flow and results of operations.

After terminating its membership with OPEC in 1995, Gabon rejoined OPEC as a full member in July 2016. Historically and from time to time, members of OPEC have entered into agreements to reduce worldwide production of crude oil, including the agreement among OPEC member countries and other leading allied producing countries (collectively, “OPEC+”) reached in April 2020 to reduce the gap between excess supply and demand in an effort to stabilize the international oil market. Gabon has undertaken measures to comply with such OPEC+ production quota agreement. As a result, the Minister of Hydrocarbons in Gabon has requested that we reduce our production through December 2020 in compliance with the OPEC+ mandate, and we have taken measures to reduce our production. A reduction in VAALCO’s crude oil production or export activities for a substantial period could materially and adversely affect our revenues, cash flow and results of operations.

Crude oil and natural gas prices are highly volatile and a depressed price regime, if prolonged, may negatively affect our financial results.

Our revenues, cash flow, profitability, crude oil and natural gas reserves value and future rate of growth are substantially dependent upon prevailing prices for crude oil and natural gas. Our ability to enter into debt financing arrangements and to obtain additional capital on reasonable terms is also substantially dependent on crude oil and natural gas prices.

Historically, world-wide crude oil and natural gas prices and markets have been volatile and may continue to be volatile in the future. Prices for crude oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include, but are not limited to, increases in supplies from U.S. shale production, international political conditions, including uprisings and political unrest in the Middle East and Africa, the domestic and foreign supply of crude oil and natural gas, actions by OPEC member countries and other state-controlled oil companies to agree upon and maintain crude oil price and production controls, the level of consumer demand that is impacted by economic growth rates, weather conditions, domestic and foreign governmental regulations and taxes, the price and availability of alternative fuels, technological advances affecting energy consumption, the health of international economic and credit markets, and changes in the level of demand resulting from global or national health epidemics and concerns, such as the ongoing COVID-19 pandemic. In addition, various factors, including the effect of federal, state and foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect our ability to market our crude oil and natural gas production. Moreover, we do not currently have in place any commodity price hedging arrangements to mitigate the effects of volatility in crude oil and natural gas prices.

A combination of factors, including a substantial decline in global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts, as well as market concerns about the ability of OPEC+ to agree on a perceived need to implement production cuts in response to weaker worldwide demand, caused an unprecedented decline in crude oil and natural gas prices during the first six months of 2020. Although crude oil prices increased to approximately $40 per barrel for Brent crude as of September 30, 2020, adverse economic effects caused by the COVID-19 pandemic, as well as the various other factors described above, could result in additional price declines.

In a period of depressed or declining crude oil and natural gas prices, such as the significant declines in crude oil and natural gas prices during the first six months of 2020, we are subject to numerous risks, including but not limited to the following:

our revenues, cash flows and profitability may decline substantially, which could also indirectly impact expected production by reducing the amount of funds available to engage in exploration, drilling and production;

third parties’ confidence in our commercial or financial ability to explore and produce crude oil and natural gas could erode, which could impact our ability to execute on our business strategy;

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our suppliers, hedge counterparties (if any), vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us;

we may take measures to preserve liquidity, such us our decision to cease or defer discretionary capital expenditures for the remainder of 2020; and

it may become more difficult to retain, attract or replace key employees.

The occurrence of certain of these events may have a material adverse effect on our business, results of operations and financial condition.

Events outside of our control, such as the ongoing COVID-19 pandemic, could adversely impact our business, results of operations, cash flows, financial condition and liquidity.

We face risks related to epidemics, outbreaks or other public health events that are outside of our control. The global or national outbreak of an illness or any other communicable disease, or any other public health crisis, including the COVID-19 pandemic, could significantly disrupt our business and operational plans and adversely affect our results of operations, cash flows, financial condition and liquidity. Although we are not able to enumerate all potential risks to our business resulting from the ongoing COVID-19 pandemic, we believe that such risks include, but are not limited to, the following:

we may experience disruption to our supply chain for materials essential to our business, including restrictions on importing and exporting products;

we may receive notices from customers, suppliers and other third parties arguing that their non-performance under our contracts with them is permitted as a result of force majeure or other reasons;

we may face cybersecurity issues, as digital technologies may become more vulnerable and experience a higher rate of cyberattacks in the current environment of remote connectivity;

we may face litigation risk and possible loss contingencies related to COVID-19 and its impact, including with respect to commercial contracts, employee matters and insurance arrangements;

we may be required to implement reductions of our workforce to adjust to market conditions, including severance payments, retention issues, and we may face an inability to hire employees when market conditions improve;

we may incur additional asset impairments;

we may experience infections and quarantining of our employees and other third parties in areas in which we operate;

we have faced and may continue to face logistical challenges, including those resulting from border closures and travel restrictions, as well as the possibility that our ability to continue production may be interrupted, limited or curtailed if workers and/or materials are unable to reach our offshore platforms and FPSO charter vessel or our counterparties are unable to lift crude oil from our FPSO charter vessel;

we may be subject to actions undertaken by national, regional and local governments and health officials to contain the virus or treat its effects, including travel restrictions and temporary closures of our facilities, that could result in operations and supply chains being interrupted, slowed, or rendered inoperable; and

we may experience a structural shift in the global economy and its demand for crude oil and natural gas as a result of changes in the way people work, travel and interact, or in connection with a global recession or depression.

We cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist, the full extent of the impact they will have on our business, results of operations, cash flows, financial condition and liquidity, or the pace or extent of any subsequent recovery. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments – Impact on Operations of COVID-19 Pandemic and the Current Crude Oil Pricing Environment”.

Material declines in crude oil and natural gas prices have required us, and may require us in the future, to take write-downs in the value of our crude oil and natural gas properties.

The estimated future net revenues attributable to our net proved reserves are prepared in accordance with current SEC guidelines and are not intended to reflect the fair market value of our reserves. In accordance with the rules of the SEC, our reserve estimates are prepared using the average price received for crude oil and natural gas based on closing prices of the average of the first day of the month price over the twelve-month period prior to the end of the reporting period. However, for the purpose of impairment analysis, the estimated future net revenues attributable to our net proved reserves are prepared in accordance with ASC 932 and are priced using forecasted realized prices at the end of the quarter. During 2019, 2018 and 2017, no impairments were necessary with respect to the Etame Marin block. However, during the first quarter of 2020, the undiscounted cash flows related to the Etame, Avouma, Ebouri and South East Etame/North Tchibala fields were less than the book values for these fields resulting in the Company recording an impairment loss of $30.6 million to write down the Company’s investment in the Etame Marin block.

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As described elsewhere herein, the COVID-19 pandemic and resulting substantial decline in the demand for crude oil coupled with the current global oversupply of crude oil has resulted in a substantial decline in the price of crude oil. If crude oil prices decline further, we expect that the estimated quantities and present values of our reserves will be reduced, which may necessitate further write-downs. The current low crude oil price environment has also caused a decline in the estimated fair value and/or the economic viability of projects associated with our undeveloped leasehold costs for the Etame Marin block and the Equatorial Guinea Block P. Any future write-downs or impairments could have a material adverse impact on our results of operations.

The choice of forum provisions in our Third Amended and Restated Bylaws (the “Bylaws”) could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us.

Our Bylaws provide that the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, the federal district court for the District of Delaware) shall be the sole and exclusive forum for: (i) any derivative action or proceeding brought in the name or right of the Company or on its behalf, (ii) any action asserting a claim for breach of a fiduciary duty owed by any director, officer, employee, stockholder or other agent of the Company to the Company or the Company’s stockholders, (iii) any action arising or asserting a claim arising pursuant to any provision of the General Corporation Law of Delaware (the “DGCL”) or any provision of the Company’s Restated Certificate of Incorporation, as amended (the “Charter”), or the Bylaws or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware or (iv) any action asserting a claim governed by the internal affairs doctrine, including, without limitation, any action to interpret, apply, enforce or determine the validity of the Charter or the Bylaws. Nonetheless, pursuant to our Bylaws, the foregoing provisions will not apply to suits brought to enforce a duty or liability created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. Our Bylaws further provide that u nless the Company consents in writing to the selection of an alternative forum, the federal district courts of the United States shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act of 1933, as amended (the “Securities Act”). Under the Securities Act, federal and state courts have concurrent jurisdiction over all suits brought to enforce any duty or liability created by the Securities Act, and stockholders cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Accordingly, there is uncertainty as to whether a court would enforce such a forum selection provision as written in connection with claims arising under the Securities Act. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of the Company will be deemed to have notice of and have consented to the provisions of our Bylaws related to choice of forum. The choice of forum provisions in our Bylaws may limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us. Additionally, the enforceability of choice of forum provisions in other companies’ governing documents has been challenged in legal proceedings, and it is possible that, in connection with any applicable action brought against us, a court could find the choice of forum provisions contained in our Bylaws to be inapplicable or unenforceable in such action. If so, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, results of operations, and financial condition.

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ITE M 6. EXHIBITS

(a) Exhibits

3.1 | Certificate of Incorporation as amended through May 7, 2014 (filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014 and incorporated herein by reference).
3.2 | Third Amended and Restated Bylaws (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 4, 2020 and incorporated herein by reference).
31.1(a) | Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a) | Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b) | Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b) | Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a) | Inline XBRL Instance Document.
101.SCH(a) | Inline XBRL Taxonomy Schema Document.
101.CAL(a) | Inline XBRL Calculation Linkbase Document.
101.DEF(a) | Inline XBRL Definition Linkbase Document.
101.LAB(a) | Inline XBRL Label Linkbase Document.
101.PRE(a) | Inline XBRL Presentation Linkbase Document.
104 | Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101).

(a) Filed herewith

(b) Furnished herewith

* Management contract or compensatory plan or arrangement.

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SIGNATURE

Pursuant to 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)

By | : | /s/ Elizabeth D. Prochnow
|  | Elizabeth D. Prochnow
|  | Chief Financial Officer (duly authorized officer and principal financial officer)

Dated: November 5, 2020

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