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~~June 30, ~~2017~~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


~~Delaware~~		~~76‑0274813~~
(State or other jurisdiction of ~~Incorporation~~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 ~~and posted on its corporate website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes ☒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‑~~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~~July 31, ~~2017,~~2020, there were outstanding ~~58,818,031~~57,456,139 shares of common stock, $0.10 par value per share, of the registrant.

Table of Contents

VAALCO ENERGY, INC. AND SUBSIDIARIES

Table of Contents



PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets
~~September~~June 30, ~~2017~~2020 and December 31, ~~2016~~2019	3
Condensed Consolidated Statements of Operations
Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019	4
Condensed Consolidated Statements of Shareholders’ Equity
Three and Six Months Ended June 30, 2020 and 2019	5
Condensed Consolidated Statements of Cash Flows
~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019	5 6
Notes to Condensed Consolidated Financial Statements	6 8
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18 28
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26 38
ITEM 4. CONTROLS AND PROCEDURES	26 39
PART II. OTHER INFORMATION	27 39
ITEM 1. LEGAL PROCEEDINGS	27 39
ITEM 1A. RISK FACTORS	28 39
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES	42
ITEM 6. EXHIBITS	29 43

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

‎

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~(UNAUDITED)~~

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

~~(Unaudited)~~

~~(in thousands, except number of shares and par value amounts)~~


	September 30, 2017		December 31, 2016		June 30, 2020		December 31, 2019
ASSETS					(in thousands)
Current assets:
Cash and cash equivalents	$	18,863	$	20,474	$	44,841	$	45,917
Restricted cash		829		741		1,090		911
Receivables:
Trade		7,203		6,751		9,521		14,335
Accounts with partners, net of allowance of $0.5 million at September 30, 2017 and December 31, 2016		2,748		3,297
Accounts with joint venture owners, net of allowance of $0.0 million and $0.5 million, respectively						134		2,714
Other		1		120		2,350		1,517
Crude oil inventory		1,160		913		853		1,072
Prepayments and other		2,952		4,040		3,445		3,292
Current assets - discontinued operations		2,773		2,139
Total current assets		36,529		38,475		62,234		69,758
Property and equipment - successful efforts method:
Crude oil and natural gas properties and equipment - successful efforts method:
Wells, platforms and other production facilities		389,204		389,231		442,665		422,651
Work-in-progress						—		7,378
Undeveloped acreage		10,000		10,000		21,476		23,771
Equipment and other		10,318		9,779		10,184		11,157
		409,522		409,010		474,325		464,957
Accumulated depreciation, depletion, amortization and impairment		(385,617)		(380,991)		(432,977)		(396,699)
Net property and equipment		23,905		28,019
Net crude oil and natural gas properties, equipment and other						41,348		68,258
Other noncurrent assets:
Restricted cash		967		918		925		925
Value added tax and other receivables, net of allowance of $6.2 million and $4.7 million at September 30, 2017 and December 31, 2016, respectively		6,624		5,110
Value added tax and other receivables, net of allowance of $1.9 million and $1.0 million, respectively						3,812		3,683
Right of use operating lease assets						27,918		33,383
Deferred tax assets						—		24,159
Abandonment funding		8,510		8,510		11,420		11,371
Total assets	$	76,535	$	81,032	$	147,657	$	211,537

LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	13,849	$	19,096	$	9,250	$	15,897
Accounts with joint venture owners						9,259		—
Accrued liabilities and other		10,098		10,506		16,299		29,773
Current portion of long term debt		7,500		7,500
Operating lease liabilities - current portion						12,274		11,990
Foreign taxes payable						3,368		5,740
Current liabilities - discontinued operations		15,400		18,452		48		350
Total current liabilities		46,847		55,554		50,498		63,750
Asset retirement obligations		19,202		18,612		16,643		15,844
Operating lease liabilities - net of current portion						15,631		21,371
Deferred tax liabilities						8,098		—
Other long term liabilities		284		284		56		852
Long term debt, excluding current portion		3,483		6,940
Total liabilities		69,816		81,390		90,926		101,817
Commitments and contingencies (Note 6)
Shareholders’ equity (deficit):
Preferred stock, none issued, 500,000 shares authorized, $25 par value		—		—
Common stock, 66,382,243 and 66,109,565 shares issued $0.10 par value, 100,000,000 shares authorized		6,638		6,611
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		71,106		70,268		73,739		73,549
Less treasury stock, 7,564,212 and 7,555,095 shares at cost		(37,941)		(37,933)
Accumulated deficit		(33,084)		(39,304)
Total shareholders' equity (deficit)		6,719		(358)
Total liabilities and shareholders' equity (deficit)	$	76,535	$	81,032

Less treasury stock, 10,363,103 and 9,649,216 shares, respectively, at cost						(42,419)		(41,429)
Retained earnings						18,629		70,833
Total shareholders' equity						56,731		109,720
Total liabilities and shareholders' equity					$	147,657	$	211,537

See notes to condensed consolidated financial statements.
‎

Table of Contents

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

~~(Unaudited)~~

~~(in thousands, except per share amounts)~~


	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands, except per share amounts)
Revenues:
Crude oil and natural gas sales	$	17,974	$	25,230	$	36,363	$	44,995
Operating costs and expenses:
Production expense		12,126		9,819		21,875		18,038
Depreciation, depletion and amortization		2,801		1,909		5,904		3,462
Impairment of proved crude oil and natural gas properties		—		—		30,625		—
General and administrative expense		3,019		2,728		3,773		7,167
Bad debt (recovery) expense and other		179		5		989		(24)
Total operating costs and expenses		18,125		14,461		63,166		28,643
Other operating expense, net		(815)		(4,399)		(846)		(4,436)
Operating income (loss)		(966)		6,370		(27,649)		11,916
Other income (expense):
Derivative instruments gain (loss), net		(756)		1,911		6,583		(1)
Interest income, net		11		201		127		388
Other, net		47		(145)		16		(383)
Total other income (expense), net		(698)		1,967		6,726		4
Income (loss) from continuing operations before income taxes		(1,664)		8,337		(20,923)		11,920
Income tax expense (benefit)		(2,249)		9,208		31,229		11,961
Income (loss) from continuing operations		585		(871)		(52,152)		(41)
Income (loss) from discontinued operations, net of tax		11		(162)		(52)		5,509
Net income (loss)	$	596	$	(1,033)	$	(52,204)	$	5,468

Basic net income (loss) per share:
Income (loss) from continuing operations	$	0.01	$	(0.01)	$	(0.90)	$	0.00
Income (loss) from discontinued operations, net of tax		0.00		0.00		0.00		0.09
Net income (loss) per share	$	0.01	$	(0.01)	$	(0.90)	$	0.09
Basic weighted average shares outstanding		57,456		59,801		57,716		59,716
Diluted net income (loss) per share:
Income (loss) from continuing operations	$	0.01	$	(0.01)	$	(0.90)	$	0.00
Income (loss) from discontinued operations, net of tax		0.00		0.00		0.00		0.09
Net income (loss) per share	$	0.01	$	(0.01)	$	(0.90)	$	0.09
Diluted weighted average shares outstanding		57,594		59,801		57,716		59,716

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016
Revenues:

Oil and natural gas sales

$
18,178

$
14,635

$
59,869

$
44,458
Operating costs and expenses:

Production expense

10,336

7,162

28,148

25,756
Exploration expense

4

2

4

4
Depreciation, depletion and amortization

1,700

1,607

5,539

5,787
General and administrative expense

2,463

1,588

8,654

7,839
Impairment of proved properties

—

88

—

88
Other operating expense

—

324

—

9,959
General and administrative related to shareholder matters

—

85

—

(350)
Bad debt expense and other

(49)

63

232

577
Total operating costs and expenses

14,454

10,919

42,577

49,660
Other operating income (expense), net

(3)

(26)

164

(8)
Operating income (loss)

3,721

3,690

17,456

(5,210)
Other expense:

Interest expense, net

(327)

(327)

(1,108)

(2,285)
Other, net

(793)

(149)

(571)

(533)
Total other expense

(1,120)

(476)

(1,679)

(2,818)
Income (loss) from continuing operations before income taxes

2,601

3,214

15,777

(8,028)
Income tax expense

2,749

2,198

9,039

6,884
Income (loss) from continuing operations

(148)

1,016

6,738

(14,912)
Loss from discontinued operations

(174)

(15,783)

(518)

(7,997)
Net income (loss)

$
(322)

$
(14,767)

$
6,220

$
(22,909)

Basic net income (loss) per share:

Income (loss) from continuing operations

$
0.00

$
0.02

$
0.11

$
(0.25)
Loss from discontinued operations

(0.01)

(0.27)

(0.01)

(0.14)
Net income (loss)

$
(0.01)

$
(0.25)

$
0.10

$
(0.39)
Basic weighted average shares outstanding

58,817

58,708

58,682

58,600
Diluted net income (loss) per share:

Income (loss) from continuing operations

$
0.00

$
0.02

$
0.11

$
(0.25)
Loss from discontinued operations

(0.01)

(0.27)

(0.01)

(0.14)
Net income (loss)

$
(0.01)

$
(0.25)

$
0.10

$
(0.39)
Diluted weighted average shares outstanding

58,817

58,708

58,686

58,600

See notes to condensed consolidated financial statements.
‎

Table of Contents

VA~~ALCO~~VAALCO ENERGY, INC. AND SUBSIDIARIES

~~CONDENSED~~CONDENSED CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~SHAREHOLDERS’ EQUITY (Unaudited)

~~(Unaudited)~~

~~(in thousands)~~

Nine Months Ended September 30,

2017

2016
CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss)

$
6,220

$
(22,909)
Adjustments to reconcile net income (loss) to net cash provided by (used in)
operating activities:

Loss from discontinued operations

518

7,997
Depreciation, depletion and amortization

5,539

5,787
Other amortization

293

1,132
Unrealized foreign exchange (gain) loss

(512)

2,175
Stock-based compensation

933

93
Commodity derivatives loss

971

772
Cash settlements received on matured derivative contracts

195

—
Bad debt provision

232

577
Other operating (income) loss, net

(164)

8
Impairment of proved properties

—

88
Change in operating assets and liabilities:

Trade receivables

(452)

(587)
Accounts with partners

542

18,126
Other receivables

274

12
Crude oil inventory

(247)

(131)
Value added tax and other receivables

(2,783)

(1,526)
Prepayments and other

1,559

(503)
Accounts payable

(5,250)

(24,339)
Accrued liabilities and other

(432)

24
Net cash provided by (used in) continuing operating activities

7,436

(13,204)
Net cash provided by (used in) discontinued operating activities

(4,204)

13,168
Net cash provided by (used in) operating activities

3,232

(36)
CASH FLOWS FROM INVESTING ACTIVITIES:

(Increase) decrease in restricted cash

(137)

15,260
Acquisitions

64

—
Property and equipment expenditures

(1,300)

(12,781)
Proceeds from the sale of oil and gas properties

250

—
Premiums paid

—

(824)
Net cash provided by (used in) continuing investing activities

(1,123)

1,655
Net cash provided by discontinued investing activities

—

—
Net cash provided by (used in) investing activities

(1,123)

1,655
CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from the issuances of common stock

38

—
Treasury shares

(8)

—
Debt issuance costs

—

(93)
Debt repayment

(7,917)

—
Borrowings

4,167

—
Net cash used in continuing financing activities

(3,720)

(93)
Net cash provided by discontinued financing activities

—

—
Net cash used in financing activities

(3,720)

(93)
NET CHANGE IN CASH AND CASH EQUIVALENTS

(1,611)

1,526
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

20,474

25,357
CASH AND CASH EQUIVALENTS AT END OF PERIOD

$
18,863

$
26,883
Supplemental disclosure of cash flow information:

Interest paid, net of capitalized interest

$
811

$
1,046
Income taxes paid

$
12,069

$
6,930
Supplemental disclosure of non-cash investing and financing activities:

Property and equipment additions incurred but not paid at period end

$
379

$
1,990
Asset retirement obligations

$
(103)

$
42


	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


	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

See notes to condensed consolidated financial statements.
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Table of Contents

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


	Six Months Ended June 30,
	2020		2019
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(52,204)	$	5,468
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Income) loss from discontinued operations		52		(5,509)
Depreciation, depletion and amortization		5,904		3,462
Impairment of proved crude oil and natural gas properties		30,625		—
Other amortization		121		121
Deferred taxes		32,271		7,667
Unrealized foreign exchange (gain ) loss		(19)		21
Stock-based compensation		(1,849)		1,620
Cash settlements paid on exercised stock appreciation rights		—		(261)
Derivatives instruments (gain) loss		(6,583)		1
Cash settlements received on matured derivative contracts, net		7,216		1,563
Bad debt (recovery) expense and other		989		(24)
Other operating loss, net		46		37
Operational expenses associated with equipment and other		1,077		(60)
Change in operating assets and liabilities:
Trade receivables		4,814		(1,921)
Accounts with joint venture owners		11,783		4,291
Other receivables		(857)		158
Crude oil inventory		219		232
Prepayments and other		(779)		(1,175)
Value added tax and other receivables		(695)		718
Accounts payable		(5,819)		(730)
Foreign taxes payable		(2,386)		(2,865)
Accrued liabilities and other		(3,333)		3,858
Net cash provided by continuing operating activities		20,593		16,672
Net cash used in discontinued operating activities		(354)		(91)
Net cash provided by operating activities		20,239		16,581
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures		(20,097)		(1,163)
Net cash used in continuing investing activities		(20,097)		(1,163)
Net cash used in discontinued investing activities		—		—
Net cash used in investing activities		(20,097)		(1,163)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock		—		107
Treasury shares		(990)		(352)
Net cash used in continuing financing activities		(990)		(245)
Net cash used in discontinued financing activities		—		—
Net cash used in financing activities		(990)		(245)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(848)		15,173
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		59,124		46,655
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	58,276	$	61,828

See notes to condensed consolidated financial statements.
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Table of Contents

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)


	Six Months Ended June 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	$	1,855	$	7,347
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	3,932	$	3,378
Recognition of right-of-use operating lease assets and liabilities	$	565	$	38,934
Asset retirement obligations	$	359	$	—

See notes to condensed consolidated financial statements.

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Table of Contents

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, ~~we have~~the Company has production operations and ~~conduct development~~conducts exploration activities in Gabon, West Africa. ~~As non-operator, we have~~The Company also has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, ~~we have~~the Company has discontinued operations associated with ~~our~~ activities in Angola, West Africa.

~~Our~~VAALCO’s consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO ~~UK (North Sea), Ltd., VAALCO International, Inc., VAALCO~~ Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited and VAALCO Energy (USA), Inc.

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

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the condensed consolidated financial statements and notes thereto included in ~~our~~the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2019, which ~~include~~includes a summary of the significant accounting policies.

~~Certain reclassifications~~

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 ~~been made~~experienced disruptions in their operations and in markets served. The Company has instituted some and may take additional temporary precautionary measures intended to ~~prior period amounts related~~help ensure the well-being of its employees, minimize business disruption and reduce its costs. Such measures include social distancing measures, actively screening and monitoring employees and contractors that come on to ~~reclassifying material~~the Company’s facilities, negotiated cost reductions with vendors, cost sharing with other operators and ~~supplies~~elimination or deferral of discretionary capital spending. 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 ~~prepayments~~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 ~~conform~~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. Further, in connection with the OPEC+ agreement, the Minister of Hydrocarbons in Gabon requested that the Company reduce its production through September 2020. To comply with such request from the Minister of Hydrocarbons, in July 2020 the Company temporarily reduced production from the Etame Marin block. 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 June 30, 2020, and therefore 0 additional charges or impairments were required in the three months ended June 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 June 30, 2020 and 2019, respectively, each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long- term amounts at June 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 ~~current period presentation. These reclassifications did not affect our consolidated financial results.~~

~~Bad debt~~ ~~– Quarterly, we evaluate our accounts receivable balances to confirm collectability. When collectability is~~amounts shown in ~~doubt, we record an allowance against the accounts receivable and a corresponding income charge for bad debts, which appears in the “Bad debt expense and other” line item of~~ the condensed consolidated statements of ~~operations.~~ cash flows:


	As of June 30,
	2020		2019
	(in thousands)
Cash and cash equivalents	$	44,841	$	48,557
Restricted cash - current		1,090		799
Restricted cash - non-current		925		922
Abandonment funding		11,420		11,550
Total cash, cash equivalents and restricted cash	$	58,276	$	61,828

The ~~majority~~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. Since the March 5, 2019 conversion to local currency, the abandonment funding account has incurred foreign currency losses of $0.2 million, net to VAALCO. 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 ~~balances are with our~~results from sales of crude oil production and joint interest billings to its joint interest owners for their share of expenses on joint venture ~~partners and~~ 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 ~~us.~~the Company. Portions of ~~our~~the Company’s costs in Gabon (including ~~our~~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 (recovery) expense and other” line item of the condensed consolidated statements of operations.

As of ~~September~~June 30, ~~2017,~~2020, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately ~~XAF 20.5 billion (XAF 6.9 billion,~~$11.3 million ($3.8 million, net to VAALCO). As of ~~September~~June 30, ~~2017,~~2020, the exchange rate was XAF~~555.742~~583.1 = $1.00.

In June 2016, we entered into an agreement with the government of Gabon to receive payments related to the outstanding VAT receivable balance, which was approximately XAF 16.3 billion (XAF 4.9 billion, net to VAALCO) as As of December 31, 2015, in thirty-six monthly installments of $0.2 million, net to VAALCO. We received one monthly installment payment in July 2016; however, no further payments have been received. We are in discussions with2019, the ~~Gabonese government regarding the timing of the resumption of payments~~. exchange rate was XAF 585.7 = $1.00.

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, we~~2020, the Company recorded ~~allowances~~a net expense of ~~$ (0.1)~~$0.1 million and ~~$0.2~~$0.9 million, respectively, related to the allowance for bad debt for VAT for which the government of Gabon has not reimbursed us. For the three and ~~nine month periods~~six months ended ~~September~~June 30, ~~2016, we~~2019, the Company recorded ~~allowances~~a net recovery (expense) of ~~$0.1 million~~$(3) thousand and ~~$0.6 million, respectively.~~$29 thousand, respectively, related to the allowance for bad debt for VAT for which the government of Gabon has not reimbursed us. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on ~~profit/loss.~~the Company’s results of operations. Such

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foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2020			2019	2020		2019
	(in thousands)
Allowance for bad debt
Balance at beginning of period	$	(1,725)	$	(1,854)	$	(1,508)	$	(2,535)
Bad debt recovery (charge)		(179)		(5)		(989)		24
Adjustment associated with reversal of allowance on Mutamba receivable		—		—		593		—
Adjustment associated with settlement of customs audit		—		—		—		623
Foreign currency gain (loss)		—		(17)		—		12
Balance at end of period	$	(1,904)	$	(1,876)	$	(1,904)	$	(1,876)

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 (loss), net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations. See Note 8 for further discussion.

Nine Months Ended September 30,

2017

2016

(in thousands)
Allowance for bad debt

Balance at beginning of year

$
(5,211)

$
(4,221)
Charge to cost and expenses

(232)

(577)
Reclassification related to Sojitz acquisition

(694)

—
Foreign currency loss

(583)

(84)
Balance at end of period

$
(6,720)

$
(4,882)

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.

610

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~~General~~Fair value of financial instruments – The Company’s assets and ~~administrative related~~liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets, accounts payable, SARs and guarantee. 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 ~~shareholder matters~~ ~~– General~~the Company’s other financial instruments included in current assets and ~~administrative expenses related~~liabilities, the carrying value of each financial instrument approximates fair value primarily due to ~~shareholder matters~~the short-term maturity of these instruments. There were 0 transfers between levels for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016 represent~~2020 and 2019.


			As of June 30, 2020
	Balance Sheet Line		Level 1		Level 2		Level 3		Total
			(in thousands)
Liabilities
SARs liability		Accrued liabilities	$	—	$	1,380	$	—	$	1,380
SARs liability		Other long-term liabilities		—		56		—		56
			$	—	$	1,436	$	—	$	1,436

			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.

Capitalization – 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 (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) 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 ~~shareholder litigation~~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 ~~was settled~~the carrying amount of such properties may not be recoverable. If the sum 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

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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 ~~April 2016. For 2016,~~ the ~~amounts also include~~impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates the ~~offsetting insurance proceeds~~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 expenses or general and administrative expenses in the condensed consolidated financial statements. See Note 11 for further discussion.

Asset retirement obligations (“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. The 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. The 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 ~~matters.~~ 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” determined based on daily production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame 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 – The 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 would impact the Company’s tax liability in any given year. The 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 liabilities in the various jurisdictions are determined. We also record as income tax expense the increase or decrease in the value of

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the government’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, it 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~~Yet Adopted

In ~~May 2017,~~December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU No. ~~2017-09, Compensation – Stock Compensation~~2019-12, Income Taxes (Topic ~~718): Scope of Modification~~740: Simplifying the Accounting ~~(ASU 2017-09) to clarify when to account~~ for ~~a change~~Income Taxes (“ASU 2019-12”), which removes certain exceptions to the ~~terms or conditions of a share-based payment award as a modification. Under~~general principles in Topic 740. ASU ~~2017-09, modification accounting~~2019-12 is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments in ASU 2017-09 are effective for ~~all entities for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to an award modified on or after~~ the ~~adoption date. We are currently evaluating the provisions of ASU 2017-09 and are assessing its potential impact on our financial position, results of operations, cash flows and related disclosures.~~

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

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”), which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for fiscal years beginning after December 15, ~~2017, and interim periods within those fiscal years. We are~~2020, with early adoption permitted. The Company is currently evaluating ~~the provisions of~~ this guidance ~~and are assessing its potential~~to determine the impact ~~on our cash flows and related disclosures. Due to the nature of this accounting standards update, this~~it may have ~~an impact~~ on ~~items reported in our statements of cash flows, but no impact is expected on our~~its condensed consolidated financial ~~position, results of operations or related disclosures as a result of implementation.~~statements.

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

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including ~~our~~the Company’s trade and ~~partner~~joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date ~~which~~that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model ~~which~~that increases the allowance when losses are probable. ~~This change is~~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. ~~We are currently evaluating the provisions~~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. The Company plans to defer the implementation of ASU 2016-13, and related updates, until January 2023.

In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting (Topic 848). This ASU 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 ~~assessing its~~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. The ASU 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 this ASU 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, is not expected to have a material impact on ~~our~~ the Company's financial statements.

Table of Contents

In March 2020, the FASB issued ASU 2020-03 - Codification Improvements to Financial Instruments. This ASU improves and clarifies various financial instruments topics, including the CECL standard. The ASU 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 this ASU 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 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 itsfinancial position, results of operations, cash flows and related disclosures.

In ~~February 2016,~~August 2018, the FASB issued ASU ~~No. 2016-02, Leases~~2018-13, Fair Value Measurement (Topic 842) (“ASU 2016-02”), which amends the accounting standards for leases. ASU 2016-02 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar820): Disclosure Framework – Changes to the ~~classification criteria~~Disclosure Requirements for ~~distinguishing between capital leases and operating leases in~~Fair Value Measurement (“ASU 2018-13”). This ASU modifies the previous guidance. Certain aspects of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessorsdisclosure requirements for fair value measurements. ASU 2018-13 removes the requirement to ~~meet the objective of enabling users of financial statements to assess~~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 ~~uncertainty~~(3) the valuation processes for Level 3 fair value measurements. ASU 2018-13 requires disclosure of ~~cash flows arising from leases. In transition, lessees~~changes in unrealized gains and ~~lessors are required to recognize and measure leases~~losses for the period included in other comprehensive income (loss) for recurring Level 3 fair value measurements held at the ~~beginning~~end of the ~~earliest~~

~~Table~~reporting period and the range and weighted average of ~~Contents~~

~~period presented using a modified retrospective approach. The amendments are~~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, ~~2018, including~~2019, and interim periods within those fiscal ~~years, with early application permitted. We are required to use a modified retrospective approach for leases that exist or are entered into after the beginning~~years. The Company’s adoption of ~~the earliest comparative period presented in the financial statements. Early adoption is allowed. Assuming adoption January 1, 2019, we expect that leases in effect~~this guidance on January 1, 2017 and leases entered into after such date will be reflected in accordance with the new standard in the audited consolidated financial statements included in our Annual Report on Form 10-K for 2019, including comparative financial statements presented in such report. We are in the preliminary stages of our gap assessment, but we expect that leases treated as operating leases with terms greater than 12 months will be capitalized. We expect adoption of this standard to result in the recording of a right of use asset related to certain of our operating leases with a corresponding lease liability. This is expected to result in a material increase in total assets and liabilities as certain of our operating leases are significant as disclosed in our Annual Report on Form 10-K for 2016. We do not expect there will be a material overall impact on results of operations or cash flows. We are continuing to evaluate the impact of this new standard, and are in the process of developing our implementation plan.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). The new standard will replace most existing revenue recognition guidance in U.S. GAAP. The core principle of ASU 2014-09 requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. In early 2016, the FASB issued additional guidance: ASU No. 2016-10, 2016-11 and 2016-12 (and together with ASU 2014-09, “Revenue Recognition ASU”). These updates provide further guidance and clarification on specific items within the previously issued ASU 2014-09. The Revenue Recognition ASU becomes effective for the Company as of January 1, 2018, with the option to early adopt the standard for annual periods beginning on or after December 15, 2016, and allows for both retrospective and modified-retrospective methods of adoption. The Company does not plan to early adopt the standard. We have preliminarily concluded that we will adopt the Revenue Recognition ASU via the modified retrospective transition method, taking advantage of the allowed practical expedients. We are substantially complete with our gap assessment and have determined that we will qualify for point in time recognition for essentially all of our sales. As such, the Company does not expect adoption of this standard to result in a change in the timing of revenue recognition compared to current practices, and therefore we do not expect adoption of this standard to have a material impact on our financial position or results of operations. Our contract review and documentation are substantially complete. We do expect that we will have expanded disclosures around the nature of our sales contracts and other matters related to revenues and the accounting for revenues. The remaining work to be completed in connection with the implementation of the standard is to develop the required disclosures and to evaluate and modify where necessary the internal controls and procedures related to revenue recognition.

~~Adopted~~

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (ASU 2015-11) to simplify the measurement of inventory. This simplification applies to all inventory other than that measured using last-in, first out (“LIFO”) or the retail inventory method and requires measurement of inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation. This guidance is to be applied prospectively effective for annual periods beginning after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. We adopted ASU 2015-11 in the first quarter of 2017 and the application of this guidance2020 did not have ~~a significant~~an impact on ~~our~~ itsfinancial position, results of operations, or cash ~~flows.~~flows and related disclosures.

3. ~~AQUISITIONS AND~~ DISPOSITIONS

~~Sojitz Acquisition~~

On November 22, 2016, we closed on the purchase of an additional 2.98% working interest (3.23% participating interest) in the Etame Marin block located offshore the Republic of Gabon from Sojitz Etame Limited (“Sojitz”), which represents all interest owned by Sojitz in the concession. The acquisition had an effective date of August 1, 2016 and was funded with cash on hand.

The following amounts represent the preliminary estimates of the fair value of identifiable assets acquired and liabilities assumed in the Sojitz acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the date of the acquisition.

~~Table of Contents~~


		~~November 22, 2016~~
		~~(in thousands)~~
~~Assets acquired:~~
~~Wells, platforms and other production facilities~~	$	~~5,754~~
~~Equipment and other~~		~~684~~
~~Value added tax and other receivables~~		~~297~~
~~Abandonment funding~~		~~546~~
~~Accounts receivable - trade~~		~~888~~
~~Prepayments and other~~		~~220~~
~~Liabilities assumed:~~
~~Asset retirement obligations~~		~~(1,731)~~
~~Accrued liabilities and other~~		~~(747)~~
~~Total identifiable net assets and consideration transferred~~	$	~~5,911~~

All assets and liabilities associated with Sojitz’s interest in Etame Marin block, including oil and gas properties, asset retirement obligations and working capital items were recorded at their fair value. In determining the fair value of the oil and gas properties, we prepared estimates of oil and natural gas reserves. We used estimated future prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing of production and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. Other significant estimates were used by management to calculate fair value of assets acquired and liabilities assumed. We may record purchase price adjustments as a result of changes in such estimates. These assumptions represent Level 3 inputs.

~~Sale of Certain U.S. Properties~~

In April 2017, we completed the sale of our interests in the East Poplar Dome field in Montana for $0.3 million, resulting in a gain of approximately $0.3 million during the nine months ended September 30, 2017.

Discontinued Operations - Angola

In November 2006, ~~our Angolan subsidiary,~~ ~~Vaalco Angola~~ (~~Kwanza), Inc., (“VAALCO Angola”),~~the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The four year primary term, referred to as the Initial Exploration Phase (IEP”), with an optional three year extension, awarded VAALCO Angola exploration rights to 1.4 million acres offshore central Angola, with a commitment to drill two exploratory wells. The IEPCompany’s working interest was extended on two occasions to run until December 1, 2014. In October 2014, VAALCO Angola entered into the Subsequent Exploration Phase (“SEP”) which extended the exploration period to November 30, 2017 and required VAALCO Angola40%, and the ~~co-participating interest owner, the Angolan national oil company, Sonangol P&P, to drill two additional exploration wells. VAALCO Angola’s working interest is 40%, and it carries~~Company carried Sonangol P&P, for 10% of the work program. On September 30, 2016, ~~VAALCO Angola~~the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, ~~VAALCO Angola~~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, ~~VAALCO Angola has taken actions to begin reducing~~the Company closed its office in Angola and ~~reducing future~~reduced its activities in Angola. As a result of this strategic shift, wethe 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 ~~our~~the Company’s condensed consolidated statements of operations. WeThe Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in ~~our~~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~~June 30, ~~2017~~2020 and December 31, ~~2016~~2019 and its results of operations for the three and ~~nine month periods~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016.~~2019.

~~Table of Contents~~

Summarized Results of Discontinued Operations


	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Operating costs and expenses:
Gain on settlement of drilling obligation	$	—	$	—	$	—	$	(7,193)
General and administrative expense (recovery)		(19)		206		61		220
Total operating costs, expenses and (recovery)		(19)		206		61		(6,973)
Operating income (loss)		19		(206)		(61)		6,973
Total other income (expense)		(5)		—		(5)		—
Income (loss) from discontinued operations before income taxes		14		(206)		(66)		6,973
Income tax expense (benefit)		3		(44)		(14)		1,464
Income (loss) from discontinued operations	$	11	$	(162)	$	(52)	$	5,509

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Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(in thousands)
Operating costs and expenses:

Exploration expense

$
—

$
15,269

$
—

$
15,270
Depreciation, depletion and amortization

—

3

—

9
General and administrative expense

174

400

512

994
Bad debt recovery and other

—

—

—

(7,629)
Total operating costs, expenses and (recovery)

174

15,672

512

8,644
Other operating loss, net

—

(7)

—

(28)
Operating loss

(174)

(15,679)

(512)

(8,672)
Other income (expense):

Interest income

—

—

—

3,201
Other, net

—

6

(3)

551
Total other income (expense)

—

6

(3)

3,752
Loss from discontinued operations before income taxes

(174)

(15,673)

(515)

(4,920)
Income tax expense

—

110

3

3,077
Loss from discontinued operations

$
(174)

$
(15,783)

$
(518)

$
(7,997)

Assets and Liabilities Attributable to Discontinued Operations


	September 30, 2017		December 31, 2016		As of June 30, 2020		As of December 31, 2019
	(in thousands)				(in thousands)
ASSETS
Current assets:
Accounts with partners	$	2,773	$	2,139
Accounts with joint venture owners					$	—	$	—
Total current assets		2,773		2,139		—		—
Total assets	$	2,773	$	2,139	$	—	$	—

LIABILITIES
Current liabilities:
Accounts payable	$	215	$	77	$	—	$	8
Foreign taxes payable		—		3,078
Accrued liabilities and other		15,185		15,297		48		342
Total current liabilities		15,400		18,452		48		350
Total liabilities	$	15,400	$	18,452	$	48	$	350

Drilling Obligation

Under the Block 5 PSA, ~~Vaalco Angola~~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~~1 well, the Kindele #1 well, was drilled in 2015. The Block 5 PSA ~~provides~~provided for a stipulated payment of $10.0 million for each of the 3 exploration ~~well for which~~wells that a drilling obligation ~~remains~~remained under the terms of the Block 5 PSA, of which ~~VAALCO Angola’s~~the Company’s participating interest share would be $5.0 million per well. ~~We have~~The Company reflected an accrual of $15.0 million for a potential payment as of ~~September 30, 2017 and~~ December 31, ~~2016, respectively, which represents what we believe~~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 be the ~~maximum potential amount attributable~~settlement agreement, the Company agreed to ~~VAALCO Angola’s interest under~~pay $4.5 million to Angola National Agency of Petroleum, Gas, and Biofuels, as National Concessionaire, and to eliminate the ~~PSA. However, we are currently engaged in discussions and meetings with newly appointed representatives~~$3.3 million receivable from Sonangol ~~E.P. regarding this potential payment and other possible solutions and believe that the ultimate amount paid could be substantially less than the accrued amount.~~

~~Other Matters – Partner Receivable~~

P&P. The ~~government-assigned working~~receivable was related to joint interest ~~partner was delinquent in paying their share of the costs several times in 2009~~billings and was ~~removed~~reflected as a current asset from discontinued operations at year-end 2018. As a result, the ~~production sharing contract in 2010 by~~Company adjusted a ~~governmental decree. Efforts to collect~~previously accrued liability and recognized a net of tax non-cash benefit from the defaulted partner were abandoned in 2012. The available 40% working interest in Block 5, offshore Angola was assigned to Sonangol P&P effective on January 1, 2014. We invoiced Sonangol P&P for the unpaid delinquent amounts from the defaulted partner plus the amounts incurred during the period prior to assignmentdiscontinued operations of ~~the working interest totaling $7.6~~$5.7 million ~~plus interest in April 2014. Because this amount was not paid and Sonangol P&P was slow in paying monthly cash call invoices since their assignment, we placed Sonangol P&P in default~~ in the first quarter of ~~2015.~~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.

~~On March 14, 2016, we received a $19.0 million payment from Sonangol P&P~~

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 2 reportable operating segments is organized and managed based upon geographic location. The 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 ~~full amount owed us as~~location of ~~December 31, 2015, including~~hydrocarbon production. Corporate and other is primarily corporate and operations support costs that are not allocated to the ~~$7.6 million~~reportable operating segments.

Segment activity of ~~pre-assignment costs and default interest of $3.2 million. The $7.6 million recovery is reflected in the “Bad debt recovery and other” line item of our summarized results of discontinued~~continuing operations for the ~~nine~~three and six months ended ~~September~~ June 30, 2020 and 2019 as well as long-lived assets and segment assets at June 30, 2020 and December 31, 2019 are as follows:


	Three Months Ended June 30, 2020
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	17,974	$	—	$	—	$	17,974
Depreciation, depletion and amortization		2,772		—		29		2,801
Other operating expense, net		(815)		—		—		(815)
Operating income (loss)		1,704		(69)		(2,601)		(966)
Derivative instruments gain (loss), net		—		—		(756)		(756)
Income tax expense (benefit)		(273)		—		(1,976)		(2,249)
Additions to crude oil and natural gas properties and equipment – accrual		1,190		—		—		1,190

1015

Table of Contents


	Six Months Ended June 30, 2020
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	36,363	$	—	$	—	$	36,363
Depreciation, depletion and amortization		5,844		—		60		5,904
Impairment of proved crude oil and natural gas properties		30,625		—		—		30,625
Bad debt recovery and other		989		—		—		989
Other operating expense, net		(846)		—		—		(846)
Operating income (loss)		(24,579)		(194)		(2,876)		(27,649)
Derivative instruments gain (loss), net		—		—		6,583		6,583
Income tax expense		21,766		—		9,463		31,229
Additions to crude oil and natural gas properties and equipment – accrual		10,611		—		—		10,611


	Three Months Ended June 30, 2019
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	25,230	$	—	$	—	$	25,230
Depreciation, depletion and amortization		1,835		—		74		1,909
Other operating expense, net		(4,399)		—		—		(4,399)
Operating income (loss)		8,963		(130)		(2,463)		6,370
Derivative instruments gain (loss), net		—		—		1,911		1,911
Income tax expense		7,869		2		1,337		9,208
Additions to crude oil and natural gas properties and equipment – accrual		1,593		—		29		1,622


	Six Months Ended June 30, 2019
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	44,995	$	—	$	—	$	44,995
Depreciation, depletion and amortization		3,314		—		148		3,462
Impairment of proved crude oil and natural gas properties		—		—		—		—
Bad debt recovery and other		(24)		—		—		(24)
Other operating expense, net		(4,436)		—		—		(4,436)
Operating income (loss)		18,493		(316)		(6,261)		11,916
Derivative instruments gain (loss), net		—		—		(1)		(1)
Income tax expense		10,360		12		1,589		11,961
Additions to crude oil and natural gas properties and equipment – accrual		2,274		(187)		220		2,307


(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of June 30, 2020	$	31,080	$	10,000	$	268	$	41,348
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 June 30, 2020	$	118,369	$	10,086	$	19,202	$	147,657
As of December 31, 2019	$	151,686	$	10,087	$	49,764	$	211,537

Table of Contents

Information about the Company’s most significant customers

The Company 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 six months ended June 30, ~~2016. Default~~2020, revenues from sales of crude oil to Mercuria and Exxon were approximately 26% and 74%, respectively, of the Company’s total revenues from customers.

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 or 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 June 30,				Six Months Ended June 30,
		2020		2019		2020		2019
	(in thousands)
Net income (loss) (numerator):
Income (loss) from continuing operations	$	585	$	(871)	$	(52,152)	$	(41)
(Income) loss from continuing operations attributable to unvested shares		(3)		—		—		—
Numerator for basic		582		(871)		(52,152)		(41)
(Income) loss from continuing operations attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	582	$	(871)	$	(52,152)	$	(41)

Income (loss) from discontinued operations, net of tax	$	11	$	(162)	$	(52)	$	5,509
(Income) loss from discontinued operations attributable to unvested shares				—		—		(42)
Numerator for basic		11		(162)		(52)		5,467
(Income) loss from discontinued operations attributable to unvested shares		—		—		—		42
Numerator for dilutive	$	11	$	(162)	$	(52)	$	5,509

Net income (loss)	$	596	$	(1,033)	$	(52,204)	$	5,468
Net (income) loss attributable to unvested shares		(3)		—		—		(42)
Numerator for basic		593		(1,033)		(52,204)		5,426
Net (income) loss attributable to unvested shares		—		—		—		42
Numerator for dilutive	$	593	$	(1,033)	$	(52,204)	$	5,468

Weighted average shares (denominator):
Basic weighted average shares outstanding		57,456		59,801		57,716		59,716
Effect of dilutive securities		138		—		—		—
Diluted weighted average shares outstanding		57,594		59,801		57,716		59,716
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		1,793		370		3,051		644

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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.

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 thirty days after the date of the bill of lading. For each lifting of crude oil, the price is determined based on a formula using published Dated Brent prices plus a fixed contract differential.

Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, 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 ~~$3.2 million~~7.5% (increasing 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 ~~shown~~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. Prior to February 1, 2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February 1, 2018, these 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 ~~“Interest income” line item~~period that the government takes its Profit Oil in-kind, i.e. the period in which it lifts the crude oil. The only in-kind payment in the current year was $1.9 million and occurred with the April 2020 lifting. As of ~~our summarized results~~June 30, 2020 and December 31, 2019, the foreign taxes payable attributable to this obligation was $3.4 million and $5.7 million, respectively.

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

Table of ~~discontinued operations for~~Contents

all of the ~~nine months ended September 30, 2016.~~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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Revenue from customer contracts:	(in thousands)
Sales under the COSPA	$	18,816	$	20,949	$	39,260	$	42,760
Other items reported in revenue not associated with customer contracts:
Gabonese government share of Profit Oil taken in-kind		1,855		7,347		1,855		7,347
Carried interest recoupment		108		733		993		1,440
Royalties		(2,805)		(3,799)		(5,745)		(6,552)
Total revenue, net	$	17,974	$	25,230	$	36,363	$	44,995

7. CRUDE OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

~~We review our~~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. The 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 3 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 2 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. The 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. The 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 2 wells and 2 appraisal wellbores by September 16, 2020. The Consortium completed drilling 2 development wells and 2 appraisal wellbores during the 2019/2020 drilling campaign with the last appraisal wellbore completed in February 2020. The Consortium is also required to complete 2 technical studies by September 16, 2020 at an estimated cost of $1.3 million gross ($0.4 million, net to VAALCO). These studies are currently being performed and are expected to be completed on a timely basis.

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%.

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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 ana 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 recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in ~~our~~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~~second quarter of ~~2017~~2020 that would cause us to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included higher future strip prices for the ~~fact~~second quarter of 2020 compared to the first quarter of 2020, and that wethe Company incurred no significant capital expenditures in ~~2017~~the period related to the fields in the Etame Marin ~~block,~~block. During the first quarter of 2020, declining 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 second quarter of 2019, as a result of lower future strip prices for the ~~third~~second quarter of ~~2017 increased,~~2019 compared to the first 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.

~~Declining forecasted oil prices~~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 ~~other factors caused us~~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 ~~perform impairment reviews~~43% in 2020, in exchange for a potential future payment of ~~our proved properties~~$3.1 million in the ~~first quarter~~event that there is commercial production from Block P, and the EG MMH has approved this assignment. The Company is currently waiting on a production sharing contract amendment to ratify the Company’s increased working interest and appointment as operator before beginning activities in Block P. VAALCO is in commercial discussions with Levene Hydrocarbon Limited (“Levene”) regarding a potential transaction whereby VAALCO would assign a portion of ~~2016~~its working interest in Block P to Levene in exchange for ~~all fields~~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 Leveneby the EG MMH must be obtained prior to any transaction being completed. As of June 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 ~~offshore Gabon and the Hefley field in North Texas. However, no impairment~~ was ~~required for the quarter ended March 31, 2016. During the second quarter of 2016, forecasted oil prices improved significantly, our negative price differential~~expanded to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the impact on reserves of a well being shut-in in the Avouma field in the Etame Marine block offshore Gabon. After consider this factor, we determined that the undiscounted future net cash flows for the Avouma field were in excess of the field’s carrying value. No impairment was required for the Avouma field, or any of our other fields, for the second quarter of 2016. During the third quarter of 2016, our negative price differential to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the impact on reserves of a second well being shut-in in the Avouma field. After considering this factor, we determined that the undiscounted future net cash flows for the Avouma field were in excess of the field’s carrying value. No impairment was required for the Avouma field, or any of our other fields, for the third quarter of 2016.

~~5. DEBT~~

On June 29, 2016, we executed a Supplemental Agreement with the International Finance Corporation (the “IFC”) which, among other things, amended and restated our existing loan agreement to convert $20.0include previously undeveloped acreage. The Company allocated $6.7 million of the ~~revolving portion~~share of the ~~credit facility,~~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 ~~a term loan (the “Term Loan”) with $15.0 million outstanding at that date. The amended loan agreement (“Amended Term Loan Agreement”) is~~ ~~secured by~~unproved leasehold costs using the ~~assets of our Gabon subsidiary,~~ VAALCO Gabon S.A. and is guaranteed by VAALCO as the parent company. The Amended Term Loan Agreement provides for quarterly principal and interest payments on the amounts currently outstanding through June 30, 2019, with interest accruing at a rate of LIBOR plus 5.75%.

~~The Amended Term Loan Agreement also provided for an additional $5.0 million, which could be requested in a single draw, subject~~acreage attributable to the ~~IFC’s approval, through March 15, 2017. On March 14, 2017, we borrowed $4.2 million under~~previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this ~~provision~~additional area is permitted throughout the term of the ~~Amended Term Loan Agreement. The additional borrowings will be repaid in five quarterly principal installments commencing June 30, 2017, together with interest which will accrue at LIBOR plus 5.75%.~~

~~Compared to the $11.0 million principal carrying value~~Etame Marin block PSC. As a result of ~~debt, net of deferred financing costs, as of September 30, 2017, the estimated fair value of the borrowings under the~~ ~~Amended Term Loan Agreement~~ is $11.2 million when measured using a discounted cash flow model over the life of the current borrowings at forecasted interest rates. The inputs to this model are Level 3 in the fair value hierarchy.

~~Covenants~~

~~Under the~~ ~~Amended Term Loan Agreement, the ratio of quarter-end net debt to EBITDAX (as defined in the~~ ~~Amended Term Loan Agreement) must be no more than 3.0 to 1.0.~~ Additionally, our debt service coverage ratio must be greater than 1.2 to 1.0 at each semi-annual review period. Certain of VAALCO’s subsidiaries are contractually prohibited from making payments, loans or transferring assets to VAALCO or other affiliated entities. Specifically, under the Amended Term Loan Agreement, VAALCO Gabon S.A. could be restricted from transferring assets or making dividends, if the positive and negative covenants are not in compliance with the Amended Term Loan Agreement. Forecasting our compliance with these and other financial covenants in future periods is inherently uncertain; therefore, we can make no assurance that we will be able to comply with our Amended Term Loan Agreement covenants in future periods. Factors that could impact our quarter-end financial covenants in future periods include future realized prices for sales of oil and natural gas, estimated future production, returns generated by our capital program, and future interest costs, among others. We were in compliance with all financial covenants as of September 30, 2017 and December 31, 2016.

~~Interest~~

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Until June 29, 2016, under the terms of the original revolving credit facility, we paid commitment fees on the undrawn portion of the total commitment. Commitment fees had been equal to 1.5% of the unused balance of a senior tranche of $50.0 million and 2.3% of the unused balance of a subordinated tranche of $15.0 million when a commitment was available for utilization. With the execution of the Supplemental Agreement with the IFC in June 2016, beginning June 29, 2016 and continuing through March 14, 2017, commitment fees were equal to 2.3% of the undrawn Term Loan amount of $5.0 million. There are no further commitment fees owing after March 14, 2017.

~~We capitalize interest and commitment fees related to expenditures made~~discovering reserves in connection with ~~exploration and~~drilling the South East Etame 4H development ~~projects that~~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 ~~not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use.~~

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

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(in thousands)
Interest incurred, including commitment fees

$
222

$
274

$
796

$
1,047
Deferred finance cost amortization

91

56

293

262
Deferred finance cost write-off due to loan modification

—

—

—

869
Other interest not related to debt

14

(3)

19

107
Interest expense, net

$
327

$
327

$
1,108

$
2,285

Average effective interest rate, excluding commitment fees

6.54%

6.38%

6.87%

5.04%

~~6. COMMITMENTS AND CONTINGENCIES~~

~~Abandonment funding~~

As part of securing the first of two five-year extensions to the Etame field production license to which we are entitled from the government of Gabon, we agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. The agreement was finalized in the first quarter of 2014 (effective as of 2011) providing for annual funding over a period of ten years in amounts equal to 12.14% of the total abandonment estimate for the first seven years and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable. The abandonment estimate used for this purpose is approximately $61.1 million ($19.0 million net to VAALCO) on an undiscounted basis. Through September 30, 2017, $27.4 million ($8.5 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.

~~Audits~~

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

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

~~As of December 31, 2016, we had accrued $1.0 million net to VAALCO in “Accrued liabilities and other” on our condensed consolidated balance sheet for certain payroll taxes in Gabon which~~but were not paid pertaining to labor provided to us over a number of years by a third-party contractor. While the payroll taxes were for individuals who were not our employees, we could be deemed liable for these expenses as the end user of the services provided. These liabilities were substantially resolved at the accrued amount in January 2017.

At September 30, 2017, we had accrued $1.0 million net to VAALCO in “Accrued liabilities and other” on our condensed consolidated balance sheet for potential fees which may result from certain regulatory audits.

~~Rig commitment~~

In 2014, we entered into a long-term contract for the Constellation II drilling rig that was under a long-term contract for the multi-well development drilling campaign offshore Gabon. The campaign included the drilling of development wells and workovers of existing

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~~wells in the Etame Marin block.~~ We began demobilization in January 2016 and released the drilling rig in February 2016, prior to the original July 2016 contract termination date, because we no longer intended to drill any wells in 2016 on our Etame Marin block offshore Gabon. In June 2016, we reached an agreement with the drilling contractor for us to pay $5.1 million net to VAALCO’s interest for unused rig days under the contract. We paid this amount, plus the demobilization charges, in seven equal monthly installments, which began in July 2016 and ended in January 2017. ~~The related expense was reported in the “Other operating expense” line item in our condensed consolidated statement of operations~~material for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2020 and 2019.

7.8. DERIVATIVES AND FAIR VALUE

~~During 2016, we executed crude oil put contracts as market conditions allowed in order~~The Company uses derivative financial instruments from time to ~~economically hedge anticipated 2016 and 2017~~time to achieve a more predictable cash ~~flows~~flow from crude oil ~~producing activities.~~ production by reducing the Company’s exposure to price fluctuations.

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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. At June 30, 2020, the Company did not have any unexpired commodity swaps.

While these ~~crude oil puts~~commodity swaps are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, ~~we have~~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. ~~These changes in fair value have no cash flow impact.~~ The ~~impact to cash flow occurs upon settlement of the underlying contract. We do~~Company does not enter into derivative instruments for speculative or trading proposes.

As of September 30, 2017, we had unexpired oil puts covering 180,000 barrels of anticipated sales volumes for the period from October 2017 through December 31, 2017 at a weighted average price of $50.00. Our put contracts are subject to agreements similar to a master netting agreement, under which we have the legal right to offset assets and liabilities. At September 30, 2017, our unexpired oil puts represented a fair value asset position of $0.1 million in the “Prepayments and other” line item of our condensed consolidated balance sheets.

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

Carrying

Fair Value Measurements Using
Derivative Item

Balance Sheet Line

Value

Level 1

Level 2

Level 3

(in thousands)
Crude oil puts

Prepayments and other

Balance at September 30, 2017

$
61

$
—

$
61

$
—
Balance at December 31, 2016

$
1,227

$
—

$
1,227

$
—

The crude oil ~~put~~swap contracts are measured at fair value using the ~~Black’s option pricing model.~~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 ~~put contract~~swap contracts’ fair value includes the impact of the counterparty’s non-performance risk.

To mitigate counterparty risk, ~~we enter~~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 ~~loss~~gain (loss) on derivative instruments ~~in our~~on the Company’s condensed consolidated statements of operations:



		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
Derivative Item	Statement of Operations Line	2017		2016		2017		2016		Statement of Operations Line	2020		2019		2020		2019
		(in thousands)									(in thousands)
Crude oil puts	Other, net	$	(921)	$	(194)	$	(971)	$	(772)
Crude oil swaps										Realized gain - contract settlements	$	6,498	$	432	$	7,216	$	1,563
										Unrealized gain (loss)		(7,254)		1,479		(633)		(1,564)
										Derivative instruments gain (loss), net	$	(756)	$	1,911	$	6,583	$	(1)

9. ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:


	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Accrued accounts payable invoices	$	4,683	$	4,650
Joint venture audit settlement		—		3,322
Gabon DMO, PID and PIH obligations		4,193		3,314
Capital expenditures		2,894		11,792
Stock appreciation rights		1,380		2,638
Accrued wages and other compensation		1,318		1,731
Other		1,831		2,326
Total accrued liabilities and other	$	16,299	$	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 June 30, 2020, $36.7 million ($11.4 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” 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 converted 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

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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 2 one-year periods beyond September 2020. These elections have been made, and the charter has been extended through September 2022. The Company obtained guarantees from each of the Company’s joint venture owners for their respective shares of the payments. The 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 $0.3 million as of June 30, 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 $39.5 million in remaining gross minimum obligations as of June 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. The 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. The Company is working with the newly appointed representatives to resolve the audit findings. The 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. The agreement in principle also provides for procedures to minimize the chances of future audit claims. 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.

Drilling Rig

The Company contracted a drilling rig to be used to drill 2 wells, including 2 appraisal wellbores, for the Etame Marin block joint operations. The agreement included options to drill four additional wells at the Etame Marin block, and the Company elected to exercise these options to drill a third development well and perform three workovers. The drilling rig contract stipulates a day rate of approximately $75,000. The term associated with the drilling rig commitment was less than one year, and the rig was released on April 9, 2020 with no material remaining obligations.

For discussion of other contractual commitments, see Note 11 – Leases.

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 ROU asset and a lease liability at the present value of the future lease payments.

Practical Expedients – The standard provides a package of three practical expedients to simplify adoption. At the transition date, the entity may elect not to reassess: (1) whether any expired or existing contracts as of the adoption date are or contain leases under the new definition of a lease, (2) lease classification for expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. These three expedients must be elected or not elected as a package. An entity that elects to apply all three of the practical expedients will, in effect, continue to classify leases that commence before the adoption date in accordance with current GAAP, unless the lease classification is reassessed after the adoption date. A lessee that elects to apply all of the practical expedients beginning on the adoption date will follow subsequent measurement guidance in ASC 842. The Company has elected to use these practical expedients, effectively carrying over its previous identification and classification of leases that existed as of January 1, 2019. Additionally, a lessee may elect not to recognize ROU assets and liabilities arising from short-term leases provided there is no purchase option the entity is likely to exercise. The Company has elected this short-term lease exemption. The adoption of ASC 842 resulted in a material increase in 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

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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 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. The 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 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, the Company gave notification to extend the FPSO lease to September 2022 during the third quarter of 2020.

The FPSO agreement also contains options to purchase the assets during or at the end of the lease term. The 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, and certain marine vessel 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. The 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 six months ended June 30, 2020, the components of the lease costs and the supplemental information were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Lease cost:	(in thousands)
Operating lease cost	$	4,335	$	3,775	$	8,525	$	7,334
Short-term lease cost		(581)		101		451		404
Variable lease cost		2,138		1,408		4,064		2,738
Total lease expense		5,892		5,284		13,040		10,476
Lease costs capitalized		178		—		3,459		—
Total lease costs	$	6,070	$	5,284	$	16,499	$	10,476

Other information:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows to operating leases							$	13,966
Weighted-average remaining lease term								2.22 years
Weighted-average discount rate								6.13%

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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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Production expense	$	1,814	$	1,626	$	4,019	$	3,223
General and administrative expense		49		49		98		98
Lease costs billed to the joint venture owners		4,148		3,609		11,221		7,155
Total lease expense		6,011		5,284		15,338		10,476
Lease costs capitalized		59		—		1,161		—
Total lease costs	$	6,070	$	5,284	$	16,499	$	10,476

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


	Lease Obligation
Year	(in thousands)
2020	$	6,865
2021		13,535
2022		9,355
2023		—
2024		—
		29,755
Less: imputed interest		1,850
Total lease liabilities	$	27,905

Under the joint operating agreements, other joint owners are obligated to fund $20.5 million of the $29.8 million in future lease liabilities.

12. ASSET RETIREMENT OBLIGATIONS

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


(in thousands)	Six Months Ended June 30, 2020		Year Ended December 31, 2019
Beginning balance	$	15,844	$	14,816
Accretion		440		812
Additions		359		595
Revisions		—		(379)
Ending balance	$	16,643	$	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. During 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. NaN shares of preferred stock were issued and outstanding as of June 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

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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 0 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

~~Our~~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 ~~our~~the Company’s Board of Directors to issue various types of incentive compensation. ~~Currently, we have~~The Company had previously issued stock options and restricted shares ~~and SARs~~ under the 2014 Long-Term Incentive Plan (“2014 Plan”)~~. At September 30, 2017, 2,126,942~~ and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s shareholders approved the 2020 Long-Term Incentive Plan (“2020 Plan”) under which 5,500,000 shares ~~were~~are authorized for future ~~grants under this plan.~~grants. At June 30, 2020, 3,174,198 shares were available for future grants.

For each stock option granted, the number of authorized shares under the ~~2014~~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. ~~We have~~The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.

~~We record non-cash~~As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative ~~expense. For the three months ended September 30, 2017 and 2016, non-cash compensation~~ expense ~~was $0.2 million and $(1.3) million, respectively, related to~~associated with the issuance of stock options, restricted stock and ~~restricted stock. For~~stock appreciation rights. During the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020, the Company did not settle any stock-based compensation. During the six months ended June 30, 2019, the Company settled in cash $0.3 million for stock appreciation rights and ~~2016, non-cash compensation was $0.9 million~~received $0.1 million ~~respectively, related to~~for stock option exercises. Because the ~~issuance of stock options and restricted stock. Because we do~~Company does not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.

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	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Stock-based compensation - equity awards	$	60	$	595	$	205	$	622
Stock-based compensation - liability awards		660		(698)		(2,054)		998
Total stock-based compensation	$	720	$	(103)	$	(1,849)	$	1,620

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 ~~our~~the Company’s Board of Directors, which ~~in the past has been a five year life, with the options vesting~~generally vest over a service period of up to five ~~years.~~ years and expire from five to ten years from the date of grant.

In ~~addition,~~June 2020, the Company granted options that are considered performance stock options ~~will become exercisable upon~~to purchase an aggregate of 644,758 shares at an exercise price of $1.23 per share and a ~~change in control, unless provided otherwise by the Compensation Committee. There were immaterial cash proceeds from the exercise~~life of ~~stock options in the three and nine months ended September 30, 2017 and 2016. For the nine months ended September 30, 2017, options for 1,550,442 shares~~ten years were granted to ~~employees; these~~employees of the Company. For each option award, options with respect to one-third of the underlying shares vest ~~over a three-year period, vesting in three equal parts~~ on the later of the first ~~second~~anniversary of the grant date and ~~third anniversaries after~~ 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-thirdof ~~grant. Options~~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 ~~465,950 shares~~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 six months ended June 30, 2020, the assumptions shown below were ~~granted~~used to ~~our non-employee directors, which~~calculate the weighted average grant date fair value of performance stock option awards issued under the 2020 Plan.

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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 six months ended June 30, 2020 and 2019, the weighted average assumptions shown below were ~~fully vested upon their grant.~~used to calculate the weighted average grant date fair value of option grants.


	Six Months Ended June 30,
	2020			2019
Weighted average exercise price - ($/share)	$	1.23		$	2.08
Expected life in years		6.00			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

Stock option activity for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 is provided below:

Number of Shares Underlying Options

Weighted Average Exercise Price Per Share

(in thousands)

Outstanding at January 1, 2017

2,644

$
3.92
Granted

1,550

0.99
Exercised

(37)

1.04
Forfeited/expired

(1,202)

4.63
Outstanding at September 30, 2017

2,955

2.13


	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	(132)		4.71
Outstanding at June 30, 2020	3,286		1.35	3.40	$	403
Exercisable at June 30, 2020	2,175		1.27	1.46	$	345

During the six months ended June 30, 2020, no shares were added to treasury as a result of tax withholding on options exercised. During the six months ended June 30, 2019, 13,875 shares were added to treasury as a result of tax withholding on options exercised. During the six months ended June 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 ~~which~~that is generally a ~~three year~~three-year period, vesting in three equal parts on the ~~first three~~ anniversaries offollowing the date of the grant. ~~Share grants~~Restricted stock granted to directors will vest ~~immediately~~on the earlier of (i) the first anniversary of the date of grant and ~~are~~(ii) the first annual meeting of stockholders following the date of grant (but not ~~restricted.~~ 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 ~~in unvested restricted stock in~~for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2020:


	Restricted Stock	Weighted Average Grant Price		Restricted Stock	Weighted Average Grant Date Fair Value
	(in thousands)			(in thousands)
Non-vested shares outstanding at January 1, 2017	252	$	1.31
Non-vested shares outstanding at January 1, 2020				343	$	1.52
Awards granted	386		0.98	971		1.23
Awards vested	(235)		1.12	(145)		1.39
Awards forfeited	(41)		1.00	—		—
Non-vested shares outstanding at September 30, 2017	362		1.12
Non-vested shares outstanding at June 30, 2020				1,169		1.30

~~In both~~During the ~~three~~six months ended ~~September~~June 30, ~~2017 and 2016, 9,117~~2020, 40,432 shares were added to treasury ~~due to tax withholding~~ as a result of tax withholding on the vesting of restricted shares. InDuring the ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016, 9,117~~2019, 30,573 shares ~~and 40,926 shares, respectively,~~ were added to treasury ~~due to tax withholding~~ as a result of tax withholding on the vesting of restricted shares.

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Stock appreciation rights (“SARs”)

SARs are granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in athe SAR award ~~on the date of grant (which~~(that may not be less than the fair market value of ~~our~~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 ~~our~~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 ~~our~~the Company’s Board of Directors.

During the ~~nine~~six months ended ~~September~~June 30, ~~2017, 1,049,528~~2020, the Company did not grant SARs ~~were granted, all having an exercise price of $1.20 per share. One-third of the SARs are~~ to ~~vest on~~employees or after the first anniversary of the grant date at such time when the market price per share of our common stock exceeds $1.30; one-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds $1.50; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds $1.75. SARs granted in 2016 vest over a three year period with a life of 5 years; these SARs have a maximum spread equal to 300% of the $1.04 SAR price per share specified in a SAR award on the date of grant. The amounts of compensation payable related to these awards through September 30, 2017 have not been significant.directors.

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SAR activity for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~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 shares forfeited	(60)		1.83
Vested shares expired	—		—
Outstanding at June 30, 2020	3,358		1.29	2.65	$	709
Exercisable at June 30, 2020	2,177		1.16	2.36	$	485

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.

Number of Shares Underlying SARs

Weighted Average Exercise Price Per Share

(in thousands)

Outstanding at January 1, 2017

180

$
1.04
Granted

1,050

1.20
Forfeited/expired

(153)

1.20
Outstanding at September 30, 2017

1,077

1.17

9.15. INCOME TAXES

On March 27, 2020, President Trump signed into U.S. federal law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which is aimed at providing emergency assistance and health care for individuals, families, and businesses affected by the COVID-19 pandemic and generally supporting the U.S. economy. The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. The Company has analyzed the different aspects of the CARES Act and implemented the applicable provisions, which had no material impact on the Company.

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.

The income tax provision for VAALCO consists primarily of Gabonese and ~~its domestic subsidiaries file a consolidated~~ United States income taxes. The Company’s operations in other foreign jurisdictions have a 0% effective tax ~~return. Certain subsidiaries’ operations are also subject to foreign income taxes.~~

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
U.S. Federal:	(in thousands)
Current	$	72	$	(128)	$	(525)	$	(165)
Deferred		(2,048)		1,467		9,988		1,766
Foreign:
Current		1,046		3,411		(517)		4,459
Deferred		(1,319)		4,458		22,283		5,901
Total	$	(2,249)	$	9,208	$	31,229	$	11,961

The Company’s effective tax rate for the six months ended June 30, 2020 and 2019, excluding the impact of discrete items, was (56%) and 79%, respectively. For the three and six months ended June 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 effective tax rate continued to be impacted by a change in current year expectations caused by lower crude oil prices. This impact was a result of the collapse in crude oil demand due in part to the world-wide economic impact of the COVID-19 pandemic. Primarily as a result of ~~September 30, 2017 and December 31, 2016.~~

~~Income taxes attributable to continuing operations~~lower crude oil prices, the Company decreased its estimate for future taxable income. The total change in valuation allowances for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 was $(4.1) million and ~~2016 are attributable~~$42.8 million, respectively.

The Company files income tax returns in all jurisdictions where such requirements exist, with Gabon and the United States being its primary tax jurisdictions.

As of June 30, 2020, the Company had 0 material uncertain tax positions. The Company’s policy is to ~~foreign taxes payable in Gabon.~~recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.

In April 2017, we were notified by the U.S. Internal Revenue Service (“IRS”) that they would be conducting an audit of our 2014 U.S. federal tax return. The audit is in progress; however, to date, the IRS has not communicated any findings.

~~10. EARNINGS PER SHARE~~
‎

Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, we assume that restricted stock is outstanding on the date of vesting, and we assume the issuance of shares from ~~the exercise of stock options using the treasury stock method.~~

~~A reconciliation from basic to diluted shares follows:~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(in thousands)
Basic weighted average shares outstanding

58,817

58,708

58,682

58,600
Effect of dilutive securities

—

—

4

—
Diluted weighted average shares outstanding

58,817

58,708

58,686

58,600
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive

3,007

4,098

2,799

4,455

1528

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~~11. SEGMENT INFORMATION~~

~~Our operations are based in Gabon, Equatorial Guinea and the U.S.~~ ~~Each of our three reportable operating segments is organized and managed based upon geographic location. Our Chief Executive Officer, who is the chief operating decision maker, and management,~~ review and evaluate the operation of each geographic segment separately primarily based on Operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production. ~~Corporate and other is primarily corporate and operations support costs which are not allocated to the reportable operating segments.~~

~~Segment activity of continuing operations for the three and nine months ended September 30, 2017 and 2016 and segment assets at September 30, 2017 and December 31, 2016 are as follows:~~

Three Months Ended September 30, 2017
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
18,162

$
—

$
16

$
—

$
18,178
Depreciation, depletion and amortization

1,633

—

—

67

1,700
Bad debt expense and other

(49)

—

—

—

(49)
Operating income (loss)

6,067

(44)

10

(2,312)

3,721
Interest expense, net

(327)

—

—

—

(327)
Income tax expense

2,749

—

—

—

2,749
Additions to property and equipment - accrual

237

—

—

60

297

Three Months Ended September 30, 2016
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
14,540

$
—

$
95

$
—

$
14,635
Depreciation, depletion and amortization

1,508

—

38

61

1,607
Impairment of proved properties

—

—

88

—

88
Bad debt expense and other

63

—

—

—

63
Other operating expense

324

—

—

—

324
Operating income (loss)

5,013

(184)

(61)

(1,078)

3,690
Interest income (expense), net

(329)

—

—

2

(327)
Income tax expense (benefit)

2,305

—

—

(107)

2,198
Additions to property and equipment - accrual

674

—

—

7

681

Nine Months Ended September 30, 2017
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
59,823

$
—

$
46

$
—

$
59,869
Depreciation, depletion and amortization

5,344

—

1

194

5,539
Bad debt expense and other

232

—

—

—

232
Operating income (loss)

25,117

(97)

356

(7,920)

17,456
Interest expense, net

(1,108)

—

—

—

(1,108)
Income tax expense

9,039

—

—

—

9,039
Additions to property and equipment - accrual

1,051

—

—

60

1,111

~~Table of Contents~~

Nine Months Ended September 30, 2016
(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Revenues-oil and natural gas sales

$
44,212

$
—

$
246

$
-

$
44,458
Depreciation, depletion and amortization

5,484

—

121

182

5,787
Impairment of proved properties

—

—

88

—

88
Bad debt expense and other

577

—

—

—

577
Other operating expense

9,959

—

—

—

9,959
Operating income (loss)

1,481

(319)

(64)

(6,308)

(5,210)
Interest expense, net

(2,285)

—

—

—

(2,285)
Income tax expense

6,884

—

—

—

6,884
Additions to property and equipment - accrual

(1,819)

—

140

7

(1,672)

(in thousands)

Gabon

Equatorial Guinea

U.S.

Corporate and Other

Total
Total assets from continuing operations:

As of September 30, 2017

$
61,694

$
10,093

$
83

$
1,892

$
73,762
As of December 31, 2016

64,478

10,122

382

3,911

78,893

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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 ~~report~~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”,~~ “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 recent 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;

~~volatility of, and declines and weaknesses in oil and natural gas prices;~~

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

~~our ability to meet the financial covenants of our Amended Term Loan Agreement;~~

our ability to resolve satisfactorily matters related to our exit from Angola, including our obligations to pay the amount, as it is ultimately determined, of our liabilities to Sonangol E.P. with respect to our production sharing contract;

~~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;~~

~~our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements through December 31, 2018;~~

~~our ability to meet the continued listing standards of the New York Stock Exchange (“NYSE”), or to cure any deficiency in meeting the listing standards;~~

~~our ability to replace our Amended Term Loan Agreement facility with another credit facility to help fund our future capital requirements;~~

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

~~the uncertainty of estimates of oil and natural gas reserves;~~

~~the impact of competition;~~

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

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

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

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

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

~~timing and amount of future production of oil and natural gas;~~

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

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

~~our ability to pay the expenditures required in order to develop certain of our properties offshore Equatorial Guinea;~~

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

~~changes in customer demand and producers’ supply;~~

~~future capital requirements and our ability to attract capital;~~

~~currency exchange rates;~~

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

~~actions by our venture partners;~~

~~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;~~

~~actions of operators of our oil and natural gas properties;~~

1829

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~~the timing and effectiveness of our remediating the significant deficiencies and material weaknesses in our internal control over financial reporting; and~~

~~weather conditions.~~

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, ~~2016~~2019 (“~~2016~~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 ~~2016~~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.

~~INTRODUCTION~~

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 ~~development~~exploration activities in Gabon, West Africa. We also have opportunities to participate in development and exploration activities ~~as a non-operator~~ in Equatorial Guinea, West Africa. As discussed further in Note 3 to the condensed consolidated financial statements included in this Form 10-Q, we have discontinued operations associated with our activities in Angola, West ~~Africa, and in April 2017 we completed the sale of our interests in Montana.~~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. ~~Oil~~Historically, crude oil and natural gas prices have been volatile and subject to fluctuations based on a number of factors beyond our control. Beginning in the third quarter of 2014, the global prices for oil and natural gas began a dramatic decline which continued through 2015 and into 2016. During this period, we scaled back our global operations, divested non-core assets, amended our credit agreement and focused on reducing costs and maximizing our cash flows. Current prices, while higher than those in early 2016, are significantly less than they were in the several years prior to mid-2014. A decline inMore 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. In March 2020, we completed the 2019/2020 drilling campaign.

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 ~~sustained period~~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 ~~natural gas prices at depressed levels could have~~consequently a ~~material adverse effect on our financial condition.~~

~~CURRENT DEVELOPMENTS~~

~~During 2016, the global oil supply continued to outpace demand, having a dampening effect on the recovery of realized~~substantial decrease in crude oil prices. ~~While global~~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, ~~were closer~~in an effort to ~~being balanced~~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 through September 2020. To comply with such request from the Minister of Hydrocarbons, in July 2020 we temporarily reduced production from the Etame Marin block. We currently expect to continue production at reduced levels through September 2020, at which time we will reassess our ability to increase production rates in light of OPEC+ agreements and related mandates from the Minister of Hydrocarbons in Gabon in place at such time. Based on planned shut-ins for fieldwide maintenance and reduced production levels due to OPEC+ quotas, we expect our crude oil production for the three months ended September 30, 2020 to be between 4,200 - 4,600 barrels per day compared to 5,410 barrels per day during the second quarter of 2020. 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

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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.

While we did not incur significant disruptions to operations during the six months ended June 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:

implemented stay-at-home initiatives for all but critical staff and put into place social distancing measures;

actively screening and monitoring 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;

temporarily reduced director, executive and certain non-executive employee compensation and

ceased or deferred 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 ~~nine~~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 and brought the well onto production on March 21, 2020. Following the completion of the South East Etame 4H, we began the planned workover on the South East Etame 2H to replace the electric submersible pumps and restored 2,400 gross barrels of oil per day.

In mid-April 2020, the South Tchibala 2H well stopped producing due to a downhole mechanical failure not related to the electric submersible pumps. The well was producing approximately 830 gross barrels of oil per day (“BOPD”), or 225 BOPD net revenue interest to VAALCO prior to ceasing production. We may not be able to address the well failure until the next drilling campaign.

During the three months ~~of 2017, no assurances can be made that this trend will continue. Prices for~~ended June 30, 2020, we maintained field integrity and our crude oil ~~improved during~~production schedule without any operational disruptions or reportable accidents despite the ~~second half of 2016 (ICE Dated Brent crude oil prices increased from approximately $36 per Bbl in early January 2016 to approximately $55 per Bbl at~~challenges presented by the ~~end of 2016, and fluctuated between $44 and $61 per Bbl from January 2017 through October 2017).~~COVID-19 pandemic.

On June 29, 2016, we executed a Supplemental Agreement with the International Finance Corporation (the “IFC”), the lender under our revolving credit facility which among other things, amended and restated our loan agreement to convert $20.0 million of the revolving portion of the credit facility into a term loan with $15.0 million outstanding at that date. The amended loan agreement also provided us with an option to borrow an additional $5.0 million in a single draw, subject to IFC approval, through March 15, 2017. On March 14, 2017, we borrowed $4.2 million under the provisions of the Amended Term Loan Agreement. Currently under this loan agreement, we have $11.0 million in total debt, net of deferred financing costs, outstanding. See Note 5 to the condensed consolidated financial statements and “Capital Resources and Liquidity—Liquidity—Credit Facility” below for additional details about the loan agreement. There is no further ability to borrow additional sums under our IFC credit facility.NYSE Noncompliance Notice

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~~Our common stock is listed and traded on the NYSE.~~ On April ~~6 and June 28, 2017, we received notices from the NYSE that~~22, 2020, we were ~~not in compliance with a provision of~~notified by the ~~NYSE’s continued listing standards~~New York Stock Exchange (the “NYSE”) that ~~require~~ the average closing price of our common stock ~~to be at least~~over the prior 30 consecutive trading days was below $1.00 per share, ~~over a consecutive 30-trading-day period. The 30 trading-day~~which is the minimum average closing price required to maintain listing on the NYSE under Section 802.01C of the Company’s common stock for these notices had been $0.99 per share. We have responded to these notifications, and will have six months from our receipt of the June 28, 2017 notice (which may be extended to our next annual shareholder meeting) to regainNYSE Listed Company Manual. On July 1, 2020, we received notification that we regained full compliance with the minimum share price rule. This notice from the NYSE does not affect our business operations or trigger any default or other violation of our debt or other material obligations. In addition, we received a notification from the NYSE on November 30, 2016 that our market capitalization had fallen below theall NYSE’s continued listing ~~standard because our average market capitalization had fallen below $50 million over a trailing 30 trading-day period and our last reported stockholders’ equity was less than $50 million.~~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~~June 30, ~~2017,~~2020, production operations in the Etame Marin block included ~~seven~~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 ~~Floating, Production, Storage~~floating, production, storage and ~~Offloading~~offloading vessel (“FPSO”) anchored to the seabed on the block. We currently have thirteen producing wells. The FPSO has production limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day. During the ~~nine~~three months ended ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, production from the block was approximately ~~4,268~~1,822 MBbls ~~(1,154~~(492 MBbls net) and ~~4,835~~1,235 MBbls ~~(1,181~~(333 MBbls net), respectively.

During the first quarter of 2016, we conducted workover operations on two Avouma field wells. An Electrical Submersible Pump (“ESP”) system was replaced successfully in one well, but the workover operations on the second well were suspended due to operational problems with its ESP. During the second and third quarters of 2016, the ESPs in the South Tchibala 2-H well and the Avouma 2-H well also failed. These wells were temporarily shut-in, but through our utilizing a lower-cost hydraulic workover unit to replace the failed ESP systems, the two wells were placed back on production in December 2016 and January 2017, respectively.

~~In July 2017, the ESP in the South Tchibala 2-H well failed, resulting in the well being temporarily shut-in.~~

In October 2017, we began workover operations on the South Tchibala 1-HB well. These operations were successfully completed in November 2017, and the well was returned to production. We began workover operations on the South Tchibala 2-H well in November 2017. This is expected to result in an increase in production for the fourth quarter. In addition the fourth quarter is expected to have higher production expenses related to the workover costs.

~~During July 2017, production was temporarily shut-in for periodic maintenance, and as a result, production volumes were lower in the three~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~our~~2019, production ~~expense increased~~from the block was approximately 3,487 MBbls (942 MBbls net) and 2,399 MBbls (648 MBbls net), respectively, as ~~a result~~discussed below in “Results of ~~the maintenance-related costs.~~Operations”.

Equatorial Guinea

~~We have~~VAALCO acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea ~~that we acquired~~ in 2012. ItThe 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. We are currently ~~unlikely that we~~waiting on a production sharing contract amendment to ratify the Company’s increased working interest and appointment as the operator before beginning activities in Block P. VAALCO is in commercial discussions with Levene Hydrocarbon 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 ~~making any near-term expenditures with respect~~completed. Further, approval of the assignment to Leveneby the EG MMH must be obtained prior to any ~~development~~transaction being completed. As of ~~this property. Before beginning exploration, we~~June 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 ~~our partners will need to evaluate~~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. ~~Our~~The Block P production sharing contract ~~covering this development and production area~~ provides for a development and production period of 25 years from the date of approval of a development and production plan. ~~We are in continued discussions with the Minister of the Ministry of Mines and Hydrocarbons regarding the timing of any possible development plan.~~

Discontinued Operations - Angola

~~In November 2006, our Angolan subsidiary,~~ ~~Vaalco Angola~~ (~~Kwanza), Inc., (“VAALCO Angola”), signed a production sharing contract for Block 5 offshore Angola (“PSA”).~~ The four year primary term, referred to as the Initial Exploration Phase (“IEP”), with an optional three year extension, awarded VAALCO Angola exploration rights to 1.4 million acres offshore central Angola, with a commitment to drill two exploratory wells. The IEP was extended on two occasions to run until December 1, 2014. In October 2014, VAALCO Angola entered into the Subsequent Exploration Phase (“SEP”) which extended the exploration period to November 30, 2017 and required VAALCO Angola and the co-participating interest owner, the Angolan national oil company, Sonangol P&P, to drill two additional exploration wells. VAALCO Angola’s working interest is 40%, and it carries Sonangol P&P, for 10% of the work program. On September 30, 2016, VAALCO Angola notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, VAALCO Angola notified the national concessionaire, Sonangol E.P., that it was withdrawing from the PSA. Further to the decision to withdraw from Angola, VAALCO Angola has taken actions to begin reducing its office in Angola and reducing future activities in Angola upon the approval of VAALCO Angola’s withdrawal. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the condensed consolidated financial statements for all periods presented. See Note 3 to the condensed consolidated financial statements for further discussion.

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~~Drilling Obligation~~

~~Under the PSA,~~ ~~Vaalco Angola~~and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases under the PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of $10.0 million for each exploration well for which a drilling obligation remains under the terms of the PSA, of which VAALCO Angola’s participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of September 30, 2017 and December 31, 2016, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA. However, we are currently engaged in discussions with newly appointed representatives from Sonangol E.P. regarding this potential payment and other possible solutions and believe that the ultimate amount paid will be substantially less than the accrued amount.

~~Other Matters – Partner Receivable~~

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

On March 14, 2016, we received a $19.0 million payment from Sonangol P&P for the full amount owed us as of December 31, 2015, including the $7.6 million of pre-assignment costs and default interest of $3.2 million. The $7.6 million recovery and default interest of $3.2 million is included in Loss from discontinued operations, net of tax for the nine months ended September 30, 2016.

~~LIQUIDITY AND~~ CAPITAL RESOURCESAND LIQUIDITY

Cash Flows

Our cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019 are as follows:

Nine Months Ended September 30,

Increase

2017

2016

(Decrease)

(in thousands)
Net cash provided by (used in) operating activities

$
3,232

$
(36)

$
3,268
Net cash provided by (used in) investing activities

(1,123)

1,655

(2,778)
Net cash used in financing activities

(3,720)

(93)

(3,627)
Net change in cash and cash equivalents

$
(1,611)

$
1,526

$
(3,137)


	Six Months Ended June 30,
	2020		2019		Increase (Decrease) in 2020 over 2019
	(in thousands)
Net cash provided by operating activities before change in operating assets and liabilities	$	17,646	$	14,106	$	3,540
Net change in operating assets and liabilities		2,947		2,566		381
Net cash provided by continuing operating activities		20,593		16,672		3,921
Net cash used in discontinued operating activities		(354)		(91)		(263)
Net cash provided by operating activities		20,239		16,581		3,658

Net cash used in investing activities		(20,097)		(1,163)		(18,934)
Net cash used in financing activities		(990)		(245)		(745)
Net change in cash, cash equivalents and restricted cash	$	(848)	$	15,173	$	(16,021)

The $3.5 million increase in net cash provided by our operating activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016 was primarily related to a $20.6 million~~2019 includes an increase in cash generated by continuing operations before change in operating assets and liabilities, which ~~in large part~~ was ~~the result of higher 2017 crude oil prices and lower operating costs and expenses. This overall improvement was~~mainly due to cash settlements received on matured derivative contracts offset by ~~a reduction~~lower revenue as referenced below in ~~cash generated~~

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Results of Operations. Cash provided by ~~our discontinued operation~~changes in operating assets and liabilities for the ~~first nine~~six months ended June 30, 2020 compared to the same period of ~~2017 totaling $17.4~~2019 remained relatively flat with a slight increase of $0.4 million. The decrease in cash generated by discontinued operations was the result of a benefit received in the nine months September 30, 2016 of $19.0 million from our Angolan joint interest partner in payment of partner receivables.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2020, these expenditures on a cash basis were ~~$1.3~~$20.1 million, primarily related to the 2019/2020 drilling campaign and equipment purchases. This compares to $1.2 million, primarily related to equipment ~~purchases. This compares to $12.8 million in property and equipment expenditures included in capital expenditures~~purchases, for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2019. See “Capital Expenditures” below for further discussion.

Net cash ~~provided by investing~~used in financing activities during the six months ended June 30, 2020 included $1.0 million for treasury stock purchases primarily made under the ~~2016 period also included a $15.3 million benefit from~~Company’s stock repurchase plan. Net cash used in financing activities during the ~~decrease in restricted cash.~~six months ended June 30, 2019 was not material.

Capital Expenditures

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2020, we ~~made~~incurred accrual basis capital expenditures of ~~$1.1~~$10.6 million. ~~At September 30, 2017,~~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 ~~had~~have ceased or deferred discretionary capital spending, and there are no remaining material ~~commitments for~~non-discretionary capital expenditures ~~to be made in 2017 and in future years.~~anticipated for the balance of 2020. We expect any capital expenditures made during ~~2017~~the remainder of 2020 will be funded by cash on hand and cash flow from operations.

~~Abandonment Obligations~~

We ~~have~~intend to manage any future capital expenditure levels in view of the existing and expected pricing environment. Under the PSC extension, the Consortium is also required to complete two technical studies by September 16, 2020 at an ~~agreed cash funding arrangement for the eventual abandonment~~estimated cost of all offshore wells, platforms and facilities on the Etame Marin block. Based upon the abandonment study completed in January 2016, the abandonment cost estimate used for this purpose is approximately $61.1$1.3 million gross ($~~19.0~~0.4 million, net to VAALCO) on an undiscounted basis. The obligation for abandonment of the Gabon offshore facilities is included in the “Asset retirement obligations” line item on our condensed consolidated balance sheets. Through September 30, 2017, $27.4 million ($8.5 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheet. The next funding

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is. These studies are underway and are expected to be ~~$7.4 million ($2.3 million net to VAALCO)~~completed on a timely basis.

Contractual Obligations

See Notes 12 and ~~paid in December 2017; however, future changes~~13 to the ~~anticipated abandonment~~condensed consolidated financial statements as well as our 2019 Form 10-K for discussion of our contractual obligations.

In April 2020, the Company executed a two-year contract for a supply vessel. The lease liability of $0.6 million was recorded in connection with this obligation. There were no other material changes in our contractual obligations during the six months ended June 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 ~~estimate could change our asset retirement obligation~~account, customs, taxes and other operational matters, as well as audits by other members of the ~~amount of future abandonment funding payments.~~

~~Capital Resources~~

~~Credit Facility~~

Historically, our primary sources of capital have been cash flows from operating activities, borrowings under the credit facility with the IFC and cash balances on hand. The current $11.2 million in principal outstandingcontractor group under our ~~Amended Term Loan Agreement matures in June 2019, and requires quarterly principal and interest payments~~joint operating agreements. See Note 10 for further discussion.

Capital Resources

Cash on ~~the amounts currently outstanding continuing through~~Hand

At June 30, 2019. Interest accrues on the unpaid balance at the per annum rate of LIBOR plus 5.75%. The current portion of the outstanding debt was $7.5 million as of September 30, 2017. Our repayment obligations under this facility require us to pay installments of principal totaling $2.0 million for the remainder of 2017, $6.7 million in 2018 and $2.5 million in 2019. We may make no further borrowings under the terms of the Amended Term Loan Agreement.

~~The indebtedness under our amended loan agreement is secured by the assets of our Gabon subsidiary, VAALCO Gabon S.A. and is guaranteed by VAALCO Energy, Inc., as the parent company.~~

The Amended Term Loan Agreement contains a number of restrictive covenants that impose significant operating and financial restrictions on us. These covenants restrict our ability to engage in certain actions, including potentially limiting our ability to sell assets, make future borrowings or incur other additional indebtedness. Our ability to meet our quarter-end net debt to EBITDAX ratio and our debt service coverage ratio can be affected by events beyond our control, including changes in commodity prices.

Under the Amended Term Loan Agreement, quarter-end net debt to EBITDAX (as defined in the loan agreement) must be no more than 3.0 to 1.0. Additionally, our debt service coverage ratio must be greater than 1.2 to 1.0 at ~~semi-annual review period~~. Forecasting our compliance with these and other financial covenants in future periods is inherently uncertain. Factors that could impact our quarter-end financial covenants in future periods include future realized prices for sales of oil and natural gas, estimated future production, returns generated by our capital program, and future interest costs, among others. We are in compliance with all financial covenants as of September 30, 2017, and we expect to be in compliance with these covenants through maturity. However, there can be no assurance that we will be able to comply with these financial covenants in future periods. In addition, if we receive any waivers or amendments to our Amended Term Loan Agreement, the lender may impose additional operating and financial restrictions on us.

A breach of the covenants under our Amended Term Loan Agreement could result in an event of default under the agreement. Such a default may allow the lender to accelerate payment of the indebtedness under the agreement and may result in the acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. Furthermore, if we were unable to repay the amounts due and payable under the loan agreement, the lender could proceed against the collateral that we granted to it to secure that indebtedness.

C~~ash on Hand~~

~~At September 30, 2017,~~2020, we had unrestricted cash of ~~$18.9~~$44.8 million. The unrestricted cash balance includes $9.3 million of cash attributable to non-operating joint venture owner advances. As operator of the Etame Marin ~~and Mutamba Iroru blocks~~block in Gabon, we enter into project related activities on behalf of our working interest ~~partners.~~joint venture owners. We generally obtain advances from ~~partners~~the joint venture owners prior to significant funding commitments. ~~Our cash on hand will be utilized, along with cash generated from operations, to fund our operations for the foreseeable future.~~

We currently sell our crude oil production from Gabon under a term contract that began in February 2020 and ends in January ~~2018.~~2021. Pricing under the contract is based upon an average of Dated Brent ~~prices~~ 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 ~~location~~Brent crude, as of March 31, 2020, as a result of market concerns about the ability of OPEC and ~~market factors. We expect that we will be~~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 ~~extend~~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 $42 per barrel as of June 30, 2020. At June 30, 2020, we did not have commodity 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 September 2021. We are continuing to evaluate all uses of cash and whether to pursue growth opportunities or ~~enter into a new contract on comparable terms on or before January 2018.~~

~~Liquidity~~

Aspreserve our resources in light of ongoing economic conditions. For instance, as discussed above in “Recent Developments”, we have ceased or deferred discretionary capital spending, and we have undertaken certain cost cutting and cost sharing measures. However, the current market environment is highly unpredictable and our ~~revenues,~~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 ~~flow, profitability, oil~~flows and ~~natural gas reserve values and future rates of growth are substantially dependent upon prevailing prices for oil and natural gas. Our~~our ability to borrow funds and to obtain additional capital on attractive terms ~~is also substantially dependent~~may be severely limited. Further, the availability of capital resources to us on ~~oil and natural gas prices. After a period~~attractive terms may be limited due to the geographic location of ~~low commodity prices, oil and gas prices have stabilized at levels which~~our primary producing assets. If we are ~~currently adequate~~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, ~~for~~furlough or layoff employees and take other actions to reduce our ~~continuing operations. We believe~~operating expenses. In addition, we may not be able to complete acquisitions that ~~at current prices, cash generated from continuing operations together with cash on hand at September 30, 2017 are adequate~~may be favorable to ~~support~~us or finance the capital expenditures necessary to maintain our ~~operations and cash requirements during the remainder of 2017 and through~~production or replace our reserves.

At December 31, ~~2018.~~

~~As discussed in Note 7 to the condensed consolidated financial statements,~~2019, we ~~have put contracts in place at September 30, 2017 which limits our exposure to a decline in oil prices through December 31, 2017.~~

~~All~~had 5.0 MMBbls of ~~our~~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 ~~June 2021, and we are focused on extending the license~~September 2028 with rights for ~~the block, which, if accompanied by a successful drilling program, could favorably improve our long-term liquidity.~~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, which would negatively impact our long-term liquidity. In addition, our~~produced. While both short-term and long-term liquidity are impacted by ~~the changes in~~ crude oil ~~prices.~~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.

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OFF-BALANCE SHEET ARRANGEMENTS

In connection with the charter of the FPSO (see “— Activities by Asset — Gabon — Offshore-Etame Marin Block”), we, as operator of the Etame Marin block, guaranteed all of the lease payments under the charter through its contract term, which expires in September 2020. At our election, the charter may be extended for two one-year periods beyond September 2020. We obtained guarantees from each of our partners for their respective shares of the payments. Our net share of the charter payment is 31.1%, or approximately $9.7 million per year. Although we believe the need for performance under the charter guarantee is remote, we recorded a liability of $0.5 million and $0.7 million as of September 30, 2017 and December 31, 2016, respectively, representing the guarantee’s fair value. The guarantee of the offshore Gabon FPSO lease has $93.1 million in remaining gross minimum obligations for the total amount of charter payments at September 30, 2017. There have been no other material off-balance sheet arrangements entered into since December 31, 2016.None.

~~COMMITMENTS AND CONTRACTUAL OBLIGATIONS~~

Other than our borrowing of $4.2 million under the Additional Term Loan Agreement discussed in Note 5 to the condensed consolidated financial statements, there have been no significant changes to our commitments and contractual obligations subsequent to December 31, 2016.

CRITICAL ACCOUNTING POLICIES

There have been no changes to our critical accounting policies subsequent to December 31, ~~2016.~~2019.

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three ~~months ended September~~Months Ended June 30, ~~2017 compared~~2020 Compared to the ~~three months ended September~~Three Months Ended June 30, ~~2016~~2019

~~We reported net loss~~Net income for the three months ended ~~September~~June 30, ~~2017~~2020 of ~~$0.3~~$0.6 million, ~~compared~~compares to a net loss of ~~$14.8~~$1.0 million for the same period of ~~2016.~~2019. The net loss for the three months ended ~~September~~June 30, ~~2017 is~~2019 was inclusive of ~~the~~ loss from discontinued operations ~~for the same period~~ of $0.2 million. ~~The net loss for the three months ended September 30, 2016 was inclusive~~


	Three Months Ended June 30,
	2020		2019		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		631		357		274
Average crude oil sales price (per Bbl)	$	28.31	$	68.62	$	(40.31)

Net crude oil revenue	$	17,974	$	25,230	$	(7,256)

Operating costs and expenses:
Production expense		12,126		9,819		2,307
Depreciation, depletion and amortization		2,801		1,909		892
General and administrative expense		3,019		2,728		291
Bad debt expense		179		5		174
Total operating costs and expenses		18,125		14,461		3,664
Other operating expense, net		(815)		(4,399)		3,584
Operating income (loss)	$	(966)	$	6,370	$	(7,336)

Table of ~~the loss from discontinued operations for the same period of $15.8 million. Further discussion of results by significant line item follows.~~Contents

~~Oil~~Crude oil and natural gas revenues ~~increased $3.5~~ decreased $7.3 million, or approximately ~~24.2%~~28.8%, during the three months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016.~~2019. The ~~increase~~decrease in revenue is attributable to lower sales prices as described below partially offset by higher ~~realized oil prices, due to increases in the Dated Brent market price as well as higher volumes attributable to the Sojitz acquisition. This was offset in part by an overall decrease in sales~~ volumes.

The revenue changes in the three months ended ~~September~~June 30, ~~2017~~2020 compared to the ~~three months ended September 30, 2016,~~same period in 2019 identified as related to changes in price or volume, are shown in the table below:

Three Months Ended September 30,

2017

2016
Gabon net oil production (MBbls)

341

347

Gabon net oil sales (MBbls)

336

343
U.S. net oil sales (MBbls)

—

1
Net oil sales (MBbls)

336

344
Net natural gas sales (MMcf)

—

32
Net oil equivalents (MBOE)

336

349

Average realized oil price ($/Bbl)

$
51.10

$
40.00
Average realized natural gas price ($/Mcf)

—

2.37
Weighted average realized price ($/BOE)

51.10

39.61
Average Dated Brent spot* ($/Bbl)

52.10

45.80
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.


	Three Months Ended June 30,
	2020		2019
Gabon net crude oil production (MBbls)		492		333
Gabon net crude oil sales (MBbls)		631		357

Average realized crude oil price ($/Bbl)	$	28.31	$	68.62
Average Dated Brent spot price* ($/Bbl)		29.70		69.04
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

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Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made ~~three~~four liftings induring both of the ~~third quarters of both 2017~~three-month periods ended June 30, 2020 and ~~2016.~~2019. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately ~~42,000~~47,142 and ~~39,000~~21,526 barrels at ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, respectively. The average realized price for the three months ended June 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 June 30, 2020 were higher than the comparable 2019 period primarily due to the new development wells brought onto production.

Production expenses increased ~~$3.2~~$2.3 million, or approximately ~~44.3%~~23.5%, in the three months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016. Excluding workovers (a component~~2019. The increase in expense was related to a significant decrease in crude inventory levels during the second quarter of ~~total~~2020 compared to the second quarter of 2019. On a per barrel basis, production ~~expenses),~~expense, excluding workover expense, for the three months ended June 30, 2020 decreased to $19.31 per barrel from $27.45 per barrel for the three months ended June 30, 2019 primarily as a result of an increase ~~is primarily~~in sales volumes. While we have not experienced any material operational disruptions associated with the ~~result of: our increased ownership interest~~current worldwide COVID-19 pandemic we have incurred approximately $0.8 million in ~~the Etame Marin block of Gabon after the November 2016 Sojitz acquisition,~~higher costs related to the ~~planned maintenance turnaround, asset integrity work performed during~~proactive measures taken in response to the ~~planned turnaround~~pandemic.

Depreciation, depletion and amortization costs increased due to higher depletable costs associated with ~~certain regulatory requirements~~new wells brought online during the fourth quarter of 2019 and first quarter of 2020.

General and administrative expenses increased $0.3 million, or approximately 10.7% in ~~Gabon. Workover costs were minimal in the 2017 period, whereas for the 2016 period we had an adjustment for estimated costs.~~

~~Depreciation, depletion and amortization (“DD&A”)~~ ~~costs were not materially different from~~ the three months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016.~~2019. The increase in expense was primarily related to a $1.4 million increase in SARs expense. SARs liability awards are fair valued. The primary driver to 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. This increase in expense was offset by lower expense for equity award stock-based compensation, professional fees and travel costs.

~~General~~Bad debt (recovery) expense was higher between the three months ended June 30, 2020 and ~~administrative expenses~~ ~~increased $0.9~~2019 primarily due to bad debt expense associated with the valued added tax allowance.

Other operating expense, net decreased $3.6 million ~~or approximately 55.1%~~ in the three months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016. Personnel costs were higher~~2019. The decrease in ~~2017 as a result of higher stock-based compensation as 2016 included the benefit~~expense was primarily related to ~~employee forfeitures. This~~a $4.4 million charge that was ~~offset by lower wages and employee benefits~~recorded during the second quarter of 2019 for an agreement in ~~2017.~~ principle to resolve a legacy issue related to findings from Etame joint ventures owners’ audits for the periods from 2007 through 2016.

~~Bad debt expense and other~~ ~~was not materially different~~ Interest income, net for the three months ended ~~September~~June 30, ~~2017~~2020 and ~~2016 related primarily~~2019 both relate to ~~the allowance for the Value added tax receivable (“VAT”).~~interest income on cash balances.

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

~~Interest expense~~ ~~for the three months ended September 30, 2017 and 2016 relates~~Derivative instruments gain (loss), net is attributable to our ~~“Term Loan”~~swaps as discussed in Note ~~5 to the condensed consolidated financial statement.~~

~~Other, net~~ ~~for the three months ended September 30, 2017 and 2016 consists primarily of foreign currency gains and derivative instrument losses, as discussed in Note 7~~8 to the condensed consolidated financial statements.

~~Income tax expense~~ ~~increased $0.6~~ The $0.8 million in the three months ended September 30, 2017 compared to the same period of 2016. Income tax expense in both periods is primarily attributable to our operations in Gabon, and is higher in 2017 than income tax for the comparable 2016 period as a result of higher revenues.

~~Loss from discontinued operations~~loss for the three months ended ~~September~~June 30, ~~2017~~2020 is a result of the increase in the price of Dated Brent crude oil during the three months ended June 30, 2020 as compared to a decrease in the price of Dated Brent crude oil during the comparable prior year period that resulted in $1.9 million in gains. 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. As a result, we do not currently expect to have a gain or loss on derivative instruments for periods after June 2020.

Other, net for the three months ended June 30, 2020 and ~~2016~~2019 primarily consists of foreign currency gains as discussed in Note 1 to the condensed consolidated financial statements.

Income tax benefit for the three months ended June 30, 2020 was $(2.2) million. This is comprised of $(3.4) million of deferred tax benefit and a current tax expense of $1.2 million. The deferred income tax expense for the three months ended June 30, 2020 included a $4.1 million decrease to the valuation allowances on U.S. and Gabonese deferred tax assets offset by a $0.7 million deferred tax expense. The three months ended June 30, 2019, includes $5.9 million of deferred tax expense and a current tax expense of $3.3 million. For both the three months ended June 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. Additionally, the $4.4 million joint venture owners’ audit settlement 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.

Income (loss) from discontinued operations for the three months ended June 30, 2020 and 2019 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The ~~small~~ loss from discontinued operations for the three months ended ~~September~~June 30, ~~2017 was related to ongoing administration costs. The loss from discontinued operations for the three months ended September 30, 2016~~2020 and 2019 was primarily related to Angola administration costs.

Six Months Ended June 30, 2020 Compared to the ~~$15.0 million accrual~~Six Months Ended June 30, 2019

Net loss for the ~~potential payment of the drilling obligations in exploration costs and $0.4 million in ongoing administration costs.~~

~~Nine~~six months ended ~~September~~June 30, ~~2017 compared~~2020 of $52.2 million, compares to ~~the nine months ended September 30, 2016~~

~~We reported~~ net income ~~for the nine months ended September 30, 2017~~ of ~~$6.2 million, compared to a net loss of $22.9~~$5.5 million for the same period of ~~2016. These amounts~~2019. The decrease in operating results for the six months ended June 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 $42.8 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 ~~(loss) were~~for the six months ended June 30, 2019 was inclusive of ~~our loss~~income from discontinued operations ~~for the nine months ended September 30, 2017~~ of ~~$0.5 million, and loss from discontinued operations for the nine months ended September 30, 2016 of $8.0~~$5.5 million. ~~Further discussion of results by significant line item follows.~~

~~Oil~~million


	Six Months Ended June 30,
	2020		2019		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		925		654		271
Average crude oil sales price (per Bbl)	$	38.24	$	66.60	$	(28.36)

Net crude oil revenue	$	36,363	$	44,995	$	(8,632)

Operating costs and expenses:
Production expense		21,875		18,038		3,837
Depreciation, depletion and amortization		5,904		3,462		2,442
Impairment of proved crude oil and natural gas properties		30,625		—		30,625
General and administrative expense		3,773		7,167		(3,394)
Bad debt (recovery) expense		989		(24)		1,013
Total operating costs and expenses		63,166		28,643		34,523
Other operating expense, net		(846)		(4,436)		3,590
Operating income (loss)	$	(27,649)	$	11,916	$	(39,565)

Crude oil and natural gas revenues ~~increased $15.4~~ decreased $8.6 million, or approximately ~~34.7%~~19.2%, during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016. A substantial portion of the increase~~2019. The decrease in revenue is ~~related~~attributable to ~~higher realized oil~~lower sales prices as ~~well as~~described below partially offset by higher ~~volumes attributable to the Sojitz acquisition. This was offset in part by an overall decrease in sales~~ volumes.

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The revenue changes in the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2019, identified as related to changes in price or volume, are shown in the table below:


(in thousands)
~~(in thousands)~~Price		$	(26,231)
~~Price~~Volume		$	~~15,808~~ 18,048
~~Volume~~Other			~~(832)~~ (449)
~~Other~~			~~435~~
$	(8,632)	$	~~15,411~~

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Nine Months Ended September 30,

2017

2016
Gabon net oil production (MBbls)

1,154

1,181

1,143

1,159
U.S. net oil sales (MBbls)

—

2
Net oil sales (MBbls)

1,143

1,161
Net natural gas sales (MMcf)

—

99
Net oil equivalents (MBOE)

1,143

1,178

Average realized oil price ($/Bbl)

$
49.86

$
36.03
Average realized natural gas price ($/Mcf)

—

1.85
Weighted average realized price ($/BOE)

49.86

35.68
Average Dated Brent spot* ($/Bbl)

51.75

41.86
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.


	Six Months Ended June 30,
	2020		2019
Gabon net crude oil production (MBbls)		942		648
Gabon net crude oil sales (MBbls)		925		654

Average realized crude oil price ($/Bbl)	$	38.24	$	66.60
Average Dated Brent spot price* ($/Bbl)		40.23		66.07
*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~~six and seven liftings ~~for~~during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016.~~2019, respectively. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately ~~42,000~~47,142 and ~~39,000~~21,526 barrels at ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, respectively. The average realized price for the six months ended June 30, 2020 reflects the impact from the significant decline in crude oil prices as discussed above in “Recent Developments.” Production volumes for the six months ended June 30, 2020 were higher than the comparable 2019 period primarily due to the new development wells brought onto production.

Production expenses increased ~~$2.4~~$3.8 million, or approximately ~~9.3%~~21.3%, in the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016,~~2019. The increase in expense was primarily related to higher workover expense of $2.8 million during the six months ended June 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 six months ended June 30, 2020 decreased to $20.61 per barrel from $27.38 per barrel for the six months ended June 30, 2019 primarily as a result of ~~our increased ownership~~an increase in sales volumes. While we have not experienced any material operational disruptions associated with the ~~Etame Marin block of Gabon after the November 2016 Sojitz acquisition,~~current worldwide COVID-19 pandemic, we have incurred approximately $0.8 million in higher costs related to the ~~planned maintenance turnaround, asset integrity work performed during~~proactive measures taken in response to the ~~planned turnaround,~~pandemic.

Depreciation, depletion and amortization costs increased due to higher depletable costs associated with ~~certain regulatory requirements in Gabon, custom fees~~new wells brought online during the fourth quarter of 2019 and ~~FPSO cost escalation.~~ first quarter of 2020.

~~Depreciation, depletion~~Impairment of proved crude oil and ~~amortization (“DD&A”)~~natural gas properties for the six months ended June 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 ~~$0.2~~$3.4 million, or approximately ~~4.3%,~~47.4% in the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016~~2019. The decrease in expense was primarily related to a $3.1 million decrease in SARs expense and $0.4 million in stock-based compensation from equity awards. SARs liability awards are fair valued. The primary driver to 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.

Bad debt (recovery) expense was higher between the six months ended June 30, 2020 and 2019 primarily due to bad debt expense associated with the ~~favorable impact of depleting our costs over a higher reserve base as a result of improvements in estimated reserves identified at December 31, 2016 as well as lower production.~~valued added tax allowance.

~~General and administrative expenses~~ ~~increased $0.8~~Other operating expense, net decreased $3.6 million ~~or approximately 10.4%~~ in the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 compared to the same period of ~~2016.~~2019. The ~~increase~~decrease in expense was primarily related to ~~higher legal fees~~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 six months ended June 30, 2020 and ~~accounting and auditing costs offset by lower personnel costs. Personnel costs were lower~~2019 both relate to interest income on cash balances.

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Derivative instruments gain (loss), net is attributable to our swaps as discussed in ~~2017 as~~Note 8 to the condensed consolidated financial statements. The $6.6 million gain for the six months ended June 30, 2020 is a result of ~~lower wages and employee benefits offset by higher stock-based compensation~~the decrease in the price of Dated Brent crude oil during the six months ended June 30, 2020 as ~~2016 included~~compared to an increase in the ~~benefit related~~price of Dated Brent crude oil that resulted in a small loss 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 ~~employee forfeitures.~~hedge against declining crude oil prices. As a result, we do not currently expect to have a gain or loss on derivative instruments for periods after June 2020.

~~Bad debt expense and other~~

Other, net for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016 related~~2019 primarily ~~to the allowance on the Value added tax (“VAT”) receivable.~~

~~Other operating expenses~~ for the nine months ended September 30, 2016 included $2.1 million accrued for certain unpaid payroll taxes in Gabon which were not paid pertaining to labor provided to us over a number of years by a third-party contractor and $7.6 million, net to VAALCO, of expense associated with the demobilization and release of the contracted drilling rig. In June 2016, we reached an agreement with the drilling contractor to pay less than our originally estimated maximum day rate, plus demobilization costs, in seven equal monthly installments beginning in July 2016. In January 2017, we resolved the Gabon payroll tax obligation.

~~General and administrative related to shareholder matters��for the nine months ended September 30, 2016 reflects offsetting insurance proceeds related to costs incurred on shareholder litigation that was settled in 2016.~~

~~Other, net~~ ~~for the nine months ended September 30, 2017 and 2016~~ consists ~~primarily~~ of foreign currency ~~gains and derivative instrument~~ losses as discussed in Note 71 to the condensed consolidated financial statements.

~~Interest~~Income tax expense for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 was $31.2 million. This is comprised of $32.2 million of deferred tax expense and ~~2016 relates to our “Term Loan” as discussed in Note 5 to~~a current tax benefit of $(1.0) million. The deferred income tax expense for the ~~condensed consolidated financial statement.~~

~~Income tax expense~~ ~~increased $2.2 million in the nine~~six months ended ~~September~~June 30, ~~2017 compared~~2020 included a $42.8 million charge to increase the ~~same period~~valuation allowances on U.S. and Gabonese deferred tax assets offset by a $(10.7) million deferred tax benefit. The current tax benefit of ~~2016. Income tax expense in both periods is primarily attributable to our operations in Gabon and is higher in 2017 than income tax for the comparable 2016 period~~$(1.0) million includes a $4.3 million favorable oil price adjustment as a result of ~~higher revenues.~~ 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 $3.3 million for the period. The six months ended June 30, 2019, includes $7.7 million of deferred tax expense and a current tax provision of $4.3 million. For the six months ended June 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.

~~Loss~~Gain (loss) from discontinued operations for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and 2019 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The ~~loss~~gain from discontinued operations for the ~~2017 period is~~six months ended June 30, 2019 was related to ~~ongoing administrative costs. For~~recording a $5.7 million after tax gain on the ~~nine months ended September 30, 2016, we reported loss from discontinued operations primarily~~finalized Angola settlement as ~~a result of $3.1 million of income tax on~~discussed in Note 3 to the condensed consolidated financial ~~gains and $15.0 million accrual for the potential payment of drilling obligations offset by $7.6 million of bad debt recovery and $3.2 million of collected default interest.~~statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

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

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While 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 ~~Fran,~~Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon isare 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.

I~~nterest Rate Risk~~

~~The floating interest rate on our amended loan agreement exposes us to risks associated with changes in interest rates (LIBOR). At September~~ As of June 30, ~~2017 and December 31, 2016,~~2020, we had ~~$11.0~~net monetary assets of $6.4 million (XAF 3,775 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 six months ended June 30, 2020, we had expenditures of approximately $2.9 million and ~~$14.4~~$5.9 million, respectively, ~~which include deferred financing costs of $0.3 million and $0.6 million, respectively,~~(net to VAALCO), denominated in borrowings outstanding with the IFC. Fluctuations in floating interest rates will cause our interest costs to fluctuate. For the nine months ended September 30, 2017 and 2016, the average effective interest rates on our debt, excluding commitment fees, were 6.87% and 5.04%, respectively. If the balance of the debt at September 30, 2017 were to remain constant, a 1% change in market interest rates would impact our cash flow by an estimated $0.1 million per year. As future quarterly repayments of the loan reduce the principal amount of the Term Loan, our cash flow becomes less sensitive to fluctuations in interest rate. XAF.

~~COUNTERPARTY Risk~~

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

Commodity Price Risk

Our major market risk exposure continues to be the prices received for our crude oil ~~and natural gas~~ 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. Beginning in the third quarter of 2014, the prices for oil and natural gas began a dramatic decline which continued through the first half of 2016. Current prices remain significantly lower than they were in years prior to 2015. Sustained lowMore recently, crude oil and natural gas prices orhave been in the midst of an unprecedented decline due to a ~~resumption~~combination of factors, including a substantial decline in global demand for crude oil caused by the ~~decreases in~~COVID-19 pandemic and subsequent mitigation efforts. We cannot predict the ultimate long-term impact on crude oil ~~and natural gas~~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 ~~336~~631 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a ~~$1.7~~$3.2 million decrease per quarter ($~~6.8~~12.8 million annualized) in revenues and operating income ~~(loss)~~ and a ~~$1.4~~$2.9 million decrease per quarter ($~~5.8~~11.5 million annualized) in net income.

As of ~~September~~June 30, ~~2017,~~2020, we ~~had unexpired oil puts with a fair value asset position of $0.1 million. While these~~did not have any crude oil swaps outstanding. In the past, we have used derivative ~~contracts are intended to be~~instruments as an economic hedge ~~they are~~against declines in crude oil prices; however, such instruments were not designated as hedges for accounting purposes. ~~The contracts are measured at fair value at the end~~Our derivative instruments only covered a portion of ~~each quarter, with changes in value flowing~~our production through ~~net income. See Note 7 to the condensed consolidated financial statements for further information about these contracts, their fair value~~June 2020 and ~~their impact on our net income.~~have expired.

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ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on ~~this~~their evaluation ~~the~~as of June 30, 2020, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were ~~not effective due~~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 ~~existence of previously reported~~manner in which controls were performed, these changes did not have a material ~~weaknesses as of the end of the period covered by this Quarterly Report~~effect on ~~Form 10-Q. The material weaknesses were identified and discussed in “Part II – Item 9A – Controls and Procedures” of our Annual Report on Form 10-K for the year ended December 31, 2016.~~

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

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~~DESCRIPTION OF MATERIAL WEAKNESSES~~

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

~~Our management conducted an assessment of the effectiveness of~~ our internal control over financial reporting, ~~as of December 31, 2016. This assessment was based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in~~ ~~Internal Control—Integrated Framework~~ (2013 framework). Based on this assessment, because of the effect of the material weaknesses, as described in the following paragraph, management determined that our internal control over financial reporting was not effective as of December 31, 2016. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such thatand there ~~is a reasonable possibility that a material misstatement of our annual or interim financial statements could occur but will not be prevented or detected on a timely basis.~~

At December 31, 2016, management determined that the effectiveness and timeliness of the performance of controls related to the review of financial reports, the review of account reconciliations and the evaluation and reporting of significant and unusual transactions was not adequate to ensure that the material weakness in internal control identified in 2015 had been fully remediated. Management also determined that as of December 31, 2016 there was a material weakness related to the execution of the control for the physical count of operational spares (included in the “Equipment and other” line item in the consolidated balance sheet) which is performed annually to validate its existence.

~~REMEDIATION EFFORTS TO ADDRESS MATERIAL WEAKNESSES~~

In response to the identified material weaknesses at December 31, 2016, our management, with oversight from our Audit Committee, has taken the following actions to remediate the material weaknesses described above:

~~Hired additional permanent employees for key roles in accounting and finance, which had previously been performed by professional consultants.~~

Improved the timing of the periodic financial close, reporting process and analysis of results through the use of a detailed financial close plan and expanding reporting of financial data to senior management.

~~In addition, management is taking actions to train personnel and improve policies and procedures related to the periodic validation of equipment used in operations.~~

Management is committed to improving our internal control processes and believes that the measures described above should remediate the material weaknesses identified and strengthen internal control over financial reporting. As we continue to evaluate and improve internal control over financial reporting, additional measures to remediate the material weaknesses or modifications to certain of the remediation procedures described above may be necessary. We expect to complete the required remedial actions during the fourth quarter of 2017.

While senior management and our Audit Committee are closely monitoring the implementation of these remediation plans, we cannot provide any assurance that these remediation efforts will be successful or that internal control over financial reporting will be effective as a result of these efforts. Until the remediation steps set forth above are fully implemented and operating for a sufficient period of time, the material weaknesses that exist at September 30, 2017 will continue to exist.

~~CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING~~

~~Except for the activities taken related to the remediation of the material weaknesses described above, there~~ were no changes in our internal control over financial reporting that occurred during the three months ended ~~September~~June 30, ~~2017~~2020 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. It is management’s opinion that all claims and litigation we are currently involved in are not ~~likely~~material to ~~have a material adverse effect on~~ our ~~consolidated financial position, cash flows or results of operations.~~business.

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ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

The following risk factors represent material changes to the risk factors disclosed under Item 1A. “Risk Factors” in our 2019 Form 10-K. For ~~a discussion~~additional information concerning of our potential risks and uncertainties, see the information in Item 1A “Risk Factors” in our ~~2016~~2019 Form 10-K. ~~There~~

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 September 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 ~~no material~~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 ~~risk~~control. These factors include, but are not limited to, increases in supplies from ~~those described~~U.S. shale production, international political conditions, including uprisings and political unrest in ~~our 2016 Form 10-K.~~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

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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 $42 per barrel for Brent crude as of June 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;

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

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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.

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 unless 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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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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 has repurchased 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 Exchange Act.

The following table represents details of the various repurchases during the quarter ended June 30, 2020:


Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Programs			Maximum Amount that May Yet Be Used to Purchase Shares Under the Program
April 1, 2020 - April 30, 2020	196,977	⁽¹⁾	$	0.99	191,004	⁽²⁾	$	5,338,383	⁽²⁾
May 1, 2020 - May 31, 2020	—			—	—			—
June 1, 2020 - June 30, 2020	—			—	—			—
	196,977		$	0.99	191,004

(1)Includes shares to satisfy tax withholding obligations related to restricted stock vesting. See Note 14 to the condensed consolidated financial statements for further discussion.

(2)Pursuant to the stock repurchase program announced on June 20, 2019, the Board of Directors authorized the Company to purchase (in the aggregate) up to $10.0 million of the outstanding shares of the Company’s common stock in open market purchases, privately negotiated transactions or by other means for a period of 12 months. The Board of Directors terminated this stock repurchase program on April 13, 2020.

See Note 13 to the condensed consolidated financial statements for further discussion. On April 13, 2020, the Board of Directors approved terminating the share repurchase program; consequently, no further shares can be repurchased pursuant to the plan.

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ITEM 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	~~Second Amended and Restated Bylaws (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on September 28, 2015, and incorporated herein by reference).~~
~~3.3~~	~~First Amendment to the Second~~Third Amended and Restated Bylaws (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on ~~December 23, 2015,~~August 4, 2020, and incorporated herein by reference).
~~31.1~~10.~~(a)~~1*	VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed on April 29, 2020, and incorporated herein by reference).
10.2*	Form of Restricted Stock Award Agreement (Director) under the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 30, 2020, and incorporated herein by reference).
10.3*	Form of Restricted Stock Award Agreement (Employee) under the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on June 30, 2020, and incorporated herein by reference).
10.4*	Form of Nonqualified Stock Option Agreement under the VAALCO Energy, Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on June 30, 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.

‎

2943

Table of Contents

SIGNATURE

~~In accordance with~~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/ ~~Philip F. Patman, Jr.~~Elizabeth D. Prochnow
		~~Philip F. Patman, Jr.~~Elizabeth D. Prochnow
		Chief Financial Officer (~~on behalf of the Registrant)~~duly authorized officer and principal financial officer)

Dated: ~~November 8, 2017~~August 6, 2020

3044


		Carrying		Fair Value Measurements Using
Derivative Item	Balance Sheet Line	Value		Level 1		Level 2		Level 3
		(in thousands)
Crude oil puts	Prepayments and other
Balance at September 30, 2017		$	61	$	—	$	61	$	—
Balance at December 31, 2016		$	1,227	$	—	$	1,227	$	—



	Three Months Ended September 30, 2017
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	18,162	$	—	$	16	$	—	$	18,178
Depreciation, depletion and amortization		1,633		—		—		67		1,700
Bad debt expense and other		(49)		—		—		—		(49)
Operating income (loss)		6,067		(44)		10		(2,312)		3,721
Interest expense, net		(327)		—		—		—		(327)
Income tax expense		2,749		—		—		—		2,749
Additions to property and equipment - accrual		237		—		—		60		297


	Three Months Ended September 30, 2016
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	14,540	$	—	$	95	$	—	$	14,635
Depreciation, depletion and amortization		1,508		—		38		61		1,607
Impairment of proved properties		—		—		88		—		88
Bad debt expense and other		63		—		—		—		63
Other operating expense		324		—		—		—		324
Operating income (loss)		5,013		(184)		(61)		(1,078)		3,690
Interest income (expense), net		(329)		—		—		2		(327)
Income tax expense (benefit)		2,305		—		—		(107)		2,198
Additions to property and equipment - accrual		674		—		—		7		681


	Nine Months Ended September 30, 2017
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	59,823	$	—	$	46	$	—	$	59,869
Depreciation, depletion and amortization		5,344		—		1		194		5,539
Bad debt expense and other		232		—		—		—		232
Operating income (loss)		25,117		(97)		356		(7,920)		17,456
Interest expense, net		(1,108)		—		—		—		(1,108)
Income tax expense		9,039		—		—		—		9,039
Additions to property and equipment - accrual		1,051		—		—		60		1,111


	Nine Months Ended September 30, 2016
(in thousands)	Gabon		Equatorial Guinea		U.S.		Corporate and Other		Total
Revenues-oil and natural gas sales	$	44,212	$	—	$	246	$	-	$	44,458
Depreciation, depletion and amortization		5,484		—		121		182		5,787
Impairment of proved properties		—		—		88		—		88
Bad debt expense and other		577		—		—		—		577
Other operating expense		9,959		—		—		—		9,959
Operating income (loss)		1,481		(319)		(64)		(6,308)		(5,210)
Interest expense, net		(2,285)		—		—		—		(2,285)
Income tax expense		6,884		—		—		—		6,884
Additions to property and equipment - accrual		(1,819)		—		140		7		(1,672)


	Nine Months Ended September 30,				Increase
	2017		2016		(Decrease)
	(in thousands)
Net cash provided by (used in) operating activities	$	3,232	$	(36)	$	3,268
Net cash provided by (used in) investing activities		(1,123)		1,655		(2,778)
Net cash used in financing activities		(3,720)		(93)		(3,627)
Net change in cash and cash equivalents	$	(1,611)	$	1,526	$	(3,137)

(in thousands)

~~3,730~~
(25,436)

~~(396)~~
18,802

~~209~~
(622)

~~3,543~~
(7,256)