egy-20190930x10q

(in thousands)

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________

FORM 10-Q

________________________________

(Mark One)

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

For the quarterly period ended September 30, 2019

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

For the transition period from _______ to _______

Commission file number 1-32167

________________________________

VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)

________________________________


Delaware		76-0274813
(State or other jurisdiction of Incorporation or organization)		(I.R.S. Employer Identification No.)

9800 Richmond Avenue Suite 700 Houston, Texas		77042
(Address of principal executive offices)		(Zip code)

(713) 623-0801

(Registrant’s telephone number, including area code)

________________________________

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



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

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

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

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 31, 2019, there were outstanding 58,387,504 shares of common stock, $0.10 par value per share, of the registrant.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets
September 30, 2019 and December 31, 2018	3
Condensed Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2019 and 2018	4
Condensed Consolidated Statements of Shareholders’ Equity
Three and Nine Months Ended September 30, 2019 and 2018	5
Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2019 and 2018	6
Notes to Condensed Consolidated Financial Statements	8
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
ITEM 4. CONTROLS AND PROCEDURES	37
PART II. OTHER INFORMATION	38
ITEM 1. LEGAL PROCEEDINGS	38
ITEM 1A. RISK FACTORS	38
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES	38
ITEM 6. EXHIBITS	39

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

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PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands, except share and per share amounts)


	September 30, 2019		December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	57,227	$	33,360
Restricted cash		769		804
Receivables:
Trade		7,503		11,907
Accounts with joint venture owners, net of allowance of $0.5 million for both periods presented		113		949
Other		1,160		1,398
Crude oil inventory		775		785
Prepayments and other		6,996		6,301
Current assets - discontinued operations		—		3,290
Total current assets		74,543		58,794
Oil and natural gas properties and equipment - successful efforts method:
Wells, platforms and other production facilities		409,995		409,487
Work-in-progress		5,303		519
Undeveloped acreage		23,771		23,771
Equipment and other		12,523		9,552
		451,592		443,329
Accumulated depreciation, depletion, amortization and impairment		(394,975)		(390,605)
Net oil and natural gas properties, equipment and other		56,617		52,724
Other noncurrent assets:
Restricted cash		924		920
Value added tax and other receivables, net of allowance of $1.3 million and $2.0 million, respectively		3,035		2,226
Right of use operating lease assets		36,852		—
Deferred tax assets		25,903		40,077
Abandonment funding		11,112		11,571
Total assets	$	208,986	$	166,312
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	6,658	$	8,083
Accounts with joint venture owners		11,828		304
Accrued liabilities and other		23,886		14,138
Operating lease liabilities - current portion		12,432		—
Foreign taxes payable		3,211		3,274
Current liabilities - discontinued operations		326		15,245
Total current liabilities		58,341		41,044
Asset retirement obligations		15,709		14,816
Operating lease liabilities - net of current portion		24,397		—
Other long term liabilities		652		625
Total liabilities		99,099		56,485
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock, $25 par value; 500,000 shares authorized, none issued		—		—
Common stock, $0.10 par value; 100,000,000 shares authorized, 67,478,897 and 67,167,994 shares issued, 58,593,068 and 59,595,742 shares outstanding, respectively		6,748		6,717
Additional paid-in capital		73,263		72,358
Less treasury stock, 8,885,829 and 7,572,251 shares, respectively, at cost		(39,943)		(37,827)
Retained earnings		69,819		68,579
Total shareholders' equity		109,887		109,827
Total liabilities and shareholders' equity	$	208,986	$	166,312

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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands, except per share amounts)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenues:
Oil and natural gas sales	$	17,603	$	25,266	$	62,598	$	77,337
Operating costs and expenses:
Production expense		9,836		7,481		27,874		31,258
Exploration expense		—		—		—		12
Depreciation, depletion and amortization		1,509		1,130		4,971		3,289
Gain on revision of asset retirement obligations		—		(3,325)		—		(3,325)
General and administrative expense		4,738		2,811		11,905		10,422
Bad debt (recovery) expense		54		(157)		30		(68)
Total operating costs and expenses		16,137		7,940		44,780		41,588
Other operating income (expense), net		35		(6)		(4,401)		332
Operating income		1,501		17,320		13,417		36,081
Other income (expense):
Derivative instruments gain (loss), net		2,267		(1,026)		2,266		(2,036)
Interest income (expense), net		193		111		581		(273)
Other, net		(138)		(3)		(521)		(148)
Total other income (expense), net		2,322		(918)		2,326		(2,457)
Income from continuing operations before income taxes		3,823		16,402		15,743		33,624
Income tax expense (benefit)		7,681		(62,224)		19,642		(54,600)
Income (loss) from continuing operations		(3,858)		78,626		(3,899)		88,224
Income (loss) from discontinued operations, net of tax		(61)		(21)		5,448		(416)
Net income (loss)	$	(3,919)	$	78,605	$	1,549	$	87,808

Basic net income (loss) per share:
Income (loss) from continuing operations	$	(0.07)	$	1.31	$	(0.07)	$	1.48
Income (loss) from discontinued operations, net of tax		0.00		0.00		0.09		(0.01)
Net income (loss) per share	$	(0.07)	$	1.31	$	0.02	$	1.47
Basic weighted average shares outstanding		58,953		59,481		59,457		59,147
Diluted net income (loss) per share:
Income (loss) from continuing operations	$	(0.07)	$	1.28	$	(0.07)	$	1.46
Income (loss) from discontinued operations, net of tax		0.00		0.00		0.09		(0.01)
Net income (loss) per share	$	(0.07)	$	1.28	$	0.02	$	1.45
Diluted weighted average shares outstanding		58,953		60,818		59,457		59,846

See notes to condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)

(in thousands)


	Common Shares Issued	Treasury Shares	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings		Total
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 acquired	—	(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 acquired	—	(79)		—		—		62		(309)		(247)
Net loss	—	—		—		—		—		(1,033)		(1,033)
Balance at June 30, 2019	67,452	(7,696)		6,745		73,059		(37,870)		73,738		115,672
Shares issued - stock-based compensation	27	—		3		23		—		—		26
Stock-based compensation expense	—	—		—		181		—		—		181
Treasury stock acquired	—	(1,190)		—		—		(2,073)		—		(2,073)
Net loss	—	—		—		—		—		(3,919)		(3,919)
Balance at September 30, 2019	67,479	(8,886)	$	6,748	$	73,263	$	(39,943)	$	69,819	$	109,887


	Common Shares Issued	Treasury Shares	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings (Deficit)		Total
Balance at January 1, 2018	66,444	(7,581)	$	6,644	$	71,251	$	(37,953)	$	(29,653)	$	10,289
Stock-based compensation expense	—	—		—		149		—		—		149
Net income	—	—		—		—		—		8,659		8,659
Balance at March 31, 2018	66,444	(7,581)		6,644		71,400		(37,953)		(20,994)		19,097
Shares issued - stock-based compensation	522	36		52		216		177		—		445
Stock-based compensation expense	—	—		—		397		—		—		397
Net income	—	—		—		—		—		544		544
Balance at June 30, 2018	66,966	(7,545)		6,696		72,013		(37,776)		(20,450)		20,483
Shares issued - stock-based compensation	127	(9)		13		80		(22)		—		71
Stock-based compensation expense	—	—		—		136		—		—		136
Net income	—	—		—		—		—		78,605		78,605
Balance at September 30, 2018	67,093	(7,554)	$	6,709	$	72,229	$	(37,798)	$	58,155	$	99,295

See notes to condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)


	Nine Months Ended September 30,
	2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,549	$	87,808
Adjustments to reconcile net income to net cash provided by operating activities:
(Income) loss from discontinued operations		(5,448)		416
Depreciation, depletion and amortization		4,971		3,289
Gain on revision of asset retirement obligations		—		(3,325)
Other amortization		181		357
Deferred taxes		12,725		(66,191)
Unrealized foreign exchange (gain) loss		(46)		819
Stock-based compensation		2,770		3,729
Cash settlements paid on exercised stock appreciation rights		(261)		(82)
Derivatives instruments (gain) loss		(2,266)		2,036
Cash settlements received on matured derivative contracts, net		2,056		28
Bad debt (recovery) expense		30		(68)
Other operating (income) loss, net		37		(332)
Operational expenses associated with equipment and other		(62)		1,695
Change in operating assets and liabilities:
Trade receivables		4,404		3,556
Accounts with joint venture owners		12,354		7,961
Other receivables		219		(313)
Crude oil inventory		10		1,031
Prepayments and other		(1,979)		(13)
Value added tax and other receivables		664		(658)
Deferred tax assets		—		(1,356)
Accounts payable		(2,154)		(4,314)
Foreign taxes payable		(122)		1,775
Accrued liabilities and other		4,092		(850)
Net cash provided by continuing operating activities		33,724		36,998
Net cash used in discontinued operating activities		(4,673)		(958)
Net cash provided by operating activities		29,051		36,040
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures		(3,382)		(13,205)
Net cash used in continuing investing activities		(3,382)		(13,205)
Net cash used in discontinued investing activities		—		—
Net cash used in investing activities		(3,382)		(13,205)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock		133		533
Treasury shares		(2,425)		(22)
Debt repayment		—		(9,166)
Net cash used in continuing financing activities		(2,292)		(8,655)
Net cash used in discontinued financing activities		—		—
Net cash used in financing activities		(2,292)		(8,655)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		23,377		14,180
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		46,655		32,286
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	70,032	$	46,466

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)


	Nine Months Ended September 30,
	2019		2018
Supplemental disclosure of cash flow information:
Interest paid	$	—	$	257
Income taxes paid	$	—	$	2,720
Income taxes paid in-kind with crude oil	$	7,347	$	9,385
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	7,042	$	2,045
Oil and natural gas property additions paid with non-cash assets	$	—	$	4,197
Recognition of right-of-use operating lease assets	$	44,681	$	—
Recognition of right-of-use operating lease liabilities	$	44,656	$	—
Asset retirement obligations	$	292	$	(6,527)

See notes to condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND ACCOUNTING POLICIES

VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO,” or the “Company”) is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, the Company has production operations and conducts exploration activities in Gabon, West Africa. The Company has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, the Company has discontinued operations associated with the Company’s activities in Angola, West Africa.

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

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

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, which includes a summary of the significant accounting policies.

Reclassifications – Certain reclassifications have been made to prior period amounts to conform to the current period presentation related to the presentation of stock based compensation and derivatives on the Company’s condensed consolidated statements of cash flows. These reclassifications had no material impact on the Company’s financial position or results of operations.

Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at September 30, 2019 and December 31, 2018, respectively, each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long term amounts at September 30, 2019 and December 31, 2018 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 11. The Company invests restricted and excess cash in readily redeemable money market funds.

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


	September 30, 2019		December 31, 2018
	(in thousands)
Cash and cash equivalents	$	57,227	$	33,360
Restricted cash - current		769		804
Restricted cash - non-current		924		920
Abandonment funding		11,112		11,571
Total cash, cash equivalents and restricted cash shown in the condensed consolidated balance sheets	$	70,032	$	46,655

The Company is required, under the Exploration and Production Sharing Contract entitled “Etame Marin No. G4-160,” dated as of July 7, 1995, as amended, (the “Etame PSC”) for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts needed to fund the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in November 2018. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on the Company’s condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the Company’s asset retirement obligation and the amount of future abandonment funding payments. See Note 13 for further discussion.

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

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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” line item of the condensed consolidated statements of operations.

As of September 30, 2019, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $8.0 million ($2.7 million, net to VAALCO). As of September 30, 2019, the exchange rate was XAF 599.3 = $1.00. As of December 31, 2018, the exchange rate was XAF 573.0 = $1.00.

For the three and nine months ended September 30, 2019, the Company recorded a net (recovery) expense of $(5) thousand and $24 thousand, respectively, related to the allowance for bad debt for VAT for which the government of Gabon has not reimbursed us. For the three and nine months ended September 30, 2018, the Company recorded a net recovery of $0.2 million and $0.1 million, respectively. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on profit/loss. Such foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019			2018	2019		2018
	(in thousands)
Allowance for bad debt
Balance at beginning of year	$	(1,876)	$	(6,948)	$	(2,535)	$	(7,033)
Bad debt recovery (charge)		(54)		157		(30)		68
Reclassification of leasehold costs related to signing bonus		—		4,197		—		4,197
Adjustment associated with settlement of customs audit		—		—		623		—
Foreign currency gain		53		13		65		187
Balance at end of period	$	(1,877)	$	(2,581)	$	(1,877)	$	(2,581)

Derivative Instruments and Hedging Activities – The Company enters into crude oil hedging arrangements 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.

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).

Fair value of financial instruments – The Company’s assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets, accounts payable 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 the Company’s other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. There were no transfers between levels for the three and nine months ended September 30, 2019 and 2018.

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			As of September 30, 2019
	Balance Sheet Line		Level 1		Level 2		Level 3		Total
			(in thousands)
Assets
Derivative asset commodity swaps		Prepayments and other	$	—	$	3,730	$	—	$	3,730
			$	—	$	3,730	$	—	$	3,730
Liabilities
SARs liability		Accrued liabilities	$	—	$	2,516	$	—	$	2,516
SARs liability		Other long-term liabilities		—		652		—		652
			$	—	$	3,168	$	—	$	3,168

			As of December 31, 2018
	Balance Sheet Line		Level 1		Level 2		Level 3		Total
			(in thousands)
Assets
Derivative asset commodity swaps		Prepayments and other	$	—	$	3,520	$	—	$	3,520
			$	—	$	3,520	$	—	$	3,520
Liabilities
SARs liability		Accrued liabilities	$	—	$	1,007	$	—	$	1,007
SARs liability		Other long-term liabilities		—		625		—		625
			$	—	$	1,632	$	—	$	1,632

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

The Company adopted Accounting Standards Codification (“ASC”) 842 effective January 1, 2019 using the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients that allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The standard had an impact on the Company’s condensed consolidated balance sheet but did not have an impact on the Company’s condensed consolidated statements of operations or condensed consolidated statements of cash flows upon adoption and as a result, a cumulative-effect adjustment was not required. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases. See Notes 2 and 12 for further discussion.

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

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

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A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s 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 an asset retirement asset recorded to oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability is adjusted, with a corresponding adjustment made to the related asset balance or income statement adjustment, 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 oil and natural gas production facilities. Accretion of interest increases the initial ARO liabilities over time until the liability matches the amount expected to settle the related retirement obligation. See Note 13 for further discussion.

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

Foreign currency transactions – The U.S. dollar is the functional currency of the Company’s foreign operating subsidiaries. Gains and losses on foreign currency transactions are included in income. Within the condensed consolidated statements of operations line item “Other income (expense) — Other, net,” the Company recognized a loss on foreign currency transactions of $0.1 million and $0.3 million, respectively, during the three and nine months ended September 30, 2019. During the three and nine months ended September 30, 2018, the Company recognized losses on foreign currency transactions of $0.0 million and $0.1 million, respectively.

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 oil and natural gas industry are open to interpretation that 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.

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, the Company may be required to record additional deferred taxes that could have a material effect on the Company’s consolidated financial position and results of operations. See Note 16 for further discussion.

2. NEW ACCOUNTING STANDARDS

Adopted

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”), which amends the accounting standards for leases. This accounting standard was further clarified by ASU 2018-10, Codification Improvements to Topic 842 and ASU 2018-11, Leases: Targeted Improvements, both of which were issued in July 2018 together (“Topic 842”). Topic 842 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases previously classified as operating leases on the balance sheet under ASC 840 - Leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance under ASC 840 - Leases. Certain aspects of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures

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

Not yet adopted

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in Accounting ASC 350, Intangibles - Goodwill and Other, in making the determination as to which implementation costs are to be capitalized as assets and which costs are to be expensed as incurred. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, and an entity can elect to apply the new guidance on a prospective or retrospective basis. The Company does not expect a material impact of adopting this guidance on the Company’s financial position, results of operations, cash flows and related disclosures.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). This ASU modifies the disclosure requirements for fair value measurements. ASU 2018-13 removes the requirement to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements. ASU 2018-13 requires disclosure of changes in unrealized gains and losses for the period included in other comprehensive income (loss) for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For all entities, ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. The Company does not expect a material impact of adopting this guidance on the Company’s financial position, results of operations and cash flows; however, the Company does expect an expansion to its current disclosures.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The FASB subsequently issued ASU No. 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU No. 2019-05 (“ASU 2019-05”): Financial Instruments-Credit Losses (Topic 326) - Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In August 2019, the FASB issued a request for comment under Project ASU No. 2019-750, Financial Instruments—Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. The proposal, which is expected to be finalized in November 2019, would defer the effective date of ASU No. 2016-13 from January 1, 2020 to January 1, 2023 for calendar year smaller reporting companies. The Company is currently evaluating the provisions of ASU 2016-13 and is assessing its potential impact on the Company’s financial position, results of operations, cash flows and related disclosures.

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3. DISPOSITIONS

Discontinued Operations - Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was 40%, and the Company carried Sonangol P&P, for 10% of the work program. On September 30, 2016, the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, the Company notified the national concessionaire, Sonangol E.P., that it was withdrawing from the Block 5 PSA. Further to the decision to withdraw from Angola, the Company closed its office in Angola and reduced its activities in Angola. As a result of this strategic shift, the Company classified all the related assets and liabilities as those of discontinued operations in the condensed consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in the Company’s condensed consolidated statements of operations. The Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in the Company’s condensed consolidated statements of cash flows. The following tables summarize selected financial information related to the Angola segment’s assets and liabilities as of September 30, 2019 and December 31, 2018 and its results of operations for the three and nine months ended September 30, 2019 and 2018.

Summarized Results of Discontinued Operations


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Operating costs and expenses:
Gain on settlement of drilling obligation	$	—	$	—	$	(7,193)	$	—
General and administrative expense		77		23		297		387
Total operating costs, expenses and (recovery)		77		23		(6,896)		387
Operating income (loss)		(77)		(23)		6,896		(387)
Other income (expense):
Other, net		—		2		—		(29)
Total other income (expense)		—		2		—		(29)
Income (loss) from discontinued operations before income taxes		(77)		(21)		6,896		(416)
Income tax expense (benefit)		(16)		—		1,448		—
Income (loss) from discontinued operations	$	(61)	$	(21)	$	5,448	$	(416)

Assets and Liabilities Attributable to Discontinued Operations



	September 30, 2019		December 31, 2018
	(in thousands)
ASSETS
Accounts with joint venture owners	$	—	$	3,290
Total current assets		—		3,290
Total assets	$	—	$	3,290

LIABILITIES
Current liabilities:
Accounts payable	$	—	$	73
Accrued liabilities and other		326		15,172
Total current liabilities		326		15,245
Total liabilities	$	326	$	15,245

Drilling Obligation

Under the Block 5 PSA, the Company and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases identified in the Block 5 PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The Block 5 PSA provided for a stipulated payment of $10.0 million for each of the three exploration wells for which a drilling obligation remains under the terms of the Block 5 PSA, of which the Company’s participating interest share would be $5.0 million per well. The Company reflected an accrual of $15.0 million for a potential payment as of December 31, 2018. In the first quarter of 2019, the Company and Sonangol E.P. entered into a settlement agreement finalizing the Company’s rights, liabilities and outstanding obligations for Block 5 in Angola. Pursuant to the settlement agreement, the Company agreed to pay $4.5 million to Angola National Agency of Petroleum, Gas, and Biofuels, as National Concessionaire, and to eliminate the $3.3 million receivable

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from Sonangol P&P. The receivable was related to joint interest billings and was reflected as current assets from discontinued operations at year-end 2018. As a result, the Company adjusted a previously accrued liability and recognized a net of tax non-cash benefit from discontinued operations of $5.7 million in the first quarter of 2019. In July 2019, subsequent to the publication of an executive decree from the Ministry of Mineral Resources and Petroleum, the Company paid the $4.5 million due under the settlement agreement.

4. SEGMENT INFORMATION

The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s two reportable operating segments is organized and managed based upon geographic location. 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 location of hydrocarbon production. Corporate and other is primarily corporate and operations support costs that are not allocated to the reportable operating segments.

Segment activity of continuing operations for the three and nine months ended September 30, 2019 and 2018 as well as long-lived assets and segment assets at September 30, 2019 and December 31, 2018 are as follows:


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


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


	Three Months Ended September 30, 2018
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-oil and natural gas sales	$	25,265	$	—	$	1	$	25,266
Depreciation, depletion and amortization		1,065		—		65		1,130
Gain on revision of asset retirement obligations		(3,325)		—		—		(3,325)
Operating income (loss)		19,826		(159)		(2,347)		17,320
Derivatives instruments loss, net		—		—		(1,026)		(1,026)
Income tax benefit		(42,141)		—		(20,083)		(62,224)
Additions to oil and natural gas properties and equipment – accrual		36,595		—		3		36,598

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	Nine Months Ended September 30, 2018
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-oil and natural gas sales	$	77,333	$	—	$	4	$	77,337
Depreciation, depletion and amortization		3,095		—		194		3,289
Gain on revision of asset retirement obligations		(3,325)		—		—		(3,325)
Other operating income (expense), net		332		—		-		332
Operating income (loss)		45,670		(274)		(9,315)		36,081
Derivatives instruments loss, net		-		—		(2,036)		(2,036)
Other, net		(127)		(3)		(18)		(148)
Interest expense, net		(397)		—		124		(273)
Income tax benefit		(34,517)		—		(20,083)		(54,600)
Additions to oil and natural gas properties and equipment – accrual		37,550		—		17		37,567


(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of September 30, 2019	$	46,276	$	10,000	$	341	$	56,617
As of December 31, 2018	$	42,195	$	10,187	$	342		52,724


(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Total assets from continuing operations:
As of September 30, 2019	$	148,221	$	10,085	$	50,680	$	208,986
As of December 31, 2018	$	103,401	$	10,320	$	49,301		163,022

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”). The Company signed a new contract with Mercuria Energy Trading SA (“Mercuria”) that covers sales from February 2019 through January 2020 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. Sales of oil to Glencore and Mercuria were approximately 100% of total revenues for the period during the terms of their contracts.

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5. EARNINGS PER SHARE

Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, 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 from basic to diluted shares follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
		2019		2018		2019		2018
	(in thousands)
Net income (loss) (numerator):
Income from continuing operations	$	(3,858)	$	78,626	$	(3,899)	$	88,224
Income (loss) from continuing operations attributable to unvested shares		—		(766)		29		(820)
Numerator for basic		(3,858)		77,860		(3,870)		87,404
Loss from continuing operations attributable to unvested shares		—		—		(29)		—
Numerator for dilutive	$	(3,858)	$	77,860	$	(3,899)	$	87,404

Income (loss) from discontinued operations, net of tax	$	(61)	$	(21)	$	5,448	$	(416)
Income (loss) from discontinued operations attributable to unvested shares		—		—		(41)		4
Numerator for basic		(61)		(21)		5,407		(412)
Income from discontinued operations attributable to unvested shares		—		—		41		—
Numerator for dilutive	$	(61)	$	(21)	$	5,448	$	(412)

Net income (loss)	$	(3,919)	$	78,605	$	1,549	$	87,808
Net loss attributable to unvested shares		—		(766)		(12)		(816)
Numerator for basic		(3,919)		77,839		1,537		86,992
Net income attributable to unvested shares		—		—		12		—
Numerator for dilutive	$	(3,919)	$	77,839	$	1,549	$	86,992

Weighted average shares (denominator):
Basic weighted average shares outstanding		58,953		59,481		59,457		59,147
Effect of dilutive securities		—		1,337		—		699
Diluted weighted average shares outstanding		58,953		60,818		59,457		59,846
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		324		244		548		1,223

6. REVENUE

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

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

Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The intervals between liftings are generally 30 days; however, changes in the timing of liftings will impact the number of liftings 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) that

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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 to which the Company is entitled based on the its ownership interest in the property, and the Company would recognize a liability if its existing proved reserves were not adequate to cover an imbalance.

For each lifting completed under the COSPA, payment is made by the customer in U.S. Dollars by electronic transfer within thirty days after the date of the bill of lading. For each lifting of oil, the price is based on an average of Dated Brent in the month of lifting adjusted for location and market forces.

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 deems this situation to be characterized as a fixed price situation.

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

In the current and prior periods, royalties owed to the government of Gabon were settled through a monthly cash payment. In October 2019, the government of Gabon notified the Company that it was electing to take its royalties in-kind beginning in January 2020.

With respect to the government’s share of profit oil, the Etame 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 are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of profit oil in prior periods, the amount associated with the profit oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported as a current income tax expense. Payments of the income tax liability is reported in the period in which the government takes its profit oil in-kind, i.e. the period in which it lifts the crude oil. The only in-kind payment in the current year was $7.3 million and occurred with the April 2019 lifting. As of September 30, 2019 and December 31, 2018, the foreign taxes payable attributable to the government’s share of profit oil was $3.2 million and $3.3 million, respectively.

Certain amounts associated with the carried interest in the Etame PSC discussed above are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs 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 PSC.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenue from customer contracts:	(in thousands)
Sales under the COSPA	$	19,660	$	18,931	$	62,420	$	74,587
Gabonese government share of Profit Oil		—		—		—		2,193
Other items reported in revenue not associated with customer contracts:
Gabonese government share of Profit Oil taken in-kind		—		9,385		7,347		9,385
Carried interest recoupment		511		573		1,951		1,929
Royalties		(2,568)		(3,623)		(9,120)		(10,757)
Total revenue, net	$	17,603	$	25,266	$	62,598	$	77,337

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7. OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

Extension of Term of Etame PSC

On September 25, 2018, VAALCO together with the other joint owners in the Etame Marin block (the “Consortium”) received an implementing Presidential Decree from the government of Gabon authorizing an extension for additional years (“PSC Extension”) to the Consortium to operate in the Etame Marin block. 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 three exploitation areas in the Etame Marin block for a period of ten years from September 17, 2018, the effective date of the PSC Extension. Prior to the PSC Extension, the exploitation periods for the three exploitation areas in the Etame Marin block would have expired beginning in June 2021. The PSC Extension also grants the Consortium the right for two additional extension periods of five years each. The PSC Extension further allows the Consortium to explore the potential for resources within the Exclusive Exploitation Authorization area as defined in the PSC Extension.

In consideration for the PSC Extension, the Consortium agreed to a signing bonus of $65.0 million ($21.8 million, net to VAALCO) payable to the government of Gabon (the “Signing Bonus”). The Consortium paid $35.0 million ($11.8 million, net to VAALCO) in cash on September 26, 2018 and paid $25.0 million ($8.4 million, net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the Consortium as of the effective date. An additional $5.0 million is to be paid in cash by the Consortium following the end of the drilling activities described below. The Company has accrued its $1.7 million share of this remaining payment as of September 30, 2018. The amount paid through a reduction in VAT has been recorded at $4.2 million that 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 that reduced the Company’s net deferred tax assets. The Company has allocated its share of the Signing Bonus between proved and unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas resulting in $22.5 million being attributed to proved leasehold costs and $13.7 million attributed to unproved leasehold costs.

Under the PSC Extension, by September 16, 2020, the Consortium is required to drill two wells and two appraisal wellbores. If the wells are not drilled, then the Consortium must pay the difference between the amounts spent on any wells that were drilled and the estimated costs of the wells as set forth in the Work Program and Budget as approved by the government of Gabon. In September 2019, the 2019/2020 drilling campaign was begun with the spudding of the first of the two appraisal wellbores, the Etame 9P. In October 2019, drilling of the Etame 9P was completed and drilling of the first well, the Etame 9H, was begun. The Company plans to drill the second appraisal wellbore and the second well as part of the current 2019/2020 drilling campaign that is currently planned to be completed in the first half of 2020. The Company estimates the cost of these wells will be approximately $68.5 million ($23.0 million, net to VAALCO). The Company could drill a third development well in the 2019/2020 drilling campaign, subject to joint owner and government approval.

The Consortium is also required to complete two technical studies by September 16, 2020 at an estimated cost of $1.3 million gross ($0.4 million, net to VAALCO). These studies are currently underway.

Also previous 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 increased to 80% for the ten-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%.

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

Depletion and Impairment

The Company reviews oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When an oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the Company’s 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.

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

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

Undeveloped Leasehold Costs

The Company has a 31% working interest in an undeveloped portion of a block offshore Equatorial Guinea that the Company acquired in 2012 (the “Block P interest”). The Company is currently awaiting the Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”) to approve its appointment as operator for Block P. Compania Nacional de Petroleos de Guinea Equatorial (“GEPetrol”) is the state-owned oil company and one of the joint venture owners in Block P. For a number of years, the Block P interest was in suspension; however, in September 2018, the EG MMH lifted the suspension subject to several conditions. GEPetrol was required to introduce a new investor or joint venture owner to the EG MMH by March 28, 2019, and it has fulfilled this requirement. Upon EG MMH approving the new joint owner, the Contractor group has one year to drill an exploration well. The Company intends to seek a joint venture owner on a promoted basis that will cover all or substantially all of the cost to drill an exploratory well. If the joint venture owners fail to drill an exploration well, the Company would lose its interest in the license, and the associated costs would become impaired. As of September 30, 2019, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. The Company and the 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 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.

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

8. DERIVATIVES AND FAIR VALUE

The Company uses derivative financial instruments to achieve a more predictable cash flow from oil production by reducing the Company’s exposure to price fluctuations. See Note 1 for further information.

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. If a liability position for these swaps exceed $10.0 million, the Company would be required to provide a bank letter of credit or deposit cash into an escrow account for the amount by which the liability exceeds $10.0 million. At September 30, 2019, the Company’s unexpired commodity swaps as shown in the table below had a fair value asset position of $3.7 million reflected in “Prepayments and other” line of the Company’s condensed consolidated balance sheet. These swaps settle on a monthly basis.


				Swaps
Settlement Period	Type of Contract	Index	Barrels	Weighted Average Fixed Price
2019	Swaps	Dated Brent	119,865	$	66.70
2020	Swaps	Dated Brent	274,870		66.70
			394,735

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

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

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

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


		Three Months Ended September 30,				Nine Months Ended September 30,
Derivative Item	Statement of Operations Line	2019		2018		2019		2018
		(in thousands)
Crude oil swaps	Realized gain - contract settlements	$	493	$	39	$	2,056	$	28
	Unrealized gain (loss)		1,774		(1,065)		210		(2,064)
	Derivative instruments gain (loss), net	$	2,267	$	(1,026)	$	2,266	$	(2,036)

9. ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:


	September 30, 2019		December 31, 2018
	(in thousands)
Accrued accounts payable invoices	$	4,915	$	4,669
Joint venture audit settlement		4,399		—
Gabon domestic market social investment obligations		2,767		3,145
Capital expenditures		6,158		2,038
Stock appreciation rights		2,516		1,007
Accrued wages and other compensation		1,468		1,802
Other		1,663		1,477
Total accrued liabilities and other	$	23,886	$	14,138

10. DEBT

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

Interest

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
	(in thousands)
Interest expense related to debt, including commitment fees	$	—		$	—	$	—		$	(257)
Deferred finance cost amortization		—			—		—			(191)
Interest income		193			2		581			33
Other interest expense not related to debt		—			109		—			142
Interest income (expense), net	$	193		$	111	$	581		$	(273)

Average effective interest rate, excluding commitment fees		0.00%	⁽¹⁾		0.00%		0.00%	⁽¹⁾		7.09%

(1)There were no outstanding borrowings during 2019

11. COMMITMENTS AND CONTINGENCIES

Abandonment funding

As part of securing the first of two five-year extensions to the Etame PSC to which the Company is entitled from the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. The agreement was finalized in the first quarter of 2014 (effective as of 2011) providing for annual funding over a period of ten years in amounts equal to 12.14% of the total abandonment estimate for the first seven years and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable. The abandonment estimate used for this purpose is approximately $61.8 million ($19.2 million net to VAALCO) on an undiscounted basis. Through September 30, 2019, $35.7 million ($11.1 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on the Company’s condensed

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consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the Company’s asset retirement obligation and the amount of future abandonment funding payments.

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

FPSO charter

In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term, which expires in September 2022. At the Company’s election, the charter may be extended for two one-year periods beyond September 2020. 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 $0.2 million as of September 30, 2019 and December 31, 2018 representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO charter has $53.9 million in remaining gross minimum obligations as of December 31, 2018.

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


	Balance at December 31, 2018
(in thousands)	Full Charter Payment		VAALCO, Net
Year
2019	$	31,294	$	9,718
2020		22,634		7,029
2021		—		—
2022		—		—
2023		—		—
Total	$	53,928	$	16,747

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

Regulatory and Joint Interest Audits

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.

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

In July 2019, the Company reached an agreement in principle to resolve a legacy issue related to findings from Etame 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 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 income (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 balance of the amount due is expected to be paid during the first half of 2020.

Drilling Rig

The Company contracted a drilling rig to be used to drill two wells, including two appraisal wellbores, for the Etame Marin joint operations. The agreement includes options to drill four additional wells at the Etame Marin block. The drilling rig contract stipulates

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a day rate of approximately $75,000. The Company expects the term associated with the drilling rig commitment to be less than one year. In September 2019, the Company commenced its 2019/2020 drilling campaign and spud the Etame 9P appraisal wellbore.

For discussion of other contractual commitments, see Note 12 – Leases.

12. LEASES

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

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

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

The FPSO lease includes an option to extend the term through September 2022. The Company considered this option reasonably certain of exercise and has included it 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 three months ended September 30, 2019, the Company notified the lessor of its intent to extend the lease term by the first option that extends the FPSO lease to September 2021.

The FPSO and HWU agreements also contain 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 have excluded the purchase price from the calculation of ROU assets and lease liabilities.

The FPSO, HWU and helicopter 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. Because the Company does not know the extent to which the Company will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities.

The discount rate used to calculate ROU assets and lease liabilities represents 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.

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For the three and nine months ended September 30, 2019, the components of the lease costs and the supplemental information were as follows:


	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Lease cost:	(in thousands)
Operating lease cost	$	4,820	$	12,154
Short-term lease cost		166		570
Variable lease cost		1,652		4,390
Total lease expense		6,638		17,114
Lease costs capitalized		99		99
Total lease costs	$	6,737	$	17,213

Other information:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows to operating leases			$	13,364
Weighted-average remaining lease term				2.5 years
Weighted-average discount rate				6.16%

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


	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
	(in thousands)
Production expense	$	1,979	$	5,202
General and administrative expense		49		147
Lease costs billed to the joint venture owners		4,610		11,765
Total lease expense		6,638		17,114
Lease costs capitalized		99		99
Total lease costs	$	6,737	$	17,213

The following table describes the future maturities of the Company’s operating lease liabilities at September 30, 2019:


	Lease Obligation
Year	(in thousands)
2019	$	3,604
2020		14,066
2021		13,310
2022		9,304
2023		—
		40,284
Less: imputed interest		3,455
Total lease liabilities	$	36,829

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Under the joint operating agreements, other joint owners are obligated to fund $27.8 million of the $40.3 million in future lease liabilities.

Other lease obligations

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



(in thousands)	Gross Obligation		VAALCO, Net
Year
2019	$	1,110	$	627
2020		693		450
2021		—		—
2022		—		—
2023		—		—
Total	$	1,803	$	1,077

The Company incurred rent expense of $0.4 million and $1.3 million, respectively, during the three and nine months ended September 30, 2018.

13. ASSET RETIREMENT OBLIGATIONS

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


(in thousands)	Nine Months Ended September 30, 2019		Year Ended December 31, 2018
Beginning balance	$	14,816	$	20,163
Accretion		601		1,180
Additions		292		—
Revisions		—		(6,527)
Ending balance	$	15,709	$	14,816

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 PSC to conduct regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. In 2018, the Company recorded a downward revision of $6.5 million to the ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 7. The most recently completed abandonment study was in November 2018. In September 2019, the Company recorded $0.3 million in additions associated with the spudding of the Etame 9P appraisal wellbore at the Etame field in conjunction with commencement of its 2019/2020 drilling campaign.

14. SHAREHOLDERS’ EQUITY

Preferred stock – Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. No shares of preferred stock were issued and outstanding as of September 30, 2019 or December 31, 2018.

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 intends to 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 “Exchange Act”.

The Board of Directors also authorized the Company to enter into written trading plans under Rule 10b5-1 of the Exchange Act. Adopting a trading plan that satisfies the conditions of Rule 10b5-1 allows a company to repurchase its shares at times when it might otherwise be prevented from doing so due to self-imposed trading blackout periods or pursuant to insider trading laws. Under any Rule 10b5-1 trading plan, the Company’s third-party broker, subject to Securities and Exchange Commission regulations regarding certain price, market, volume and timing constraints, would have authority to purchase the Company’s common stock in accordance with the terms of the plan. The Company may from time to time enter into Rule 10b5-1 trading plans to facilitate the repurchase of its common stock pursuant to its share repurchase program.

From commencement of the plan in June 2019 through September 30, 2019, the Company had purchased 1,331,365 shares of common stock at an average price of $1.74 per share for an aggregate purchase price of $2.3 million under the plan. From October 1, 2019

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through the settlement date of November 5, 2019, the Company has purchased 275,354 shares of its common stock at an average price of $2.01 per share for an aggregate purchase price of $0.6 million.

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.

15. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS

The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Board of Directors to issue various types of incentive compensation. Currently, the Company has issued stock options and restricted shares under the 2014 Long-Term Incentive Plan (“2014 Plan”) and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. At September 30, 2019, 68,241 shares were authorized for future grants under the 2014 plan.

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

The Company records compensation expense related to stock-based compensation as general and administrative expense. For the three months ended September 30, 2019 and 2018, stock-based compensation was $1.2 million and $1.0 million, respectively, related to the issuance of stock options, restricted stock and stock appreciation rights. For the nine months ended September 30, 2019 and 2018, stock-based compensation was $2.8 million and $3.7 million, respectively, related to the issuance of stock options, restricted stock and stock appreciation rights. During the nine months ended September 30, 2019 and 2018, the Company settled in cash $0.3 million and $0.1 million, respectively, for stock appreciation rights exercises. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Stock-based compensation - equity awards	$	180	$	136	$	802	$	683
Stock-based compensation - liability awards		970		837		1,968		3,046
Total stock-based compensation	$	1,150	$	973	$	2,770	$	3,729

Stock options

Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors, which in the past has been a five-year life, with the options vesting over a service period of up to five years. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. There were $0.1 million and $0.5 million, respectively, in cash proceeds from the exercise of stock options in the nine months ended September 30, 2019 and 2018, respectively. On February 28, 2019, the Company granted stock options for 622,140 shares to employees; these options vest over a three-year period, vesting in three equal parts on the first, second and third anniversaries after the date of grant with an exercise price of $2.33 per share. On April 1, 2019, the Company granted stock options for 44,163 shares to an employee with an exercise price of $2.29 per share. On June 6, 2019, the Company granted stock options for 257,228 shares to directors with an exercise price of $1.43 per share; these options vested immediately.

During the nine months ended September 30, 2019, 13,875 shares were added to treasury as a result of tax withholding on options exercised. No shares were added to treasury as a result of tax withholding on options exercised during 2018. During the nine months ended September 30, 2019, 62,235 shares that had been granted from treasury were exercised and taken from treasury.

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 vesting period of the option. During the nine months ended September 30, 2019 and 2018, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants. 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 model.

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	Nine Months Ended September 30,
	2019			2018
Weighted average exercise price - ($/share)	$	2.08		$	1.05
Expected life in years		3.2			3.5
Average expected volatility		72.53	%		70.50	%
Risk-free interest rate		2.33	%		2.51	%
Weighted average grant date fair value - ($/share)	$	1.06		$	0.68

Stock option activity for the nine months ended September 30, 2019 is provided below:


	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
	(in thousands)			(in years)		(in thousands)
Outstanding at January 1, 2019	2,601	$	1.54
Granted	923		2.08
Exercised	(141)		0.94
Unvested shares forfeited	(306)		1.50
Vested shares expired	(124)		6.70
Outstanding at September 30, 2019	2,953		1.52	2.96	$	2,010
Exercisable at September 30, 2019	1,952		1.45	2.52	$	1,497

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three-year period, vesting in three equal parts on the anniversaries following the date of the grant. Share grants to directors vest immediately and are not restricted. On February 28, 2019, the Company issued 174,464 shares of service based restricted stock to employees with a grant date fair value of $2.33 per share. The vesting of these shares is dependent upon the employee’s continued service with the Company. The shares will vest in three equal parts over three years. On April 1, 2019, the Company issued 22,926 shares of service based restricted stock to an employee with a grant date fair value of $2.29 per share. The vesting of these shares is dependent upon the employee’s continued service with the Company. The shares will vest in three equal parts over three years. On June 6, 2019, the Company issued 111,888 shares of service based restricted stock to directors with a grant date fair value of $1.43 per share. These shares vested immediately.

The following is a summary of activity for the nine months ended September 30, 2019:


	Restricted Stock	Weighted Average Grant Price
	(in thousands)
Non-vested shares outstanding at January 1, 2019	507	$	0.91
Awards granted	309		2.00
Awards vested	(232)		1.14
Awards forfeited	(166)		1.29
Non-vested shares outstanding at September 30, 2019	418		1.44

During the three and nine months ended September 30, 2019, 30,573 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the three and nine months ended September 30, 2018, 8,117 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the nine months ended September 30, 2018, 35,265 shares were taken from treasury for vesting of restricted stock that had been granted outside of the 2014 Plan.

Stock appreciation rights (“SARs”)

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

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On February 28, 2019, 951,699 SARs were granted that vest over a three-year period with a life of 5 years and have a $2.33 SAR price per share specified in a SAR award on the date of grant. On May 10, 2019, 196,892 SARs were granted that vest over a three-year period with a life of 5 years and have a $1.72 SAR price per share specified in a SAR award on the date of grant.

SAR activity for the nine months ended September 30, 2019 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, 2019	3,369	$	0.96
Granted	1,148		2.23
Exercised	(270)		0.86
Unvested shares forfeited	(541)		1.41
Vested shares expired	—		—
Outstanding at September 30, 2019	3,706		1.29	3.39	$	2,971
Exercisable at September 30, 2019	1,240		1.04	2.75	$	1,231

Other Benefit Plans

On May 2 and June 6, 2019, the Company adopted forms of change in control agreement for its named executive officers and certain other officers of the Company and amended its severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control. 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 their 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.

16. INCOME TAXES

For 2019, the Company will determine 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 apply 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 United States income taxes. The Company’s operations in other foreign jurisdictions have a 0% effective tax rate because the Company has incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
U.S. Federal:	(in thousands)
Current	$	(135)	$	(406)	$	(300)	$	(406)
Deferred		3,042		(19,677)		4,808		(19,677)
Foreign:
Current		2,758		4,373		7,217		11,997
Deferred		2,016		(46,514)		7,917		(46,514)
Total	$	7,681	$	(62,224)	$	19,642	$	(54,600)

The Company’s effective tax rate for the three and nine months ended September 30, 2019 is 101%. For the three and nine months ended September 30, 2019, the Company’s 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. The effective tax rate was also impacted by a change in current year expectations in the valuation allowance. The deferred income tax expense for the three months ended September 30, 2019 included a $4.8 million charge to increase the valuation allowances on U.S. deferred tax assets due to a decrease in future estimated taxable earnings primarily as result of lower crude oil prices. Additionally, the joint venture owners’ audit settlement was treated as discrete during the nine months ended September 30, 2019. Further, a change in the valuation allowance relating to a change in expectations in future periods was treated as discrete to the quarter. An income tax benefit and expense, respectively, was provided at the U.S. tax rate of 21%.

For the three and nine months ended September 30, 2018, we determined that the potential for a recovery of our Cost Account maintained under the Etame Marine PCS was no longer remote, and therefore we recorded a deferred tax asset of $46.5 million related

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to the excess of the Cost Account over the book basis of the Etame Marin block assets. In addition, as a result of recording the deferred tax asset of $46.5 million related to our Cost Account, we recorded a corresponding deferred tax liability of $9.8 million attributable to the U.S. federal income tax impact. We also evaluated the amount of the valuation allowance needed related to deferred tax assets recognized related to U.S. federal income taxes. We determined that it is more likely than not that we will realize a portion of the benefit from the deferred tax assets related to the fixed asset basis differences as well as the net operating losses. Accordingly, we reversed $29.9 million of the valuation allowance recorded in prior periods.

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 September 30, 2019, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.
‎

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

our ability to discover, acquire, develop and replace oil and natural gas reserves;

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;

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 oil and natural gas;

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

the impact of competition;

weather conditions;

the uncertainty of estimates of 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 oil to commercial markets;

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;

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;

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 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, 2018 (“2018 Form 10-K”) and under the heading “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (“2019 First Quarter 10-Q”) and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 (together with the 2019 First Quarter 10-Q, the “2019 Quarterly Reports”), identifies

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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, the 2018 Form 10-K and our 2019 Quarterly Reports, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this report.

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

INTRODUCTION

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

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

CURRENT DEVELOPMENTS

In July 2019, the Etame-4H well, that was producing an average of 350 barrels per day gross (95 barrels net to VAALCO) in the second quarter, stopped producing. Separately in July, we performed an acid simulation job on the N. Tchibala-2H well. Subsequent to this work, the well would not flow naturally, and we were unable to restore production. During the second quarter of 2019, this well produced an average of 420 barrels per day gross (113 barrels net to VAALCO). VAALCO is currently undertaking a technical analysis of cost-effective remedial work with a view to re-establishing production from the N. Tchibala-2H well.

In early September 2019, the ESP failed in the Etame-10H well after operating for 4.5 years. Prior to the ESP failure, the well was producing approximately 735 BOPD gross (200 BOPD, net to VAALCO). VAALCO is planning to perform a workover to replace the ESP utilizing the Vantage drilling rig in the first half of 2020.

As previously announced, VAALCO contracted the Vantage Drilling International Topaz jackup drilling rig to execute the 2019/2020 drilling campaign. In September 2019, VAALCO commenced its 2019/2020 drilling campaign and spud the Etame 9P appraisal wellbore at the Etame field offshore Gabon. In October 2019, the Etame 9P, targeting the subcropping Dentale reservoir, was successfully drilled to a total depth of 10,260 feet and encountered both Gamba and Dentale oil sands. We did not encounter H₂S in either the Gamba or Dentale reservoirs. Operations are underway to drill the Etame 9H horizontal development well section in the Gamba reservior. Following the Etame 9H well, we plan to drill up to two more development wells and an additional appraisal wellbore.

Also in the third quarter, the Company and the Etame joint venture owners executed definitive agreements to resolve past audit findings for the periods from 2007 through 2016 for $4.4 million net to VAALCO. The Company previously accrued $4.4 million related to this item in the second quarter 2019 financial statements and no further adjustments are expected. In October 2019, the Company paid $1.1 million of the $4.4 million. The balance of the remaining amount due is expected to be paid during the first half of 2020.

On September 26, 2019, VAALCO began trading its common shares on the London Stock Exchange’s Main Market under the ticker EGY.

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ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of four companies. As of September 30, 2019, production operations in the Etame Marin block included nine platform wells, plus three subsea wells across all fields tied back by pipelines to deliver oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased FPSO anchored to the seabed on the block. We currently have nine producing wells. The FPSO has production limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day. In August 2019, VAALCO performed a planned maintenance turnaround for the FPSO Petroleo Nautipa, which included a nine-day full field shut down that impacted production for the three months ended September 30, 2019. During the three months ended September 30, 2019 and 2018, production from the block was approximately1,049 MBbls (284 MBbls net) and 1,406 MBbls (379 MBbls net), respectively. During the nine months ended September 30, 2019 and 2018, production from the block was approximately 3,448 MBbls (932 MBbls` net) and 3,804 MBbls (1,027 MBbls net), respectively.

Equatorial Guinea

VAALCO has a 31% working interest in an undeveloped portion of a block offshore Equatorial Guinea acquired in 2012 (the “Block P interest”). We are currently awaiting the Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”) to approve our appointment as operator for Block P. Compania Nacional de Petroleos de Guinea Equatorial (“GEPetrol”) is the state-owned oil company and one of the joint venture owners in Block P. For a number of years, the Block P interest was in suspension; however, in September 2018, the EG MMH lifted the suspension subject to several conditions. GEPetrol was required to introduce a new investor or joint venture owner to the EG MMH by March 28, 2019, and it has fulfilled this requirement. Upon EG MMH approving the new joint owner, the Contractor group has one year to drill an exploration well. VAALCO intends to seek a joint venture owner on a promoted basis that will cover all or substantially all of the cost to drill an exploratory well. If the joint venture owners fail to drill an exploration well, VAALCO would lose its interest in the license, and the associated costs would become impaired. As of September 30, 2019, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. VAALCO and its joint venture owners are evaluating the timing and budgeting for development and exploration activities under a development and production area in the block, including the approval of a development and production plan. The production sharing contract covering this development and production area provides for a development and production period of 25 years from the date of approval of a development and production plan.

Discontinued Operations - Angola

In November 2006, we signed a production sharing contract for the Block 5 PSA. Our working interest was 40%, and it carried Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P., that we were withdrawing from the Block 5 PSA. Further to our decision to withdraw from Angola, we closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the condensed consolidated financial statements for all periods presented. See Note 3 to the condensed consolidated financial statements.

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CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the nine months ended September 30, 2019 and 2018 are as follows:


	Nine Months Ended September 30,
	2019		2018		Increase (Decrease)
	(in thousands)
Net cash provided by operating activities before change in operating assets and liabilities	$	16,236	$	30,179	$	(13,943)
Net change in operating assets and liabilities		17,488		6,819		10,669
Net cash provided by continuing operating activities		33,724		36,998		(3,274)
Net cash used in discontinued operating activities		(4,673)		(958)		(3,715)
Net cash provided by operating activities		29,051		36,040		(6,989)

Net cash used in continuing investing activities		(3,382)		(13,205)		9,823
Net cash used in discontinued investing activities		—		—		—
Net cash used in investing activities		(3,382)		(13,205)		9,823

Net cash used in continuing financing activities		(2,292)		(8,655)		6,363
Net cash used in discontinued financing activities		—		—		—
Net cash used in financing activities		(2,292)		(8,655)		6,363
Net change in cash, cash equivalents and restricted cash	$	23,377	$	14,180	$	9,197

The decrease in net cash provided by our operating activities for the nine months ended September 30, 2019 compared to the same period of 2018 includes a $13.9 million decrease in cash generated by continuing operations before change in operating assets and liabilities, which was mainly due to lower revenue as referenced below in Results of Operations, and a decrease in our operating assets and liabilities of $10.7 million. The increase in cash resulting from the net change in operating assets and liabilities of $17.5 million for the nine months ended September 30, 2019 reflects decreases of $17.6 million in trade and other receivables and an increase of $4.1 million in “Accrued liabilities and other.” This was offset by a decrease in cash resulting from a $2.2 million decrease in accounts payable, a $0.1 million decrease in “Foreign taxes payable,” and a $2.0 million increase in “Prepayments and other”. The increase in cash resulting from the net change in operating assets and liabilities of $6.7 million for the nine months ended September 30, 2018 is the result of $8.0 million in payments made by joint venture owners, a $1.8 million increase in “Foreign taxes payable”, a $3.6 million decrease in “Trade receivables” and a $1.0 million decrease in “Crude oil inventory.” This was offset by decreases in cash resulting from payments made in “Accounts payable” of $4.3 million and a reduction in “Accrued liabilities and other” of $1.0 million.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. During the nine months ended September 30, 2019, these expenditures on a cash basis were $3.4 million, primarily related to equipment purchases and expenditures related to the commencement of the 2019/2020 drilling program. This compares to $13.2 million, primarily related to the $11.8 million signing bonus paid in connection with the PSC Extension and $1.4 million in property and equipment expenditures included in capital expenditures for the nine months ended September 30, 2018. See “Capital Expenditures” below for further discussion.

Net cash used in financing activities during the nine months ended September 30, 2019 included $2.4 million for treasury stock purchases primarily made under the Company’s stock repurchase plan. Net cash used in financing activities during the nine months ended September 30, 2018 included $9.2 million in principal payments on debt that was extinguished in May 2018.

Capital Expenditures

During the nine months ended September 30, 2019, we incurred accrual basis capital expenditures of $8.4 million. Pursuant to the PSC Extension as discussed in Note 7, we have commitments for capital expenditures related to the drilling of two wells and two appraisal wellbores by September 16, 2020. We estimate the cost of the two wells and two appraisal wellbores to be approximately $68.5 million ($23.0 million, net to VAALCO). We spudded one of the appraisal wellbores, Etame 9P, during September 2019 and anticipate drilling the remaining two wells and appraisal wellbore as well as a possible third well before completion of the 2019/2020 drilling campaign in the first half of 2020. The third well is subject to approval by the joint venture owners and the government of Gabon.

Contractual Obligations

See Note 11 to the condensed consolidated financial statements as well as our 2018 Form 10-K for discussion of our contractual obligations.

During the nine months ended September 30, 2019, we entered into contracts for a drilling rig and helicopter. There were no other material changes in our contractual obligations during the nine months ended September 30, 2019.

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Regulatory and Joint Interest Audits

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

In July 2019, we reached an agreement to resolve a legacy issue related to findings from Etame joint ventures owners’ audits for the periods from 2007 through 2016 for $4.4 million net to VAALCO. Accordingly, we have accrued $4.4 million that is reflected in the “Accrued liabilities and other” line of the Company’s condensed consolidated balance sheet and is recorded as a second quarter 2019 expense in the condensed consolidated results of operations in the line item “Other operating income (expense), net”. The final settlement agreements were executed by VAALCO and all of the joint venture owners effective September 9, 2019. In October 2019, the Company paid $1.1 million of the $4.4 million. The balance of the amount due is expected to be paid during the first half of 2020.

Capital Resources

Cash on Hand

At September 30, 2019, we had unrestricted cash of $57.2 million. The unrestricted cash balance includes $11.8 million of cash attributable to non-operating joint venture owner advances. As operator of the Etame Marin block in Gabon, we enter into project related activities on behalf of our working interest joint venture owners. We generally obtain advances from the joint venture owners prior to significant funding commitments.

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

Liquidity

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

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

OFF-BALANCE SHEET ARRANGEMENTS

None.

CRITICAL ACCOUNTING POLICIES

There have been no changes to our critical accounting policies subsequent to December 31, 2018 except for the adoption of a new leasing standard on January 1, 2019. See Notes 1 and 12 to the condensed consolidated financial statements.

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018

We reported net loss for the three months ended September 30, 2019 of $3.9 million compared to net income of $78.6 million for the same period of 2018. The net loss for the three months ended September 30, 2019 is inclusive of the loss from discontinued operations for the same period of $0.1 million as well as $5.1 million in deferred income tax expense that was primarily due to a change in the valuation allowance. The net income for the three months ended September 30, 2018 was inclusive of the loss from discontinued operations for the same period of $21 thousand as well as a $66.6 million deferred tax benefit related to the recognition of deferred tax

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assets and the reversal of valuation allowances on deferred tax assets. Substantially all of our operations are attributable to our Gabon segment. Further discussion of results by significant line item follows.

Oil and natural gas revenues decreased $7.7 million, or approximately 30.3%, during the three months ended September 30, 2019 compared to the same period of 2018. The decrease in revenue is attributable to lower prices and lower sales volumes as described below:

The revenue changes in the three months ended September 30, 2019 compared to the three months ended September 30, 2018, identified as related to changes in price or volume, are shown in the table below:


	Three Months Ended September 30,
	2019		2018
Gabon net oil production (MBbls)		283		379
International net oil sales (MBbls)		279		329

Average realized oil price ($/Bbl)	$	61.26	$	75.40
Average Dated Brent spot* ($/Bbl)		61.95		75.07
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Production expenses increased $2.4 million, or approximately 31.5%, in the three months ended September 30, 2019 compared to the same period of 2018. The increase was primarily a result of higher maintenance, fuel, transportation, customs, DMO, PID/PIH, and other production costs. In addition, 2018 reflected credits to workover expenses.

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

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

General and administrative expenses increased $1.9 million, or approximately 68.6% in the three months ended September 30, 2019 compared to the same period of 2018. The increase in expense was primarily related to higher personnel related costs, higher legal and professional fees and higher stock-based compensation expense during the three months ended September 30, 2019 compared to the same period in 2018.

Bad debt (recovery) expense for the three months ended September 30, 2019 reflected a small amount of bad debt expense whereas there were recoveries of $0.2 million during the three months ended September 30, 2018.

Other operating income (expense), net for the three months ended September 30, 2019 and 2018 is related to changes in inventory obsolescence.

Interest income (expense), net for the three months ended September 30, 2019 and 2018 relates to interest income on cash balances.

Derivative instruments gain (loss), net for the three months ended September 30, 2019 and 2018 is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements and the $2.3 million gain is a result of the decrease in the price of Dated Brent crude oil during the three months ended September 30, 2019 as compared to an increase in the price during the comparable prior period resulting in a $1.0 million loss.

Other, net for the three months ended September 30, 2019 and 2018 primarily consists of foreign currency losses as discussed in Note 1 to the condensed consolidated financial statements.

Income tax expense for the three months ended September 30, 2019 was $7.7 million. This is comprised of $5.1 million of deferred tax expense and a current tax provision of $2.6 million. The deferred income tax expense for the three months ended September 30, 2019 included a $4.8 million charge to increase the valuation allowances on U.S. deferred tax assets due to a decrease in future estimated taxable earnings primarily as a result of lower crude oil prices. The income tax benefit for the three months ended September 30,

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2018 includes a $66.6 million deferred tax benefit related to the recognition of deferred tax assets and the reversal of valuation allowances on deferred tax assets. In addition to the deferred tax benefit, we had a current tax provision of $4.0 million during the three months ended September 30, 2018. The current tax provision in both periods is primarily attributable to our operations in Gabon and is lower in 2019 than income tax for the comparable 2018 period as a result of lower revenues. See Note 16 to the condensed consolidated financial statements for further discussion.

Loss from discontinued operations for the three months ended September 30, 2019 and 2018 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The loss from discontinued operations for the three months ended September 30, 2019 and 2018 was related to Angola administration costs.

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

We reported net income for the nine months ended September 30, 2019 of $1.5 million compared to net income of $87.8 million for the same period of 2018. The net income for the nine months ended September 30, 2019 is inclusive of the income from discontinued operations for the same period of $5.4 million as well as $12.7 million in deferred income tax expense that was primarily due to change in valuation allowance. The net income for the nine months ended September 30, 2018 was inclusive of the loss from discontinued operations for the same period of $0.4 million as well as a $66.6 million deferred tax benefit related to the recognition of deferred tax assets and the reversal of valuation allowance on deferred tax assets. Substantially all of our operations are attributable to our Gabon segment. Further discussion of results by significant line item follows.

Oil and natural gas revenues decreased $14.7 million, or approximately 19.1%, during the nine months ended September 30, 2019 compared to the same period of 2018. The decrease in revenue is attributable to lower sales volumes as described below and to a lesser extent lower prices.

The revenue changes in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, identified as related to changes in price or volume, are shown in the table below:


	Nine Months Ended September 30,
	2019		2018
Gabon net oil production (MBbls)		932		1,027
International net oil sales (MBbls)		933		1,041

Average realized oil price ($/Bbl)	$	65.00	$	72.55
Average Dated Brent spot* ($/Bbl)		64.65		72.17
*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 ten liftings during each of the nine months ended September 30, 2019 and 2018. Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 23,000 and 99,400 barrels at September 30, 2019 and 2018, respectively. Production volumes for the nine months ended September 30, 2019 were lower than the comparable 2018 period in part due to the planned annual full-field shut down in August that took nine days to complete, the loss of production from three wells, the Etame 4H, N. Tchibala 2H and the Etame 10H and natural decline. Sales volumes were lower between the periods because sales volumes for the nine months ended September 30, 2018 included 95,525 barrels associated with the last lifting in 2017 that was not completed until January 1, 2018 as well as lower production volumes. Net revenues of $6.5 million associated with the January 1, 2018 lifting volumes were reported as revenue in the nine months ended September 30, 2018.

Production expenses decreased $3.4 million, or approximately 10.8%, in the nine months ended September 30, 2019 compared to the same period of 2018. The decrease in expense was primarily related to lower workovers ($4.2 million) offset by higher transportation, customs and fuel in 2019 compared to 2018.

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

General and administrative expenses increased $1.5 million, or approximately 14.2% in the nine months ended September 30, 2019 compared to the same period of 2018. The increase in expense was primarily related to higher personnel related costs, legal and other professional services, and travel and other costs during the three months ended September 30, 2019 compared to the same period in

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2018. The increase in expense was offset by a $1.1 million decrease 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 15 to our condensed consolidated financial statements for further discussion.

Bad debt (recovery) expense was higher between the nine months ended September 30, 2019 and 2018 primarily related to lower bad debt recoveries in the 2019 period.

Other operating income (expense), net for the nine months ended September 30, 2019 is related to a $4.4 million agreement to resolve a legacy issue related to findings from Etame joint ventures owners’ audits for the periods from 2007 through 2016. During the nine months ended September 30, 2018, we recorded a reduction in inventory obsolescence.

Interest income (expense), net for the nine months ended September 30, 2019 relates to interest income on cash balances whereas the September 30, 2018 period includes interest expense related to our term loan with the IFC as discussed in Note 10 to the condensed consolidated financial statements and to interest on taxes other than income taxes.

Derivative instruments gain (loss), net for the nine months ended September 30, 2019 is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements and the $2.3 million gain is a result of the decrease in the price of Dated Brent crude oil during the nine months ended September 30, 2019 as compared to an increase in the price of Dated Brent crude oil that resulted in a $2.0 million loss during the comparable prior year period.

Other, net for the nine months ended September 30, 2019 and 2018 primarily consists of foreign currency losses as discussed in Note 1 to the condensed consolidated financial statements.

Income tax expense for the nine months ended September 30, 2019 was $19.6 million. This is comprised of $12.7 million of deferred tax expense and a current tax provision of $6.9 million. The deferred income tax expense for the nine months ended September 30, 2019 included a $4.8 million charge to increase the valuation allowances on U.S. deferred tax assets due to a decrease in future estimated taxable earnings primarily as a result of lower crude oil prices. The income tax benefit for the nine months ended September 30, 2018 includes a $66.6 million deferred tax benefit related to the recognition of deferred tax assets and the reversal of valuation allowances on deferred tax assets. In addition to the deferred tax benefit, we had a current tax provision of $11.6 million during the nine months ended September 30, 2018. The current tax provision in both periods is primarily attributable to our operations in Gabon and is lower in 2019 than income tax for the comparable 2018 period as a result of lower revenues. See Note 16 to the condensed consolidated financial statements for further discussion.

Gain (loss) from discontinued operations for the nine months ended September 30, 2019 and 2018 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The gain from discontinued operations for the nine months ended September 30, 2019 is primarily related to recording a $5.7 million after tax gain on the finalized Angola settlement as discussed in Note 3 to the condensed consolidated financial statements. The loss from discontinued operations for the nine months ended September 30, 2018 was related to Angola administration costs.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

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

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of September 30, 2019, we had net monetary assets of $3.3 million (XAF 1,982.6 million) (net to VAALCO) denominated in XAF. A 10% weakening of the CFA relative to the U.S. dollar would have a $0.3 million reduction in the value of these net assets. For the three and nine months ended September 30, 2019, we had expenditures of approximately $3.1 million and $8.2 million (net to VAALCO), respectively, denominated in XAF.

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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 production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for oil and natural gas have been volatile and unpredictable in recent years, and this volatility may continue. Sustained low oil prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms. If oil sales were to remain constant at the most recent quarterly sales volumes of 279 MBbls, a $5 per Bbl decrease in oil price would be expected to cause a $1.4 million decrease per quarter ($5.6 million annualized) in revenues and operating income and a $0.3 million decrease per quarter ($1.3 million annualized) in net income.

During the three and nine months ended September 30, 2019, we had oil swaps outstanding. These instruments were intended to be an economic hedge against declines in crude oil prices; however, they were not designated as hedges for accounting purposes.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

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

DESCRIPTION OF MATERIAL WEAKNESS

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

Management’s plan for remediation of THE material weakness

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

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

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

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Except for the activities taken related to the remediation of the material weakness described above, there were no changes in our internal control over financial reporting that occurred during the three months ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

For a discussion of our potential risks and uncertainties, see the information in Item 1A “Risk Factors” in our 2018 Form 10-K and our 2019 Quarterly Reports. There have been no material changes in our risk factors from those described in our 2018 Form 10-K and our 2019 Quarterly Reports.

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

On June 20, 2019, our Board of Directors authorized and approved a share repurchase program for up to $10.0 million of the currently outstanding shares of our common stock over a period of 12 months. Under the stock repurchase program, we intend to 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 Exchange Act.

The following table represents details of the various repurchases during the quarter ended September 30, 2019:


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
July 1, 2019 - July 31, 2019	555,439		1.72	555,439	8,796,075
August 1, 2019 - August 31, 2019	469,018		1.75	469,018	7,973,937
September 1, 2019 - September 30, 2019	165,222		1.79	165,222	7,678,110
	1,189,679		1.74	1,189,679

See Note 14 to the condensed consolidated financial statements for further discussion. Subsequent to September 30, 2019 and through the settlement date of November 5, 2019, we purchased 275,354 shares at an average price of $2.01 for $0.6 million.

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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 Amended and Restated Bylaws of VAALCO Energy, Inc. dated as of December 31, 2015 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 23, 2015, 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)	XBRL Instance Document.
101.SCH(a)	XBRL Taxonomy Schema Document.
101.CAL(a)	XBRL Calculation Linkbase Document.
101.DEF(a)	XBRL Definition Linkbase Document.
101.LAB(a)	XBRL Label Linkbase Document.
101.PRE(a)	XBRL Presentation Linkbase Document.

(a) Filed herewith

(b) Furnished herewith

‎

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SIGNATURE

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

VAALCO ENERGY, INC.

(Registrant)


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

Dated: November 6, 2019