Report
of
Independent Registered Public Accounting Firm
Shareholders and Board of Directors
VAALCO Energy, Inc.
Houston, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations, shareholders’ equity (deficit), and cash flows for each of the three years ended in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of VAALCO Energy, Inc. and subsidiaries as of December 31, 2018 and 2017, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 8, 2019 expressed an adverse opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion
.
/s/BDO USA, LLP
We have served as the Company's auditor since 2016.
Houston, TX
March
8
, 2019
VA
ALCO ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2018
|
|
2017
|
ASSETS
|
|
(in thousands)
|
Current assets:
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
33,360
|
|
$
|
19,669
|
Restricted cash
|
|
|
804
|
|
|
842
|
Receivables:
|
|
|
|
|
|
|
Trade
|
|
|
11,907
|
|
|
3,556
|
Accounts with joint venture owners, net of allowance of $0.5 million for both years presented
|
|
|
949
|
|
|
3,395
|
Other
|
|
|
1,398
|
|
|
100
|
Crude oil inventory
|
|
|
785
|
|
|
3,263
|
Prepayments and other
|
|
|
6,301
|
|
|
2,791
|
Current assets - discontinued operations
|
|
|
3,290
|
|
|
2,836
|
Total current assets
|
|
|
58,794
|
|
|
36,452
|
Oil and natural gas properties and equipment - successful efforts method:
|
|
|
|
|
|
|
Wells, platforms and other production facilities
|
|
|
409,487
|
|
|
389,935
|
Work-in-progress
|
|
|
519
|
|
|
—
|
Undeveloped acreage
|
|
|
23,771
|
|
|
10,000
|
Equipment and other
|
|
|
9,552
|
|
|
9,432
|
|
|
|
443,329
|
|
|
409,367
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(390,605)
|
|
|
(386,146)
|
Net oil and natural gas properties, equipment and other
|
|
|
52,724
|
|
|
23,221
|
Other noncurrent assets:
|
|
|
|
|
|
|
Restricted cash
|
|
|
920
|
|
|
967
|
Value added tax and other receivables, net of allowance of $2.0 million and $6.5 million, respectively
|
|
|
2,226
|
|
|
6,925
|
Deferred tax assets
|
|
|
40,077
|
|
|
1,260
|
Abandonment funding
|
|
|
11,571
|
|
|
10,808
|
Total assets
|
|
$
|
166,312
|
|
$
|
79,633
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
8,083
|
|
$
|
11,584
|
Accounts with joint venture owners
|
|
|
304
|
|
|
—
|
Accrued liabilities and other
|
|
|
14,138
|
|
|
12,991
|
Foreign taxes payable
|
|
|
3,274
|
|
|
—
|
Current portion of long term debt
|
|
|
—
|
|
|
6,666
|
Current liabilities - discontinued operations
|
|
|
15,245
|
|
|
15,347
|
Total current liabilities
|
|
|
41,044
|
|
|
46,588
|
Asset retirement obligations
|
|
|
14,816
|
|
|
20,163
|
Other long term liabilities
|
|
|
625
|
|
|
284
|
Long term debt, excluding current portion, net
|
|
|
—
|
|
|
2,309
|
Total liabilities
|
|
|
56,485
|
|
|
69,344
|
Commitments and contingencies (Note 12)
|
|
|
|
|
|
|
Shareholders’ equity:
|
|
|
|
|
|
|
Preferred stock, none issued, 500,000 shares authorized, $25 par value
|
|
|
—
|
|
|
—
|
Common stock, $0.10 par value; 100,000,000 shares authorized, 67,167,994 and 66,443,971 shares issued, 59,595,742 and 58,862,876 shares outstanding, respectively
|
|
|
6,717
|
|
|
6,644
|
Additional paid-in capital
|
|
|
72,358
|
|
|
71,251
|
Less treasury stock, 7,572,251 and 7,581,095 shares, respectively, at cost
|
|
|
(37,827)
|
|
|
(37,953)
|
Retained earnings (deficit)
|
|
|
68,579
|
|
|
(29,653)
|
Total shareholders' equity
|
|
|
109,827
|
|
|
10,289
|
Total liabilities and shareholders' equity
|
|
$
|
166,312
|
|
$
|
79,633
|
See notes to consolidated financial statements.
V
A
ALCO ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
$
|
104,943
|
|
$
|
77,025
|
|
$
|
59,784
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Production expense
|
|
40,415
|
|
|
39,697
|
|
|
37,586
|
Exploration expense
|
|
14
|
|
|
7
|
|
|
5
|
Depreciation, depletion and amortization
|
|
5,596
|
|
|
6,457
|
|
|
6,926
|
Gain on revision of asset retirement obligations
|
|
(3,325)
|
|
|
—
|
|
|
—
|
General and administrative expense
|
|
11,398
|
|
|
10,377
|
|
|
9,561
|
Impairment of proved properties
|
|
—
|
|
|
—
|
|
|
88
|
Other operating expense
|
|
—
|
|
|
—
|
|
|
8,853
|
General and administrative related to shareholder matters
|
|
—
|
|
|
—
|
|
|
(332)
|
Bad debt (recovery) expense and other
|
|
(77)
|
|
|
452
|
|
|
1,222
|
Total operating costs and expenses
|
|
54,021
|
|
|
56,990
|
|
|
63,909
|
Other operating income (expense), net
|
|
365
|
|
|
(84)
|
|
|
(266)
|
Operating income (loss)
|
|
51,287
|
|
|
19,951
|
|
|
(4,391)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(145)
|
|
|
(1,414)
|
|
|
(2,613)
|
Other, net
|
|
4,332
|
|
|
2,113
|
|
|
(2,015)
|
Total other income (expense)
|
|
4,187
|
|
|
699
|
|
|
(4,628)
|
Income (loss) from continuing operations before income taxes
|
|
55,474
|
|
|
20,650
|
|
|
(9,019)
|
Income tax expense (benefit)
|
|
(43,254)
|
|
|
10,378
|
|
|
9,248
|
Income (loss) from continuing operations
|
|
98,728
|
|
|
10,272
|
|
|
(18,267)
|
Loss from discontinued operations
|
|
(496)
|
|
|
(621)
|
|
|
(8,283)
|
Net income (loss)
|
$
|
98,232
|
|
$
|
9,651
|
|
$
|
(26,550)
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per share:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
$
|
1.65
|
|
$
|
0.17
|
|
$
|
(0.31)
|
Loss from discontinued operations
|
|
(0.01)
|
|
|
(0.01)
|
|
|
(0.14)
|
Net income (loss) per share
|
$
|
1.64
|
|
$
|
0.16
|
|
$
|
(0.45)
|
Basic weighted average shares outstanding
|
|
59,248
|
|
|
58,717
|
|
|
58,384
|
Diluted net income (loss) per share:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
$
|
1.63
|
|
$
|
0.17
|
|
$
|
(0.31)
|
Loss from discontinued operations
|
|
(0.01)
|
|
|
(0.01)
|
|
|
(0.14)
|
Net income (loss) per share
|
$
|
1.62
|
|
$
|
0.16
|
|
$
|
(0.45)
|
Diluted weighted average shares outstanding
|
|
59,997
|
|
|
58,720
|
|
|
58,384
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
VA
ALCO ENERGY, INC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (DEFICIT)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Shares Issued
|
|
Treasury Shares
|
|
Common Stock
|
|
Additional Paid-In Capital
|
|
Treasury Stock
|
|
Retained Earnings (Deficit)
|
|
Total
|
Balance at January 1, 2016
|
|
65,621
|
|
(7,514)
|
|
$
|
6,562
|
|
$
|
70,150
|
|
$
|
(37,882)
|
|
$
|
(12,754)
|
|
$
|
26,076
|
Shares issued - stock-based compensation
|
|
489
|
|
—
|
|
|
49
|
|
|
(49)
|
|
|
—
|
|
|
—
|
|
|
—
|
Stock-based compensation expense
|
|
—
|
|
—
|
|
|
—
|
|
|
167
|
|
|
—
|
|
|
—
|
|
|
167
|
Treasury stock acquired
|
|
—
|
|
(41)
|
|
|
—
|
|
|
—
|
|
|
(51)
|
|
|
—
|
|
|
(51)
|
Net loss
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(26,550)
|
|
|
(26,550)
|
Balance at December 31, 2016
|
|
66,110
|
|
(7,555)
|
|
|
6,611
|
|
|
70,268
|
|
|
(37,933)
|
|
|
(39,304)
|
|
|
(358)
|
Shares issued - stock-based compensation
|
|
334
|
|
—
|
|
|
33
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
39
|
Stock-based compensation expense
|
|
—
|
|
—
|
|
|
—
|
|
|
977
|
|
|
—
|
|
|
—
|
|
|
977
|
Treasury stock acquired
|
|
—
|
|
(26)
|
|
|
—
|
|
|
—
|
|
|
(20)
|
|
|
—
|
|
|
(20)
|
Net income
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,651
|
|
|
9,651
|
Balance at December 31, 2017
|
|
66,444
|
|
(7,581)
|
|
|
6,644
|
|
|
71,251
|
|
|
(37,953)
|
|
|
(29,653)
|
|
|
10,289
|
Shares issued - stock-based compensation
|
|
724
|
|
35
|
|
|
73
|
|
|
287
|
|
|
177
|
|
|
—
|
|
|
537
|
Stock-based compensation expense
|
|
—
|
|
—
|
|
|
—
|
|
|
820
|
|
|
—
|
|
|
—
|
|
|
820
|
Treasury stock acquired
|
|
—
|
|
(26)
|
|
|
—
|
|
|
—
|
|
|
(51)
|
|
|
—
|
|
|
(51)
|
Net income
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
98,232
|
|
|
98,232
|
Balance at December 31, 2018
|
|
67,168
|
|
(7,572)
|
|
$
|
6,717
|
|
$
|
72,358
|
|
$
|
(37,827)
|
|
$
|
68,579
|
|
$
|
109,827
|
See notes to consolidated financial statements.
V
AALCO ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
98,232
|
|
$
|
9,651
|
|
$
|
(26,550)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in)
operating activities:
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations
|
|
|
496
|
|
|
621
|
|
|
8,283
|
Depreciation, depletion and amortization
|
|
|
5,596
|
|
|
6,457
|
|
|
6,926
|
Gain on revision of asset retirement obligations
|
|
|
(3,325)
|
|
|
—
|
|
|
—
|
Other amortization
|
|
|
417
|
|
|
369
|
|
|
1,424
|
Deferred taxes
|
|
|
(56,907)
|
|
|
(1,260)
|
|
|
—
|
Unrealized foreign exchange (gain) loss
|
|
|
834
|
|
|
(576)
|
|
|
(32)
|
Stock-based compensation
|
|
|
2,306
|
|
|
1,098
|
|
|
192
|
Commodity derivatives (gain) loss
|
|
|
(3,520)
|
|
|
1,032
|
|
|
1,711
|
Cash settlements (paid)/received on matured derivative contracts, net
|
|
|
(744)
|
|
|
195
|
|
|
—
|
Bad debt (recovery) expense
|
|
|
(77)
|
|
|
452
|
|
|
1,222
|
Other operating (income) loss, net
|
|
|
(570)
|
|
|
84
|
|
|
266
|
Operational expenses associated with equipment and other
|
|
|
1,604
|
|
|
1,189
|
|
|
—
|
Impairment of proved properties
|
|
|
—
|
|
|
—
|
|
|
88
|
Change in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
Trade receivables
|
|
|
(8,351)
|
|
|
3,195
|
|
|
(1,050)
|
Accounts with joint venture owners
|
|
|
2,747
|
|
|
(108)
|
|
|
16,284
|
Other receivables
|
|
|
(1,330)
|
|
|
(43)
|
|
|
(18)
|
Crude oil inventory
|
|
|
2,478
|
|
|
(2,350)
|
|
|
(192)
|
Prepayments and other
|
|
|
420
|
|
|
1,646
|
|
|
517
|
Value added tax and other receivables
|
|
|
(777)
|
|
|
(3,025)
|
|
|
(1,937)
|
Accounts payable
|
|
|
(3,409)
|
|
|
(7,297)
|
|
|
(15,459)
|
Foreign taxes payable
|
|
|
2,751
|
|
|
—
|
|
|
—
|
Accrued liabilities and other
|
|
|
(643)
|
|
|
2,050
|
|
|
(4,586)
|
Other long-term assets
|
|
|
—
|
|
|
—
|
|
|
546
|
Net cash provided by (used in) continuing operating activities
|
|
|
38,228
|
|
|
13,380
|
|
|
(12,365)
|
Net cash provided by (used in) discontinued operating activities
|
|
|
(1,052)
|
|
|
(4,423)
|
|
|
12,286
|
Net cash provided by (used in) operating activities
|
|
|
37,176
|
|
|
8,957
|
|
|
(79)
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
—
|
|
|
64
|
|
|
(5,692)
|
Property and equipment expenditures
|
|
|
(14,127)
|
|
|
(1,813)
|
|
|
(8,705)
|
Proceeds from the sale of oil and gas properties
|
|
|
—
|
|
|
250
|
|
|
830
|
Premiums paid for put options
|
|
|
—
|
|
|
—
|
|
|
(2,939)
|
Net cash used in continuing investing activities
|
|
|
(14,127)
|
|
|
(1,499)
|
|
|
(16,506)
|
Net cash used in discontinued investing activities
|
|
|
—
|
|
|
—
|
|
|
—
|
Net cash used in investing activities
|
|
|
(14,127)
|
|
|
(1,499)
|
|
|
(16,506)
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Proceeds from the issuances of common stock
|
|
|
544
|
|
|
39
|
|
|
—
|
Treasury shares
|
|
|
(58)
|
|
|
(20)
|
|
|
(51)
|
Debt issuance costs
|
|
|
—
|
|
|
—
|
|
|
(93)
|
Debt repayment
|
|
|
(9,166)
|
|
|
(10,001)
|
|
|
—
|
Borrowings
|
|
|
—
|
|
|
4,167
|
|
|
—
|
Net cash used in continuing financing activities
|
|
|
(8,680)
|
|
|
(5,815)
|
|
|
(144)
|
Net cash used in discontinued financing activities
|
|
|
—
|
|
|
—
|
|
|
—
|
Net cash used in financing activities
|
|
|
(8,680)
|
|
|
(5,815)
|
|
|
(144)
|
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH
|
|
|
14,369
|
|
|
1,643
|
|
|
(16,729)
|
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF YEAR
|
|
|
32,286
|
|
|
30,643
|
|
|
47,372
|
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF YEAR
|
|
$
|
46,655
|
|
$
|
32,286
|
|
$
|
30,643
|
See notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
257
|
|
$
|
997
|
|
$
|
1,326
|
Income taxes paid in cash
|
|
$
|
2,720
|
|
$
|
15,153
|
|
$
|
9,210
|
Income taxes paid in-kind with oil
|
|
$
|
9,385
|
|
$
|
—
|
|
$
|
—
|
Supplemental disclosure of non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
Property and equipment additions incurred but not paid at year end
|
|
$
|
2,138
|
|
$
|
455
|
|
$
|
2,282
|
Oil and natural gas property additions paid with non-cash assets
|
|
$
|
4,197
|
|
$
|
—
|
|
$
|
—
|
Gross-up of oil and natural gas properties by establishment of deferred tax liability
|
|
$
|
18,613
|
|
$
|
—
|
|
$
|
—
|
Asset retirement obligations
|
|
$
|
(6,527)
|
|
$
|
600
|
|
$
|
1,543
|
Restricted stock vestings issued out of treasury
|
|
$
|
(177)
|
|
$
|
—
|
|
$
|
—
|
See notes to consolidated financial statements.
V
AALCO ENERGY, INC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration activities in Gabon, West Africa. We have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 4 below, we have discontinued operations associated with our activities in Angola, West Africa.
Our consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., VAALCO International, Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited and VAALCO Energy (USA), Inc.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation
– The accompanying consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries.
Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.
All intercompany transactions within the consolidated group have been eliminated in consolidation.
Correction of error – Deferred tax liability related to oil and gas properties
–
Subsequent to the issuance of our condensed consolidated financial statements for the three months ended September 30, 2018, we identified an error
related to a gross up in oil and natural gas properties for the establishment of a deferred tax liability of $18.6 million as a result of differences between the book basis attributable to leasehold costs incurred in connection with the extension of the Etame Marin block production sharing contract with Gabon entered into on September 25, 2018 and the tax basis in these costs. To correct this error, we recorded an adjustment as of September 30, 2018 which resulted in an increase in capitalized oil and gas property costs of $18.6 million and a decrease in net deferred tax assets of $18.6 million. This correction only impacted long-term assets and had no impact on total assets or working capital in our consolidated balance sheet. This correction also had no impact on the unaudited condensed consolidated statements of operations or cash flows for the periods ended September 30, 2018
. See Note 16 for the restated condensed consolidated balance sheet.
Reclassifications
– Certain reclassifications have been made to prior period amounts to conform to the current period presentation related to the adoption of Accounting Standards Update (“
ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”)
. These reclassifications did not affect our consolidated financial results. See Note 3 – New Accounting Standards for further information associated with ASU 2016-18.
Use of estimates
– The preparation of the Financial Statements in conformity with generally accepted accounting principles in the United States (“U.S.”) (“GAAP”) requires estimates and assumptions that affect the reported amounts of assets and liabilities
and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods.
Our Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
Estimates of oil and natural gas reserves used to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available.
Cash and cash equivalents
–
Cash and cash equivalents includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
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 December 31, 2018 and 2017 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at December 31, 2018 and 2017 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 12. We invest restricted and excess cash in readily redeemable money market funds.
We are required under the Exploration and Production Sharing Contract entitled “Etame Marin No. G4-160,” dated as of July 7, 1995, as amended, (the “Etame PSC”) for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in November 2018.
This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments. See Note 12 for further discussion.
On
February 28, 2019, the
Gabonese branch of the international commercial b
ank holding the abandonment funds in a U
.
S
. dollar
denominated account advised that the bank regulator required transfer of the funds to
the
Central Bank for “CEMAC” (the Central African Economic and Monetary Community), of which Gabon is one of the six member states,
for conversion to local currency
with a
credit back to the
Gabonese branch
in local currency.
Amend
ment 5 to the PSC provides that in the event that the Gabonese bank fails for any reasons to reimburse all of the principal and interest due, the Contractor shall no longer be held liable for the obligation to remediate the sites.
Accounts with joint owners
– Accounts with joint owners represent the excess of charges billed over cash calls paid by the joint owners for exploration, development and production expenditures made by us as an operator.
Bad debts
– Quarterly, we evaluate our accounts receivable balances to confirm collectability. When collectability is in doubt, we record an allowance against the accounts receivable and a corresponding income charge for bad debts which appears in the “Bad debt expense and other” line item of the consolidated statements of operations. The majority of our accounts receivable balances are with our joint venture owners, purchasers of our production and the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed us.
Portions of our costs in Gabon (including our VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). As of December 31, 2018, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF
6.9
billion (XAF
2.3
billion, net to VAALCO). The VAT receivable balance was reduced by
XAF14.1
billion (XAF
4.7
billion, net to VAALCO or
$4.2
million) associated with a signing bonus as part of the Sixth Amendment to the Etame PSC
executed on September 17, 2018 (“PSC Extension”). As of December 31, 2018, the exchange rate was XAF
573.0
= $1.00.
In 2018, 2017 and 2016, we recorded recoveries (
allowances) of $
0.1
million, $
(0.4)
million and $
(0.7)
million
, respectively, related to VAT which the government of Gabon has not reimbursed. 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 consolidated balance sheets. Because both the VAT receivable and the related allowance 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 consolidated statements of operations.
The following table provides an analysis of the change in the allowance:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
Allowance for bad debt
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year
|
|
$
|
(7,033)
|
|
$
|
(5,211)
|
|
$
|
(4,221)
|
Bad debt recovery (charge)
|
|
|
77
|
|
|
(452)
|
|
|
(1,222)
|
Reclassification to leasehold costs related to signing bonus
|
|
|
4,197
|
|
|
—
|
|
|
—
|
Reclassification related to Sojitz acquisition
|
|
|
—
|
|
|
(694)
|
|
|
—
|
Foreign currency gain (loss)
|
|
|
224
|
|
|
(676)
|
|
|
232
|
Balance at end of period
|
|
$
|
(2,535)
|
|
$
|
(7,033)
|
|
$
|
(5,211)
|
|
|
|
|
|
|
|
|
|
|
Crude oil inventory
–
Crude oil inventories are carried at the lower of cost or market and represent our share of crude oil produced and stored on the FPSO, but unsold at the end of the period.
Materials and supplies
– Materials and supplies, which are included in the “Prepayments and other” line item of the consolidated balance sheet, are primarily used for production related activities. These assets are valued at the lower of cost, determined by the weighted-average method, or market.
Oil and natural gas properties, equipment and other
–
We use the successful efforts method of accounting for oil and natural gas producing activities. Our m
anagement believes that this method is preferable, as we have focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by drilling results.
Capitalizati
on
– Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Geological and geophysical costs are expensed as incurred. Costs of
seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
Depreciation, depletion and amortization
– Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a field basis under the unit-of-production method based upon estimates of proved reserves.
Support equipment (other than equipment inventory) and leasehold improvements related to oil and natural gas producing activities, as well as property, plant and equipment unrelated to oil and natural gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically
five
years for office and miscellaneous equipment and
five
to
seven
years for leasehold improvements.
Impairment
– We review our oil and natural gas producing properties for impairment
on a field-by-field basis
whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs which are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. We identified equipment inventory in Gabon
that required an adjustment of
$0.4
million to the “Other operating
income (expense)
, net” line item of the consolidated statement of
operations for the year
ended December 31, 2018.
We identified equipment inventory in Gabon that we do not expect to use and charged
$(0.3)
million to the “Other operating
income (expense)
, net” line item of the consolidated statement of operations in each of th
e years ended December 31,
2017 and 2016, respectively
.
When undeveloped oil and natural gas leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to undeveloped acreage in the Etame Marin block and in Equatorial Guinea.
Capitalized interest
– Interest costs and commitment fees from external borrowings are capitalized on exploration and development projects that are not subject to current depletion.
Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use.
Capitalized interest is added to the cost of the underlying asset and is depleted on the unit-of-production method in the same manner as the underlying assets
.
We capitalized
no
interest costs during the years ended December
31, 2018, 2017 and 2016.
Lease commitments
– We are lessees of office buildings, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expire at various times. All leases are characterized as operating leases and are expensed either as production expenses or general and administrative expenses. See Note 12 for further discussion.
Asset retirement obligations (“ARO”)
– We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and natural gas properties. We use current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to oil and natural gas properties.
To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate.
Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and natural gas production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. See Note 11 for disclosures regarding our asset retirement obligations. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. During the year ended December 31, 2018, we recorded a downward revision of $6.5 million to the
ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 9.
Revenue recognition
–
Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements.
There is a single performance obligation (delivering oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block 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%
(i
ncreasing 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.
Major maintenance activities
– Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and our labor costs.
Stock based compensation
–
We measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. Grant date fair value for options is estimated using the Black-Scholes option pricing model.
The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award
. For restricted stock, grant date fair value is determined using the market value of our common stock on the date of grant. The fair value of stock appreciation rights (“SARs”) is based on a Monte Carlo simulation at grant date and at each subsequent reporting date for the 2016 grants. The Monte Carlo simulation to value our SARs uses the following inputs: (i) the quoted market price of our common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term which is based on the contractual term, (iv) the expected volatility which is based on the historical volatility of the our stock for the length of time corresponding to the expected term of the SARs, (v) the expected dividend yield is based on our anticipated dividend payments, (vi) the risk-free interest rate which is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the SARs. We utilize the Black-Scholes option pricing model to measure the fair value of the 2017 and 2018 SARs.
Our stock-based compensation expense is recognized based on the awards as they vest, using the straight-line attribution method over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
When awards are forfeited before they vest, previously recognized expense related to such forfeitures is reversed in the period in which the forfeiture occurs.
Foreign currency transactions
–
The U.S. dollar is the functional currency of our foreign operating subsidiaries
. Gains and losses on foreign currency transactions are included in income. Within the consolidated statements of operations line item “Other income (expense)—Other, net,” we recognized losses on foreign currency transactions of $
0.1
million and
$30
thousand in 2018
and 2016, respectively, while we recognized gains on foreign currency transactions of $
0.5
million in 2017.
Income taxes
– Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year. We also operate in foreign jurisdictions where the tax laws relating to the oil and natural gas industry are open to interpretation which could potentially result in tax authorities asserting additional tax liabilities. While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.
Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered are earnings generated in previous periods, forecasted earnings and the expiration period of carryovers. As of December 31, 2018, the Company had deferred tax assets of $131.0 million primarily attributable to U.S. federal taxes related to basis differences in fixed assets, foreign tax credit carryforwards, and net operating loss carryforwards as well as foreign net operating losses for foreign jurisdictions for which a valuation allowance of $90.9 million had been recorded. During the year ended December 31, 2018, management determined that it was more-likely-than-not that a portion of the deferred tax assets related to basis differences in fixed assets and net operating loss carryforwards would be realized, and therefore
$
16.5
million of the valuation allowance recorded in prior periods was reversed.
In certain jurisdictions, we may deem the likelihood of realizing deferred tax assets as remote where we expect that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, we have not recognized deferred tax assets. Should our expectations change regarding the expected future tax consequences, we may
be required to record additional deferred taxes that could have a material effect on our consolidated financial position and results of operations. As of December 31, 2017, we had not recognized deferred tax assets related to our Cost Account in the Gabon jurisdiction. As discussed in Note 8 to the Financial Statements, as a result of the benefits under the PSC Extension which was granted in September 2018, we determined that it was now more-likely-than-not we would recover our Cost Account, and therefore we recorded a deferred tax
asset of
$
57.6
million primarily
related to the excess of the Cost Account over the book basis of the Etame Marin block assets.
Derivative instruments and hedging activities
– We use derivative financial instruments to achieve a more predictable cash flow from oil production by reducing our exposure to price fluctuations. Our derivative instruments at December 31, 2016 consisted of fixed price oil puts, which give us the option to sell a contracted volume of oil at a contracted price on a contracted date in the future.
All of our oil put contracts, which provided for settlement based upon reported the Brent price, had expired as of December 31, 2017. Our derivative instruments at December 31, 2018, consisted of oil swaps, which require us to pay a counterparty when the price of oil exceeds
$74.00
per barrel, and where the price of oil falls below
$74.00
, we receive a payment from the counterparty.
We record balances resulting from commodity risk management activities in the 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 “Other, net” line item located within the “Other income (expense)” section of the consolidated statements of operations. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Commodity derivatives (gain) loss” and “Cash settlements (paid)/received on matured derivative contracts, net” lines items located as adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities on the statements of consolidated cash flows. We paid net cash settlements of $
0.7
million during the year ended December 31, 2018 related to matured derivative contracts. We received cash settlements of
$0.2
million during the year ended December 31, 2017 related to matured derivative contracts.
Fair value
– Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in our internally developed present value of future cash flows model that underlies the fair-value measurement).
Fair value of financial instruments
– Our current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, liabilities for stock appreciation rights (“SARs”) and guarantee. As discussed further in Note 10, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivative asset commodity swaps referenced below are reported on the consolidated balance sheet on line item “
Prepayments and other.”
SARs liabilities are measure and reported at fair value using level 2 inputs each period with changes in fair value recognized in net income. The current portion of the SARs liabilities is reported on the consolidated balance sheet on line item “Accrued liabilities and other” while the long-term portion is located on the line item “Other long term liabilities”. With respect to our other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
(in thousands)
|
Recurring
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative asset commodity swaps
|
|
$
|
—
|
|
$
|
3,520
|
|
$
|
—
|
|
$
|
3,520
|
|
|
$
|
—
|
|
$
|
3,520
|
|
$
|
—
|
|
$
|
3,520
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
SARs liability
|
|
$
|
—
|
|
$
|
1,632
|
|
$
|
—
|
|
$
|
1,632
|
|
|
$
|
—
|
|
$
|
1,632
|
|
$
|
—
|
|
$
|
1,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
(in thousands)
|
Recurring
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
SARs liability
|
|
$
|
—
|
|
$
|
146
|
|
$
|
—
|
|
$
|
146
|
|
|
$
|
—
|
|
$
|
146
|
|
$
|
—
|
|
$
|
146
|
General and administrative related to shareholder matters
– Amounts related to shareholder matters for the year ended December 31, 2016 relates
to costs incurred related to shareholder litigation that was settled in 2016. For 2016, the amounts also include the offsetting insurance proceeds related to these matters.
Other, net
– “Other, net” in non-operating income and expenses includes gains and losses from derivatives and foreign currency transactions as discussed above. In addition, “Other, net” for the year ended December 31, 2017 includes
$2.6
million related to the reversal of accruals for liabilities we are no longer obligated to pay.
3
. NEW ACCOUNTING STANDARDS
Not Yet Adopted
In August 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in Accounting Standards Codification (“ASC”) 350, Intangibles - Goodwill and Other, in making the determination as to which implementation costs are to be capitalized as assets and which costs are to be expensed as incurred. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, and an entity can elect to apply the new guidance on a prospective or retrospective basis. The Company is currently evaluating the impact of adopting this guidance.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). This ASU modifies the disclosure requirements for fair value measurements. ASU 2018-13 removes the requirement to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements. ASU 2018-13 requires disclosure of changes in unrealized gains and losses for the period included in other comprehensive income (loss) for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For all entities, ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. We are currently evaluating the effect that this guidance will have on our consolidated financial statements and disclosures.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including our trade and joint venture owners receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date which is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model which increases the allowance when losses are probable. This change is effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We are currently evaluating the provisions of ASU 2016-13 and are assessing its potential impact on our
financial position, results of operations, cash flows and related disclosures
.
In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”), which amends the accounting standards for leases. This accounting standard w
as further clarified by ASU 2018-10,
Codification Improvements
to Topic 842
and ASU 2018-11, Leases:
Targeted Improvements, both of which were issued in July 2018 together (“Topic 842”). Topic 842 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Certain aspects of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early application permitted. In transition, lessees and lessors may use either a prospective approach in which they recognize and measure leases at the date of adoption and recognize a cumulative effect adjustment to the opening balance of retained earnings or they may use a modified retrospective approach in which leases are recognized and measured at the beginning of the earliest period presented. We intend to use the prospective approach when we adopt the new standard effective January 1, 2019. Leases with terms greater than 12 months, which are currently treated as operating leases, will be capitalized. The adoption of this standard will result in the recording of a right of use asset related to certain of our operating leases with a corresponding lease liability. This will result in a significant increase in total assets and liabilities and a decrease in working capital.
In connection with our implementation plan, we
have reviewed
our lease contracts and are evaluating other contracts to identify embedded leases to determine the appropriate accounting treatment. The most significant lease we currently have is related to the FPSO as further discussed in Note 12
, and we are finalizing the evaluation of that lease
.
L
ease payments reflected in the table in Note 12 represent the minimum amounts due. The new leasing standard requires capitalization based on the expected term of this lease which may
or
may not extend beyond the minimum period. While we may exercise our right to terminate the contract as early as September 2020, the minimum lease period,
the FPSO charter ends in September 2022.
Adopted
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Beginning January 1, 2018, we adopted ASU No. 2014-09, and the related additional guidance provided under ASU No. 2016-10, 2016-11 and 2016-12 (together with ASU 2014-09, “Revenue Recognition ASU”). This new standard replaced most existing revenue recognition guidance in U.S. GAAP. The core principle of the Revenue Recognition ASU requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. We adopted the Revenue Recognition ASU via the modified retrospective transition method, taking advantage of the allowed practical expedient that states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. This standard applies to revenues from contracts with customers. In addition, we recognize other items from carried interest recoupment and royalties paid which are reported in revenues but are not considered to be revenues from contracts with customers. For revenues from contracts with customers, adoption of this standard did not result in a change in the timing or amount of revenue recognized, and therefore the adoption of this standard did not have a material impact on our financial position, results of operations, debt covenants or business practices. The adoption did result in expanded disclosures related to the nature of our sales contracts and other matters related to revenues and the accounting for revenues, which are reflected in Note 7. In addition, we implemented new internal controls and procedures associated with revenue recognition and disclosures related to revenues.
In November 2016, the FASB issued ASU No. 2016-18, which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted ASU 2016-18 beginning January 1, 2018 with retroactive application to prior periods. Due to the nature of this accounting standards update, this had an impact on items reported in our consolidated statements of cash flows and related disclosures, but no impact on our financial position and results of operations.
The following tables provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the amounts shown in the consolidated statements of cash flows:
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2018
|
|
2017
|
|
|
(in thousands)
|
Cash and cash equivalents
|
|
$
|
33,360
|
|
$
|
19,669
|
Restricted cash - current
|
|
|
804
|
|
|
842
|
Restricted cash - non-current
|
|
|
920
|
|
|
967
|
Abandonment funding
|
|
|
11,571
|
|
|
10,808
|
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows
|
|
$
|
46,655
|
|
$
|
32,286
|
In May 2017, the FASB issued ASU No. 2017-09, Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting (“ASU 2017-09”) to clarify when to account for a change to the terms or conditions of a share-based payment award as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the
classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments in ASU 2017-09 are effective for all entities for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to an award modified on or after the adoption date. The adoption of ASU 2017-09 has not had a material impact on our
financial position, results of operations, cash flows and related disclosures
.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The purpose of the amendment is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, the amendments in ASU 2017-01 are effective for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to acquisitions and disposals completed on or after the effective date, with no disclosures required at transition. The adoption of ASU 2017-01 has not had a material impact on our
financial position, results of operations, cash flows and related disclosures
.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) related to how certain cash receipts and payments are presented and classified in the statement of cash flows. These cash flow issues include debt prepayment or extinguishment costs, settlement of zero-coupon debt, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of ASU 2016-15 has not had a material impact on our
financial position, results of operations, cash flows and related disclosures.
4. ACQUISITIONS AND DISPOSITIONS
Sojitz Acquisition
On November 22, 2016, we closed on the purchase of an additional 2.98% working interest (3.23% participating interest) in the Etame Marin block located offshore the Republic of Gabon from Sojitz Etame Limited (“Sojitz”), which represents all interest owned by Sojitz in the concession. The acquisition had an effective date of August 1, 2016 and was funded with cash on hand.
The actual impact of the Sojitz acquisition was an increase to “Total revenues” in the consolidated statement of operations of $0.2 million for the year ended December 31, 2016 and a minimal decrease to “Net loss” in the consolidated statement of operations for the year ended December 31, 2016.
Sale of Certain U.S. Properties
In December 2016, we completed the sale of our interests in two wells in the Hefley field in North Texas for $0.8 million resulting in a minimal loss.
In April 2017, we completed the sale of our interests in the East Poplar Dome field in Montana for
$0.3
million, resulting in a gain of approximately
$0.3
million reported on the line “Other operating income (expense), net” in our results of operations for the year ended December 31, 2017.
Discontinued Operations - Angola
In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). Our working interest is 40%, and we carry Sonangol P&P for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P., that we were withdrawing from the PSA. Further to the decision to withdraw from Angola, we have taken actions to close our office in Angola and reduce future activities in Angola. As a result of this strategic shift, we classified all the related assets and liabilities as those of discontinued operations in the consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in our consolidated statements of operations. We segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in our consolidated statements of cash flows. The following tables summarize selected financial information related to the Angola segment assets and liabilities as of December 31, 2018 and 2017 and its results of operations for the years ended December 31, 2018, 2017 and 2016.
Summarized Results of Discontinued Operations
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(in thousands)
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Exploration expense
|
$
|
—
|
|
$
|
—
|
|
$
|
15,137
|
Depreciation, depletion and amortization
|
|
—
|
|
|
—
|
|
|
9
|
General and administrative expense
|
|
467
|
|
|
615
|
|
|
1,269
|
Bad debt recovery and other
|
|
—
|
|
|
—
|
|
|
(7,629)
|
Total operating costs, expenses and (recovery)
|
|
467
|
|
|
615
|
|
|
8,786
|
Other operating loss, net
|
|
—
|
|
|
—
|
|
|
(172)
|
Operating loss
|
|
(467)
|
|
|
(615)
|
|
|
(8,958)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income
|
|
—
|
|
|
—
|
|
|
3,201
|
Other, net
|
|
(29)
|
|
|
(3)
|
|
|
552
|
Total other income (expense)
|
|
(29)
|
|
|
(3)
|
|
|
3,753
|
Loss from discontinued operations before income taxes
|
|
(496)
|
|
|
(618)
|
|
|
(5,205)
|
Income tax expense
|
|
—
|
|
|
3
|
|
|
3,078
|
Loss from discontinued operations
|
$
|
(496)
|
|
$
|
(621)
|
|
$
|
(8,283)
|
Assets and Liabilities Attributable to Discontinued Operations
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2018
|
|
2017
|
|
|
(in thousands)
|
ASSETS
|
|
|
|
|
|
|
Accounts with joint venture owners
|
|
$
|
3,290
|
|
$
|
2,836
|
Total current assets
|
|
|
3,290
|
|
|
2,836
|
Total assets
|
|
$
|
3,290
|
|
$
|
2,836
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
73
|
|
$
|
158
|
Accrued liabilities and other
|
|
|
15,172
|
|
|
15,189
|
Total current liabilities
|
|
|
15,245
|
|
|
15,347
|
Total liabilities
|
|
$
|
15,245
|
|
$
|
15,347
|
Drilling Obligation
Under the PSA, we
and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases identified in the PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of $10.0 million for each exploration well
for which a drilling obligation remains under the terms of the PSA, of which our participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of December 31, 2018 and 2017, respectively, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA.
Other Matters – Joint Owner Receivable
The government-assigned working interest joint owner was delinquent in paying their share of the costs several times in 2009 and was removed from the production sharing contract in 2010 by a governmental decree. Efforts to collect from the defaulted joint venture owner were abandoned in 2012. The available 40% working interest in Block 5, offshore Angola was assigned to Sonangol P&P effective on January 1, 2014. We invoiced Sonangol P&P for the unpaid delinquent amounts from the defaulted joint venture owner plus the amounts incurred during the period prior to assignment of the working interest totaling
$7.6
million plus interest in April 2014. Because this amount was not paid and Sonangol P&P was slow in paying monthly cash call invoices since their assignment, we placed Sonangol P&P in default in the first quarter of 2015.
On March 14, 2016, we received a $19.0 million payment from Sonangol P&P for the full amount owed us as of December 31, 2015, including the $7.6 million of pre-assignment costs and default interest of $3.2 million. The $7.6 million recovery is reflected in the “Bad debt expense and other” line item in our summarized results of discontinued operations. Default interest of $3.2 million is shown in the “Interest income” line item in our summarized results of discontinued operations.
5. SEGMENT INFORMATION
Our operations are based in Gabon and Equatorial Guinea.
Each of our
two
reportable operating segments is organized and managed based upon geographic location. Our Chief Executive Officer, who is the chief operating decision maker, and m
anagement review and evaluate the operation of each geographic segment separately primarily based on Operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production.
Corporate and other is primarily corporate and operations support costs which are not allocated to the reportable operating segments.
Segment activity of continuing operations for the years ended December 31, 2018, 2017 and 2016 and long-lived assets and segment assets at December 31, 2018 and 2017 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
104,938
|
|
$
|
—
|
|
$
|
5
|
|
$
|
104,943
|
Depreciation, depletion and amortization
|
|
|
5,176
|
|
|
—
|
|
|
420
|
|
|
5,596
|
Bad debt expense and other
|
|
|
(77)
|
|
|
—
|
|
|
—
|
|
|
(77)
|
Operating income (loss)
|
|
|
61,930
|
|
|
(470)
|
|
|
(10,173)
|
|
|
51,287
|
Other, net
|
|
|
92
|
|
|
(4)
|
|
|
4,244
|
|
|
4,332
|
Interest expense, net
|
|
|
(396)
|
|
|
—
|
|
|
251
|
|
|
(145)
|
Income tax benefit
|
|
|
(26,670)
|
|
|
—
|
|
|
(16,584)
|
|
|
(43,254)
|
Additions to oil and natural gas properties and equipment - accrual
|
|
|
38,430
|
|
|
187
|
|
|
17
|
|
|
38,634
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2017
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
76,978
|
|
$
|
—
|
|
$
|
47
|
|
$
|
77,025
|
Depreciation, depletion and amortization
|
|
|
6,196
|
|
|
—
|
|
|
261
|
|
|
6,457
|
Bad debt expense and other
|
|
|
452
|
|
|
—
|
|
|
—
|
|
|
452
|
Operating income (loss)
|
|
|
28,488
|
|
|
(122)
|
|
|
(8,415)
|
|
|
19,951
|
Other, net
|
|
|
3,142
|
|
|
15
|
|
|
(1,044)
|
|
|
2,113
|
Interest expense, net
|
|
|
(1,414)
|
|
|
—
|
|
|
—
|
|
|
(1,414)
|
Income tax expense (benefit)
|
|
|
11,638
|
|
|
—
|
|
|
(1,260)
|
|
|
10,378
|
Additions to oil and natural gas properties and equipment - accrual
|
|
|
1,576
|
|
|
—
|
|
|
126
|
|
|
1,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
59,460
|
|
$
|
—
|
|
$
|
324
|
|
$
|
59,784
|
Depreciation, depletion and amortization
|
|
|
6,531
|
|
|
—
|
|
|
395
|
|
|
6,926
|
Impairment of proved properties
|
|
|
—
|
|
|
—
|
|
|
88
|
|
|
88
|
Bad debt expense and other
|
|
|
1,222
|
|
|
—
|
|
|
—
|
|
|
1,222
|
Operating income (loss)
|
|
|
3,901
|
|
|
(384)
|
|
|
(7,908)
|
|
|
(4,391)
|
Other, net
|
|
|
(22)
|
|
|
(8)
|
|
|
(1,985)
|
|
|
(2,015)
|
Interest expense, net
|
|
|
(2,614)
|
|
|
—
|
|
|
1
|
|
|
(2,613)
|
Income tax expense
|
|
|
9,248
|
|
|
—
|
|
|
—
|
|
|
9,248
|
Additions to oil and natural gas properties and equipment - accrual
|
|
|
(4,242)
|
|
|
—
|
|
|
181
|
|
|
(4,061)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Long-lived assets from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
$
|
42,195
|
|
$
|
10,187
|
|
$
|
342
|
|
$
|
52,724
|
As of December 31, 2017
|
|
|
12,638
|
|
|
10,000
|
|
|
583
|
|
|
23,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Total assets from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
$
|
103,401
|
|
$
|
10,320
|
|
$
|
49,301
|
|
$
|
163,022
|
As of December 31, 2017
|
|
|
63,121
|
|
|
10,095
|
|
|
3,581
|
|
|
76,797
|
Information about our most significant customers
For the years ended December 31, 2018, 2017 and 2016, we sold our crude oil production from Gabon under a term contract with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The contracted purchaser was Glencore Energy UK Ltd. (“Glencore”) for these periods and through January 2019. Sales of oil to Glencore were approximately 100% of revenues sold to customers for 2018, 2017 and 2016. We have signed a new contract with Mercuria Energy Trading SA which covers sales from February 2019 through January 2020.
6. EARNINGS PER SHARE
Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, we assume that restricted stock is outstanding on the date of vesting, and we assume the issuance of shares from
the exercise of stock options using the treasury stock method.
A reconciliation of reported net income (loss) to net income (loss) used in calculating EPS as well as a reconciliation from basic to diluted shares follows
:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
(in thousands)
|
Net income (loss) - (numerator):
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
$
|
98,728
|
|
$
|
10,272
|
|
$
|
(18,267)
|
(Income) from continuing operations attributable to unvested shares
|
|
(1,231)
|
|
|
(62)
|
|
|
—
|
Numerator for basic
|
|
97,497
|
|
|
10,210
|
|
|
(18,267)
|
(Income) loss from continuing operations attributable to unvested shares
|
|
—
|
|
|
—
|
|
|
—
|
Numerator for dilutive
|
$
|
97,497
|
|
$
|
10,210
|
|
$
|
(18,267)
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations
|
$
|
(496)
|
|
$
|
(621)
|
|
$
|
(8,283)
|
Loss from discontinued operations attributable to unvested shares
|
|
6
|
|
|
4
|
|
|
—
|
Numerator for basic
|
|
(490)
|
|
|
(617)
|
|
|
(8,283)
|
Loss from discontinued operations attributable to unvested shares
|
|
—
|
|
|
—
|
|
|
—
|
Numerator for dilutive
|
$
|
(490)
|
|
$
|
(617)
|
|
$
|
(8,283)
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
98,232
|
|
$
|
9,651
|
|
$
|
(26,550)
|
Income attributable to unvested shares
|
|
(1,225)
|
|
|
(58)
|
|
|
—
|
Numerator for basic
|
|
97,007
|
|
|
9,593
|
|
|
(26,550)
|
Net (income) loss attributable to unvested shares
|
|
—
|
|
|
—
|
|
|
—
|
Numerator for dilutive
|
$
|
97,007
|
|
$
|
9,593
|
|
$
|
(26,550)
|
|
|
|
|
|
|
|
|
|
Weighted average shares (denominator):
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
59,248
|
|
|
58,717
|
|
|
58,384
|
Effect of dilutive securities
|
|
749
|
|
|
3
|
|
|
—
|
Diluted weighted average shares outstanding
|
|
59,997
|
|
|
58,720
|
|
|
58,384
|
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive
|
|
1,316
|
|
|
2,823
|
|
|
4,363
|
7. REVENUE
Substantially all of our revenues are attributable to our Gabon operations. Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPAs”). The COSPAs have been and will be renewed or replaced from time to time either with the current buyer or another buyer. Since August 2015, a COSPA has been in place with the same customer, initially for a
one
-year period, with amendments that extended the period through January 31, 2018. On February 1, 2018, a new COSPA was entered into with this same customer, which terminated January 31, 2019. A new COSPA with a different customer has been executed for the period from February 2019 through January 2020.
COSPAs with customers are renegotiated near the end of the contract term and may be entered into with a different customer or the same customer going forward. Except for internal costs (which are expensed as incurred), there are no upfront costs associated with obtaining a new COSPA.
Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take
one
to
two
days to complete. The intervals between liftings are generally
30
days; however, changes in the timing of liftings will impact the number of liftings which occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations.
W
e have utilized the practical expedient in ASC Topic 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
Previously, we followed the sales method of accounting to account for crude oil production imbalances. In conjunction with our adoption of ASC Topic 606 on January 1, 2018, we will continue to account for production imbalances as a reduction in reserves. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property, and we would recognize a liability if our existing proved reserves were not adequate to cover an imbalance.
For each lifting completed under a COSPA, payment is made by the customer in U.S. Dollars by electronic transfer
thirty
days after the date of the bill of lading. For each lifting of oil, the price is determined based on a formula using published Dated Brent prices as well as market differentials plus a fixed contract differential.
Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, we deem this situation to be characterized as a fixed price situation.
In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. 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 and a shared portion of “Profit Oil” determined based on daily production rates, as well as a gross carried working interest of
7.5%
(i
ncreasing to
10%
beginning June 20, 2026) for all costs
. For both royalties and Profit Oil, the Etame PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments.
To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment. Payments for royalties are reflected as a reduction in revenues from customers. Should the government elect to take the production attributable to its royalty in-kind, we would no longer have sales to customers associated with production assigned to royalties.
With respect to the government’s share of Profit Oil, the Etame PSC provides that corporate income tax is satisfied through the payment of Profit Oil. In the consolidated statements of operations, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. Prior to February 1, 2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February 1, 2018, these sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported in current income tax expense. Payments of the income tax expense will be reported in the period in which the government takes its Profit Oil in-kind, i.e. the period in which it lifts the crude oil. The in-kind payment related to the September lifting was $9.4 million. As of December 31, 2018, the foreign taxes payable attributable to this obligation is $
3.3
million.
Certain amounts associated with the carried interest in the Etame Marin block discussed above are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs which would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues.
The following table presents revenues from contracts with customers as well as revenues associated with the obligations under the
Etame PSC:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
Revenue from customer contracts:
|
|
|
|
|
|
|
|
|
|
Sales under the COSPA
|
|
$
|
104,891
|
|
$
|
74,693
|
|
$
|
59,475
|
Gabonese government share of Profit Oil
|
|
|
2,193
|
|
|
11,638
|
|
|
9,248
|
U.S. oil and natural gas revenue
|
|
|
5
|
|
|
47
|
|
|
324
|
Other items reported in revenue not associated with customer contracts:
|
|
|
|
|
|
|
|
|
|
Gabonese government share of Profit Oil taken in-kind
|
|
|
9,385
|
|
|
—
|
|
|
—
|
Carried interest recoupment
|
|
|
3,545
|
|
|
2,205
|
|
|
—
|
Royalties
|
|
|
(15,076)
|
|
|
(11,558)
|
|
|
(9,263)
|
Total revenue, net
|
|
$
|
104,943
|
|
$
|
77,025
|
|
$
|
59,784
|
8. INCOME TAXES
VAALCO and its domestic subsidiaries file a consolidated U.S. income tax return. Certain subsidiaries’ operations are also subject to foreign income taxes.
On December 22, 2017, the U. S. government enacted the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act includes significant changes to the U.S. income tax system including but not limited to: a federal corporate rate reduction from
35%
to 21%; limitations on the deductibility of interest expense and executive compensation; repeal of the Alternative Minimum Tax (“AMT”); full expensing provisions related to business assets; creation of new minimum taxes such as the base erosion anti-abuse tax (“BEAT”) and Global Intangible Low Taxed Income (“GILTI”) tax; and the transition of U.S. international taxation from a worldwide tax system to a modified territorial tax system, which will result in a one time U.S. tax liability on those earnings which have not previously been repatriated to the U.S. (the “Transition Tax”). The impacts of this legislation are outlined below:
|
·
|
|
Beginning January 1, 2018, the U.S. corporate income tax rate is
21%
. The Company recognized the impacts of this rate change on its deferred tax assets and liabilities in the period enacted, i.e. during the year ended December 31, 2017. As the Company has a full valuation allowance on its net deferred tax asset as of December 31, 2017, the deferred tax recognized due to the change in rate was offset with a change in the valuation allowance. Therefore, there was no overall impact to the Financial Statements in 2017 due to this change in rate.
|
|
·
|
|
The Tax Reform Act also repealed the corporate AMT for tax years beginning on or after January 1, 2018 and provided for existing alternative minimum tax credit carryovers to be refunded beginning in 2018. The Company has approximately
$1.4
million in refundable credits, and it expects that a substantial portion will be refunded between 2018 and 2021. As such, most of the valuation allowance in place at the end of 2017 related to these credits was released in 2017 and a deferred tax asset of $1.3 million was reflected as of December 31, 2017 related to the expected benefit in future years.
|
|
·
|
|
The Transition Tax on unrepatriated foreign earnings is a tax on previously untaxed accumulated and current earnings and profits ("E&P") of the Company's foreign subsidiaries. To determine the amount of the Transition Tax, the Company must determine, among other factors, the amount of post-1986 E&P of its foreign subsidiaries, as well as the amount of non-U.S. income taxes paid on such earnings. Based on the Company’s reasonable estimate of the Transition Tax, there is no provisional Transition Tax expense.
|
|
·
|
|
The Tax Reform Act created a new requirement that GILTI income earned by foreign subsidiaries must be included currently in the gross income of the U.S. shareholder. The Company did not have any amounts related to potential GILTI tax.
|
Other provisions in the legislation, such as interest deductibility and changes to executive compensation plans have not had a material implications to the Company’s Financial Statements.
Additionally, the Tax Reform Act may further limit the Company’s ability to utilize foreign tax credits in the future. The Tax Reform Act introduces a new credit limitation basket for foreign branch income. Income from foreign branches is now allocated to this specific tax credit limitation basket which cannot offset income in other baskets of foreign
income. Under the Tax Reform Act, foreign taxes imposed on the foreign branch profits will not offset U.S. non-branch related foreign source income. Additional
analysis will be
needed
under proposed IRS regulations
to determine how this will impact the Company and any future utilization of foreign tax credit carryforwards.
Income taxes attributable to continuing operations for the years ended December 31, 2018, 2017, and 2016 are attributable to foreign taxes payable in Gabon as well as income taxes in the U.S. The Company has not recorded any measurement period adjustments under ASU 2018-05 during the year ended December 31, 2018.
Provision for income taxes related to income (loss) from continuing operations consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
|
2016
|
U.S. Federal:
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
(674)
|
|
$
|
—
|
|
$
|
—
|
Deferred
|
|
|
(15,910)
|
|
|
(1,260)
|
|
|
—
|
Foreign:
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
14,327
|
|
|
11,638
|
|
|
9,248
|
Deferred
|
|
|
(40,997)
|
|
|
—
|
|
|
—
|
Total
|
|
$
|
(43,254)
|
|
$
|
10,378
|
|
$
|
9,248
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017, the Company had deferred tax assets of $154.5 million primarily attributable to U.S. federal taxes related to
basis differences in fixed assets, foreign tax credit carryforwards, and net operating loss carryforwards as well as foreign net operating losses for foreign jurisdictions. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. As of December 31, 2017, the Company was in a cumulative three year pre-tax loss position for both the U.S. and Gabon jurisdictions. As of December 31, 2017, we did not anticipate utilization of the foreign tax credits prior to expiration nor did we expect to generate sufficient taxable income to utilize other deferred tax assets. On the basis of this evaluation, valuation allowances of $153.2 million were recorded as of December 31, 2017. Valuation allowances reduce the deferred tax assets to the amount that is more likely than not to be realized.
Taxes paid in Gabon with respect to earnings from the Etame Marin block are determined under the provisions of the Etame PSC. In accordance with the Etame PSC, the Consortium maintains a “Cost Account” which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. For each calendar year, the Consortium is entitled to receive a percentage of the production (“Cost Recovery Percentage”) remaining after deducting royalties so long as there are amounts remaining in the Cost Account. Prior to the PSC Extension, the Cost Recovery Percentage was
70%
. As a result of the PSC Extension, the Cost Recovery Percentage has been increased to
80%
for the period from September 17, 2018 through September 16, 2028. See Note 9 for further discussion of the PSC Extension. After September 16, 2028, the Cost Recovery Percentage returns to
70%
. The difference between revenues, net of royalties, and the costs recovered for the period is “Profit Oil.” As payment of corporate income taxes, the Consortium pays the government an allocation of the remaining Profit Oil production from the contract area ranging from
50%
to
60%
. The percentage of Profit Oil paid to the government as tax is a function of production rates. When the Cost Account is less than the entitled recovery percentage (either 70% or 80%, depending on the period), Profit Oil as a percentage of revenues increases and Gabon taxes paid increase as a percentage of revenues. At December 31, 2017, there was
$97.6
million remaining in the portion of the Cost Account associated with our interest.
Prior to the PSC Extension, the Cost Recovery Percentage was 70%, and the exploitation periods ended beginning in June 2021. Future proved reserves did not extend beyond 2021. Opportunities for increasing reserves by drilling wells were limited, and while oil prices had improved since 2016, they were not at the levels needed to recover VAALCO’s Cost Account. As a result of these factors, the ability to recognize the benefit from the potential deferred tax asset related to the difference between VAALCO’s Cost Account and the book basis of the Etame Marin block assets was deemed to be remote, and the deferred tax asset was not recognized. As a result of the PSC Extension in September 2018, the Cost Recovery Percentage increased to 80% and the exploitation periods were extended to at least September 16, 2028, and if the two five-year option periods are elected the period would extend to September 16, 2038. In addition to the benefits under the PSC Extension, we expect higher future oil prices based on current Brent futures strip pricing over the next few years, and we expect future production from the planned drilling of
two
to
three
wells in 2019. Given these factors, we
determined that the potential for a recovery of our Cost Account was no longer remote, and therefore we recorded a deferred tax asset of $
57.6
million
. The PSC extension payment was not recoverable for Gabon tax purposes, which resulted in the recording of a deferred tax liability of $18.6 million with an offsetting gross-up to oil and natural gas properties. Additionally, a reduction of $16.1 million was recorded in relation to current year activity and other changes resulting in an ending Gabon net deferred tax asset of $22.9 million
.
We also evaluated the amount of the valuation allowance needed
on
deferred tax assets recognized related to U.S. federal income taxes. In making this evaluation, we considered the impact on future taxable income of increased earnings as a result of the PSC Extension
,
increases in oil prices during the year, including current oil prices as well as Brent futures strip pricing over the next few years and the future production from the planned drilling of two to three wells in 2019. We also considered the pattern of earnings over the past three years. On the basis of these factors, we determined that it is more likely than not that we will realize a portion of the benefit from the deferred tax assets related to the fixed asset basis differences as well as the net operating losses. Accordingly, we reversed $
16.5
million of the valuation allowance
based on estimated future earnings. The total change in the valuation allowance related to U.S. net deferred tax assets was a decrease of $37.8 million. As a result of the above mentioned Gabon deferred tax asset, we recorded the corresponding deferred tax liability of $8.6 million attributable to the U.S. federal income tax impact. The deferred tax asset was further reduced by $8.9 million for current year activity and $4.3 million for expiring foreign tax credits. The items above along with other items of $0.1 million resulted in a net deferred tax asset for U.S. federal income tax purposes of $17.2 million.
The primary differences between the financial statement and tax bases of assets and liabilities resulted in deferred tax assets associated with continuing operations at December 31,
2018
and
2017
are as follows:
|
|
|
|
|
|
|
|
|
As of December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
Deferred tax assets:
|
|
|
|
|
|
|
Basis difference in fixed assets
|
|
$
|
38,479
|
|
$
|
46,929
|
Foreign tax credit carryforward
|
|
|
43,760
|
|
|
48,071
|
Alternative minimum tax credit carryover
|
|
|
674
|
|
|
1,349
|
U.S. federal net operating losses
|
|
|
20,616
|
|
|
22,490
|
Foreign net operating losses
|
|
|
19,989
|
|
|
26,371
|
Asset retirement obligations
|
|
|
3,111
|
|
|
4,234
|
Basis difference in accrued liabilities
|
|
|
3,816
|
|
|
3,716
|
Basis difference in receivables
|
|
|
387
|
|
|
1,331
|
Other
|
|
|
180
|
|
|
(26)
|
Total deferred tax assets
|
|
|
131,012
|
|
|
154,465
|
Valuation allowance
|
|
|
(90,935)
|
|
|
(153,205)
|
Net deferred tax assets
|
|
$
|
40,077
|
|
$
|
1,260
|
|
|
|
|
|
|
|
Foreign tax credits will expire between the years 2019 and 2025. Foreign tax credits of $4.3 million expired during the year. The alternative minimum tax credits do not expire, and foreign net operating losses (“NOLs”) are not subject to expiry dates. The NOL for our United Kingdom subsidiary can be carried forward indefinitely, while the NOLs for our Gabon subsidiaries are included in the respective subsidiaries’ cost oil accounts, which will be offset against future taxable revenues. We plan to liquidate the United Kingdom subsidiary and the Gabon branch which carries the NOL’s, and therefore the realization of deferred tax assets for these entities is remote. Accordingly, the related deferred tax assets of $8.7 million and $15.9 million, respectively, were written off during the year with a corresponding offset to the valuation allowance. All of the Company’s U.S. federal NOLs were incurred prior to 2018 and will expire between 2035 and 2037. U.S. federal NOLs incurred after 2017 do not expire. The ability to utilize NOLs and other tax attributes could be subject to a limitation if the Company were to undergo an ownership change as defined in Section 382 of the Tax Code. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. We do not anticipate utilization of the foreign tax credits prior to expiration and have recorded a full valuation allowance on these deferred tax assets.
As a result of the 2017 tax legislation enacted in the U.S., we expect to realize the benefit from our AMT credit carryforwards. The valuation allowance recorded related to AMT credits in previous periods was reversed in 2017 with the exception for a reserve for the possible sequestration of the credits. The $1.3 million reversal was recorded as a deferred income tax benefit during the fourth quarter of 2017. As a result of further guidance by the Internal Revenue Service, the $0.1 million reserve for possible sequestration of the credits was reversed in 2018.
On the basis of the evaluations discussed above, valuation allowances of
$90.9
million,
$153.2
million and
$211.8
million have been recorded as of
December 31, 2018
,
2017
and
2016
, respectively. Valuation allowances reduce the deferred tax assets to the amount that is more likely than not to be realized.
The Company recognizes the financial statement benefit of a tax position only after determining that they are more likely than not to sustain the position following an audit. The Company believes that its income tax positions and deductions will be sustained on audit and therefore no reserves for uncertain tax positions have been established. Accordingly,
no
interest or penalties have been accrued as of December 31,
2018
and
2017
. The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense.
Income (loss) from continuing operations before income taxes is attributable as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
|
2016
|
U.S.
|
|
$
|
(5,672)
|
|
$
|
(9,453)
|
|
$
|
(9,893)
|
Foreign
|
|
|
61,146
|
|
|
30,103
|
|
|
874
|
|
|
$
|
55,474
|
|
$
|
20,650
|
|
$
|
(9,019)
|
The reconciliation of income tax expense (benefit) attributable to income (loss) from continuing operations to income tax on income (loss) from continuing operations at the U.S. statutory rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
|
2016
|
Tax provision computed at U.S. statutory rate
|
|
$
|
11,650
|
|
$
|
7,228
|
|
$
|
(3,156)
|
Foreign taxes not offset in U.S. by foreign tax credits
|
|
|
24,840
|
|
|
6,775
|
|
|
6,319
|
Impact of Tax Reform Act
|
|
|
—
|
|
|
52,449
|
|
|
—
|
Recognition of foreign deferred tax assets, net of U.S. impact
|
|
|
(45,751)
|
|
|
—
|
|
|
—
|
Unrealizable foreign deferred tax assets
|
|
|
24,176
|
|
|
|
|
|
|
Effect of change in foreign statutory rates
|
|
|
—
|
|
|
—
|
|
|
2,394
|
Permanent differences
|
|
|
(104)
|
|
|
309
|
|
|
4,505
|
Foreign tax credit expirations
|
|
|
4,311
|
|
|
2,394
|
|
|
—
|
Increase/(decrease) in valuation allowance
|
|
|
(62,270)
|
|
|
(58,777)
|
|
|
(802)
|
Other
|
|
|
(106)
|
|
|
—
|
|
|
(12)
|
Total income tax expense (benefit)
|
|
$
|
(43,254)
|
|
$
|
10,378
|
|
$
|
9,248
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
2018
,
2017
and
2016
, we were subject to foreign and U.S. federal taxes only, with no allocations made to state and local taxes. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
|
|
|
|
|
|
Jurisdiction
|
|
Years
|
U.S.
|
|
2009-2018
|
Gabon
|
|
2014-2018
|
9. OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT
Extension of Term of Etame Marin Block PSC
On September 25, 2018, VAALCO together with the other joint owners in the Etame Marin block (the “Consortium”) received an implementing Presidential Decree from the government of Gabon authorizing the PSC Extension. Our subsidiary, VAALCO Gabon S.A., has a
33.575%
participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.
The PSC Extension extends the term for each of the three exploitation areas in the Etame Marin block for a period of
ten
years with effect from September 17, 2018, the effective date of the PSC Extension. Prior to the PSC Extension, the exploitation periods for the
three
exploitation areas in the Etame Marin block would expire beginning in June 2021. The PSC Extension also grants the Consortium the right for
two
additional extension periods of
five
years each. The PSC Extension further allows the Consortium to explore the potential for resources within the area of each Exclusive Exploitation Authorization as defined in the PSC Extension.
In consideration for the PSC Extension, the Consortium agreed to a signing bonus of
$65.0
million (
$21.8
million, net to VAALCO) payable to the government of Gabon (the “signing bonus”). The Consortium paid
$35.0
million (
$11.8
million, net to VAALCO) in cash on September 26, 2018 and paid
$25.0
million (
$8.4
million, net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the Consortium as of the effective date. An additional
$5.0
million (
$1.7
million, net to VAALCO) is to be paid in cash by the Consortium following the end of the drilling activities described below. We have accrued our $1.7 million share of this remaining payment as of September 30, 2018. The amount paid through a reduction in VAT has
been recorded at $4.2 million which represents the book value of the receivable, net of the valuation allowance as of the effective date. In addition, we recorded an increase of $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis. A corresponding $18.6 million deferred tax liability was recorded which reduced our net deferred tax assets. We have allocated our share of the signing bonus between proved and unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas resulting in $22.5 million being attributed to
p
roved leasehold costs and $13.7 million attributed to unproved leasehold costs.
Under the PSC Extension, by September 16, 2020, th
e Consortium is required to drill two wells and two appraisal well bores. We estimate the cost of these wells will be approximately
$61.2
million (
$20.5
million, net to VAALCO). If
the wells are not drilled, then the Consortium must pay the difference between the amounts spent on any wells that were drilled and the estimated costs of the wells as set forth in the Work Program and Budget as approved by the government of Gabon. The Consortium is planning to drill these wells in the second half of 2019. The Consortium is also required to complete two technical studies by September 16, 2020 at an estimated cost of
$1.3
million gross (
$0.4
million, net to VAALCO).
Prior to the PSC Extension, the Consortium was entitled to take up to
70%
of production remaining after the
13%
royalty (“Cost Recovery Percentage”) to recover its costs so long as there are amounts remaining in the Cost Account. Under the PSC Extension, the Cost Recovery Percentage is increased to
80%
for the ten-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to
70%
.
Prior to the PSC Extension, the PSC provided for the government of Gabon to take a
7.5%
gross working interest carried by the Consortium. The government of Gabon transferred this interest to a third party. Pursuant to the PSC Extension, the government of Gabon will acquire from the Consortium an additional
2.5%
gross working interest carried by the Consortium effective June 20, 2026. VAALCO’s share of this interest to be transferred to the government of Gabon is
0.8%
.
Proved Properties
We review our oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When an oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in our impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.
During the year ended December 31, 2018, oil and natural gas property costs increased significantly as a result of amounts recorded in connection with the PSC Extension and yearend oil prices decreased over the prior year; however, reserves increased significantly over the prior year. We evaluated these and other factors and determined that no impairment was required for any of the Etame fields.
There was no triggering event in the year ended December 31, 2017 that would cause us to believe the value of oil and natural gas producing properties should be impaired
.
During
2016
, our negative price differential to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the Avouma field in the Etame Marine block offshore Gabon where reserves were impacted by temporary shut-ins on certain wells in the field. We evaluated the undiscounted future net cash flows for the Avouma field and determined that they were in excess of the field’s carrying value at December 31, 2016. As a result, no impairment was required for the Avouma field, or any of our other fields in Gabon, for
2016.
Undeveloped Leasehold Costs
We have a
31%
working interest in an undeveloped portion of Block P offshore Equatorial Guinea that we acquired in 2012 for which we have
$10.0
million capitalized in undeveloped acreage.
For a number of years, the Block P interest was in suspension; however, in September 2018, the Ministry of Mines and Hydrocarbons (“EG MMH”) lifted the suspension. We are awaiting the EG MMH to approve our appointment as technical operator for Block P.
Compania Nacional de Petroleos de Guinea Equatorial (“GEPetrol”) will act as the administrative operator
. Under the terms of lifting of the suspension, a new joint owner is expected to assume GEPetrol’s working interest obligations and be presented to the EG MMH by March 28, 2019. Once the joint owner is approved, we are required to drill one exploration well within one year. While there is no monetary penalty for failing to meet the terms of the lifting of the suspension, we would lose our interest in the license, and the associated capitalized unproved leasehold costs of $10.0 million as of December 31, 2018 would become impaired.
Our production sharing contract covering this development and production area provides for a development and production period of
25
years from the date of approval of a development and production plan.
As a result of the PSC Extension, the exploitation area was expanded to include previously undeveloped acreage. We allocated $6.7 million of our share of the signing
bonus and
$7
.
1
million of the $18.6 million resulting
from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame PSC.
Capitalized Equipment Inventory
Certain capitalized
equipment inventory related to the Etame Marin block was increased in value by
$0.4
million due to adjustments in obsolescence of some items.
10. DERIVATIVES AND FAIR VALUE
We use derivative financial instruments to achieve a more predictable cash flow from oil production by reducing our exposure to price fluctuations. See Note 2 for further information.
Commodity swaps
-
In June 2018, we entered into
commodity
swaps at a Dated Brent weighted average of
$74.00
per barrel for the period from and including June 2018 through June 2019 for a quantity of approximately
400,000
barrels. If a liability position exceeds
$10.0
million, we would be required to provide a bank letter of credit or deposit cash into an escrow account for the amount by which the liability exceeds $10.0 million. These swaps settle on a monthly basis. At December 31, 2018, our unexpired
commodity
swaps were for an underlying quantity of
172,000
barrels and had a fair value asset position of $
3.5
million reflected in “Prepayments and other” line of our consolidated balance sheet.
Put options
- During 2016, we executed crude oil put contracts as market conditions allowed in order to economically hedge anticipated 2016 and 2017 cash flows from crude oil producing activities. At December 31, 2017, our crude oil put contracts expired.
While these commodity swaps and crude oil puts are intended to be an economic hedge to mitigate the impact of a decline in oil prices, we have not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. We do not enter into derivative instruments for speculative or trading proposes.
The crude oil swaps and put contracts are measured at fair value using the Black’s option pricing model. Level 2 observable inputs used in the valuation model include market information as of the reporting date, such as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates. The determination of the swap and put contracts fair value includes the impact of the counterparty’s non-performance risk.
To mitigate counterparty risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.
The following table sets forth the gain (loss) on derivative instruments on our consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
Derivative Item
|
|
Statement of Operations Line
|
|
2018
|
|
2017
|
|
2016
|
|
|
|
|
(in thousands)
|
Crude oil swaps
|
|
Other, net
|
|
$
|
4,264
|
|
$
|
—
|
|
$
|
—
|
Crude oil puts
|
|
Other, net
|
|
|
—
|
|
|
(1,032)
|
|
|
(1,711)
|
11. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in our asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
Balance at January 1
|
|
$
|
20,163
|
|
$
|
18,612
|
|
$
|
16,166
|
Accretion
|
|
|
1,180
|
|
|
951
|
|
|
903
|
Acquisitions and dispositions
|
|
|
—
|
|
|
(103)
|
|
|
1,544
|
Revisions
|
|
|
(6,527)
|
|
|
703
|
|
|
(1)
|
Balance at December 31
|
|
$
|
14,816
|
|
$
|
20,163
|
|
$
|
18,612
|
Accretion is recorded in the line item “Depreciation, depletion and amortization” on our consolidated statements of operations.
We are 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, we recorded a downward revision of $6.5 million to the ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 9. The most recently completed abandonment study was in November 2018.
As discussed further in Note 2, on February 28, 2019,
t
he
Gabonese branch of the international commercial b
ank holding the abandonment funds in a U
.
S
. dollar
denominated account advised that the bank regulator required transfer of the funds to
the
Central Bank for CEMAC
for conversion to local currency
with a
credit back to the
Gabonese branch
in local currency.
12. COMMITMENTS AND CONTINGENCIES
FPSO charter
In connection with the charter of the FPSO (the “FPSO charter”), we, as operator of the Etame Marin block, guaranteed all of the lease payments under the FPSO charter through its contract term, which expires
in September 2022. At our election, the FPSO charter may be terminated as early as September 2020. We obtained guarantees from each of our joint owners for their respective shares of the payments. Our net share of the charter payment is
31.1%
, or approximately
$9.7
million per year. Although we believe the need for performance under the charter guarantee is remote, we recorded
a liability of
$0.3
million and
$0.5
million as of December 31, 2018 and 2017, respectively, representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO lease 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 which reflects the right of early termination are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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,
$12.8
million and
$11.2
million for the years ended December 31, 2018, 2017 and 2016, respectively.
Other lease obligations
In addition to the FPSO, we have operating lease obligations, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gross Obligation
|
|
VAALCO, Net
|
Year
|
|
|
|
|
|
|
2019
|
|
$
|
1,110
|
|
$
|
627
|
2020
|
|
|
693
|
|
|
450
|
2021
|
|
|
—
|
|
|
—
|
2022
|
|
|
—
|
|
|
—
|
2023
|
|
|
—
|
|
|
—
|
Total
|
|
$
|
1,803
|
|
$
|
1,077
|
We incurred rent expense of
$1.3
million,
$2.4
million and
$4.5
million under operating leases for the years ended December 31, 2018, 2017 and 2016
.
Drilling and other commitments
In connection with the PSC Extension, the Etame Marin block joint owners are required to drill
two
wells and
two
appraisal well bores by September 16, 2020. The estimated cost for these wells is
approximately
$61.2
million (
$20.5
million, net to VAALCO).
In addition to the drilling commitment, the Etame Marin block joint owners are required to pay
$
5.0
million (
$1.7
million, net to VAALCO) in cash to the government of Gabon following the end of the drilling activities for the two wells. As the payment is not contingent on the success of these wells and at least $5.0 million would be paid if no wells are drilled, we have accrued a liability for our net $1.7 million share as of December 31, 2018. The joint owners are also obligated to perform
two
technical studies estimated to cost
$1.3
million (
$0.4
million, net to VAALCO). The costs related to these studies will be recognized in future periods when the studies are performed.
Rig commitment
In 2014, we entered into a long-term contract for the Constellation II drilling rig that was under a long-term contract for the multi-well development drilling campaign offshore Gabon. The campaign included the drilling of development wells and workovers of existing wells in the Etame Marin block. We released the drilling rig in February 2016, prior to the original July 2016 contract termination date, and in June 2016, we reached an agreement with the drilling contractor for us to pay
$5.1
million, net to VAALCO’s interest for
unused rig days under the contract. The expense related to the termination was reported in the “Other operating expense” line item in our consolidated statement of operations for the year ended December 31, 2016.
Gabon domestic market obligation and other investment obligations
Under the terms of the Etame PSC, effective in April 2016, the Consortium is required to provide to the local government refinery a volume of crude at a
15%
discount to market price (the “Gabon DMO”). Prior to April 2016, the discount was
25%
. The volume required to be furnished is the amount of the Etame Marin block production divided by total Gabon production times the volume of oil refined by the refinery per year. In 2018, we paid $
1.1
million for our share of the 2017 obligation. In 2017, we paid $
1.2
million for our share of the 2016 obligation. In 2016, we paid
$1.7
million for our share of the 2015 obligation. We accrue an amount for the Gabon DMO based on management’s best estimate of the volume of crude required, because the refinery does not publish throughput figures. The amount accrued at December 31, 2018, for our share of the 2018 obligation was
$1.2
million. The amount accrued at December 31, 2017, for our share of the 2017 obligation was
$1.3
million. These costs are cost recoverable under the terms of the Etame PSC. Also, beginning in April 2016, the Consortium is required to pay an additional
1%
of revenues for provisions for diversified investments (“PID”) and for investments in hydrocarbons (“PIH”). The amount accrued at December 31, 2018, for our share of the 2018 obligation was $1.9 million. The amount accrued at December 31, 2017, for our share of the 2017 obligation was
$1.4
million.
75%
of PID and PIH costs are cost recoverable under the terms of the Etame PSC.
Abandonment funding
Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028. The amounts paid will be reimbursed through the Cost Account and are non-refundable. The abandonment estimate used for this purpose is approximately
$61.8
million (
$19.2
million, net to VAALCO) on an undiscounted basis. Through December 31, 2018,
$37.4
million (
$11.6
million, net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of our consolidated balance sheet. Future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.
Regulatory and Joint Interest Audits
We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements.
As of December 31, 2016, we had accrued
$1.0
million, net to VAALCO, in the “Accrued liabilities and other” line item of our consolidated balance sheet for certain payroll taxes in Gabon which were not paid pertaining to labor provided to us over a number of years by a third-party contractor. While the payroll taxes were for individuals who were not our employees, we could be deemed liable for these expenses as the end user of the services provided. These liabilities were substantially resolved at the accrued amount in January 2017.
In 2016, the government of Gabon conducted an audit of our operations in Gabon, covering the years 2013 through 2014. We received the findings from this audit and responded to the audit findings in January 2017.
Since providing our response, there have been changes in the Gabonese officials responsible for the audit. We are working with the currently appointed representatives to resolve the audit findings.
We do not anticipate that the ultimate outcome of this audit will have a material effect on our financial condition, results of operations or liquidity.
In 2017, the government of Gabon conducted a tax audit of our Gabon subsidiary covering the years 2013 through 2016, and in December 2017, we received a report on their findings. We have evaluated the results of this audit, and have made an accrual of
$0.5
million, net to VAALCO, for the estimated additional taxes along with penalties in the “Accrued liabilities and other” line item of our consolidated balance sheet.
At December 31, 2018, we had accrued
$1.3
million, net to VAALCO, in the “Accrued liabilities and other” line item of our consolidated balance sheet for potential fees which may result from a customs audit. This matter was fully resolved in January 2019 for
$1.3
million, net to VAALCO.
Employment agreements
Our Chief Executive Officer and Chief Financial Officer have employment agreements which provide for payments of annual salary, incentive compensation and certain other benefits if their employment is terminated without cause.
13. DEBT
On May 22, 2018, we terminated an amended term loan agreement
we had with the
International Finance Corporation (the “IFC”) (the “Amended Term Loan Agreement”)
by prepaying the outstanding principal and accrued interest.
We did not incur any termination or prepayment penalties as a result of the termination of the Amended Term Loan Agreement.
We entered into the Amended Term Loan Agreement o
n June 29, 2016 through the execution of a Supplemental Agreement with the IFC which, among other things, amended and restated our existing loan agreement to convert the
$20.0
million revolving portion of
the credit facility, to a term loan with
$15.0
million outstanding at that date. The Amended Term Loan Agreement was secured by the assets of our Gabon subsidiary, VAALCO Gabon S.A., and was guaranteed by VAALCO as the parent company. The Amended Term Loan Agreement provided for quarterly principal and interest payments on the amounts outstanding, with interest accruing at a rate of LIBOR plus
5.75%
.
The Amended Term Loan Agreement also provided for an additional
$5.0
million, which could be requested in a single draw, subject to the IFC’s approval, through March 15, 2017.
On March 14, 2017, we borrowed
$4.2
million under this provision of the Amended Term Loan Agreement. The additional borrowings were to be repaid in five quarterly principal installments commencing June 30, 2017, together with interest which will accrue at LIBOR plus
5.75%
.
Interest
Until June 29, 2016, under the terms of the original loan agreement with the IFC, we paid commitment fees on the undrawn portion of the total commitment. Commitment fees had been equal to
1.5%
of the unused balance of the senior tranche of
$50.0
million and
2.3%
of the unused balance of the subordinated tranche of
$15.0
million when a commitment was available for utilization. With the execution of the Amended Term Loan Agreement with the IFC in June 2016, beginning on June 29, 2016,
and continuing through March 14, 2017, commitment fees were equal to 2.3% of the undrawn term loan amount of $5.0 million. There are no further commitment fees owing after March 14, 2017.
The table below shows the components of the “Interest expense” line item of our consolidated statements of operations and the average effective interest rate, excluding commitment fees, on our borrowings:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(in thousands)
|
Interest expense related to debt, including commitment fees
|
$
|
(257)
|
|
$
|
(997)
|
|
$
|
(1,353)
|
Deferred finance cost amortization
|
|
(191)
|
|
|
(369)
|
|
|
(319)
|
Deferred finance cost write-off due to loan modification
|
|
—
|
|
|
—
|
|
|
(869)
|
Interest income
|
|
270
|
|
|
7
|
|
|
3
|
Other interest expense not related to debt
|
|
33
|
|
|
(55)
|
|
|
(75)
|
Interest expense, net
|
$
|
(145)
|
|
$
|
(1,414)
|
|
$
|
(2,613)
|
|
|
|
|
|
|
|
|
|
Average effective interest rate, excluding commitment fees
|
|
7.09%
|
|
|
6.72%
|
|
|
5.52%
|
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 December 31, 2018 or 2017.
Treasury stock
–
In the years ended December 31, 2018, 2017 and 2016, we withheld
26,421
,
26,000
and
40,926
shares, respectively,
in connection with cashless stock option exercises and restricted stock vestings to satisfy tax withholding obligations related to stock option exercises. In the year ended December 31, 2018, restricted stock vestings of 35,265 shares were issued from treasury.
15. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS
Our stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of our Board of Directors to issue various types of incentive compensation. Currently, we have issued stock options, restricted shares and SARs from the 2014 Long-Term Incentive Plan (“2014 Plan”).
At December 31, 2018,
1,112,527
shares were authorized for future grants under this plan.
For each stock option granted, the number of authorized shares under the 2014 Plan will be reduced on a
one
-for-one basis. For each restricted share granted, the number of shares authorized under the 2014 Plan will be reduced by twice the number of restricted shares.
We have no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.
We record non-cash compensation expense related to stock-based compensation as general and administrative expense.
For the years ended December 31, 2018, 2017 and 2016, non-cash compensation expense was $2.3 million, $1.1 million and $0.2 million, respectively,
related to the issuance of stock options, restricted stock and SARs. Because we do not pay significant U.S. federal income taxes,
no
amounts were recorded for tax benefits.
Stock options
Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of our Board of Directors, which in the past has been a five year life, with the options vesting over a service period of up to
five
years. In
addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee.
There were
$0.5
million and
$39
thousand in cash proceeds received from the exercise of stock options in 2018 and 2017, respectively.
For 2016, there were
no
cash proceeds received from the exercise of stock options. During 2018, options for
494,941
shares were granted to employees; these options vest over a
three
-year period, vesting in three equal parts on the first, second and third anniversaries after the date of grant and have an exercise price of
$0.86
per share. Options for
175,644
shares also were granted in 2018 to our non-employee directors, which were fully vested upon their grant and have an exercise price of
$1.60
per share.
We use the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the vesting period of the option. During 2018, 2017 and 2016, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants. Because we have not paid cash dividends and do not anticipate paying cash dividends on the common stock in the foreseeable future, no expected dividend yield was input to the Black-Scholes model.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
|
2016
|
Weighted average exercise price - ($/share)
|
$
|
1.05
|
|
$
|
0.99
|
|
$
|
1.14
|
|
Expected life in years
|
|
3.5
|
|
|
3.2
|
|
|
3.0
|
|
Average expected volatility
|
|
71
|
%
|
|
73
|
%
|
|
71
|
%
|
Risk-free interest rate
|
|
2.51
|
%
|
|
1.51
|
%
|
|
1.1
|
%
|
Weighted average grant date fair value - ($/share)
|
$
|
0.68
|
|
$
|
0.49
|
|
$
|
0.49
|
|
Stock option activity for the year ended December 31, 2018 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, 2018
|
|
2,597
|
|
$
|
1.77
|
|
|
|
|
|
|
Granted
|
|
671
|
|
|
1.05
|
|
|
|
|
|
|
Exercised
|
|
(528)
|
|
|
1.02
|
|
|
|
|
|
|
Forfeited/expired
|
|
(139)
|
|
|
5.60
|
|
|
|
|
|
|
Outstanding at December 31, 2018
|
|
2,601
|
|
|
1.54
|
|
|
2.26
|
|
$
|
989
|
Exercisable at December 31, 2018
|
|
1,649
|
|
|
1.90
|
|
|
2.69
|
|
$
|
499
|
The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of stock options exercised in 2018 and 2017 was
$0.6
million and $
0.0
million, respectively. There were
no
exercises of stock options in 2016.
On February 28, 2019, the Company granted stock options for
622,1
40
shares to employees with an exercise price of
$2.33
per share.
As of December 31, 2018, unrecognized compensation cost related to outstanding stock options was
$0.2
million, which is expected to be recognized over a weighted average period of
1.1
years.
Restricted shares
Restricted stock granted to employees will vest over a period determined by the Compensation Committee which is generally a
three
-
year period, vesting in three equal parts on the first three anniversaries following the date of the grant. Share grants to directors vest immediately and are not restricted. The following is a summary of activity in unvested restricted stock in 2018.
|
|
|
|
|
|
|
|
Restricted Stock
|
|
Weighted Average Grant Price
|
|
|
(in thousands)
|
|
|
|
Non-vested shares outstanding at January 1, 2018
|
|
340
|
|
$
|
1.10
|
Awards granted
|
|
398
|
|
|
1.00
|
Awards vested
|
|
(231)
|
|
|
1.34
|
Awards forfeited
|
|
—
|
|
|
—
|
Non-vested shares outstanding at December 31, 2018
|
|
507
|
|
|
0.91
|
The total vest-date fair value of restricted stock awards which vested during 2018, 2017 and 2016 was $0.4 million,
$0.3
million and
$0.6
million, respectively. The weighted average grant date fair value per share of restricted stock awards was $1.71,
$0.98
and
$1.11
for the years ended December 31, 2018, 2017 and 2016, respectively.
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.
As of December 31, 2018, unrecognized compensation cost related to restricted stock totaled
$0.2
million and is expected to be recognized over a weighted average period of
1.2
years.
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 (which may not be less than the fair market value of our common stock on the date of grant) and the fair market value per share on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of our Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of our Board of Directors.
The
815,355
SARs granted in 2016 vest over a
three
-year period with a life of
5
years and have a maximum spread of
300%
of the
$1.04
SAR price per share specified in a SAR award on the date of grant. On February 28, 2018,
2,373,411
SARs were granted which vest over a
three
-year period with a life of
5
years and have a
$0.86
SAR price per share specified in a SAR award on the date of grant. On February 28, 2019,
951,699
SARs were granted which 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.
For the year ended December 31, 2017,
1,049,528
SARs were granted, all having an exercise price of
$1.20
per share. One-third of the SARs are to vest on or after the first anniversary of the grant date at such time when the market price per share of our common stock exceeds
$1.30
; one-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds
$1.50
; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds
$1.75
. SARs granted in 2017 vest over a
three
year period with a life of
5
years.
Total compensation expense related to our SARs awards during the year ended December 31, 2018 was $
1.6
million.
SAR activity for the year ended December 31, 2018 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, 2018
|
|
1,076
|
|
$
|
1.17
|
|
|
|
|
|
Granted
|
|
2,373
|
|
|
0.86
|
|
|
|
|
|
Exercised
|
|
(47)
|
|
|
1.20
|
|
|
|
|
|
Forfeited/expired
|
|
(33)
|
|
|
0.86
|
|
|
|
|
|
Outstanding at December 31, 2018
|
|
3,369
|
|
|
0.95
|
|
3.93
|
|
$
|
1,896
|
Exercisable at December 31, 2018
|
|
371
|
|
|
1.15
|
|
2.99
|
|
$
|
167
|
Other benefit plans
We sponsor a 401(k) plan, with a company match feature, for our employees. Costs incurred in the years ended December 31, 2018, 2017 and 2016 for the Company’s matching contribution and for administering the plan were approximately
$0.3
million
,
$0.2
million and
$0.3
million, respectively.
16. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Our unaudited quarterly results for years ended December 31, 2018 and 2017 were prepared in accordance with GAAP, and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. These adjustments are of a normal recurring nature. Quarterly income per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
(in thousands of dollars except per share information)
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
27,645
|
|
$
|
24,426
|
|
$
|
25,266
|
|
$
|
27,606
|
Total operating costs and expenses
|
|
|
14,631
|
|
|
19,017
|
|
|
7,940
|
|
|
12,433
|
Operating income
|
|
|
13,038
|
|
|
5,723
|
|
|
17,320
|
|
|
15,206
|
Income from continuing operations
|
|
|
8,711
|
|
|
887
|
|
|
78,626
|
|
|
10,504
|
Loss from discontinued operations
|
|
|
(52)
|
|
|
(343)
|
|
|
(21)
|
|
|
(80)
|
Net income
|
|
|
8,659
|
|
|
544
|
|
|
78,605
|
|
|
10,424
|
Basic net income per share
|
|
$
|
0.15
|
|
$
|
0.02
|
|
$
|
1.31
|
|
$
|
0.17
|
Diluted net income per share
|
|
$
|
0.15
|
|
$
|
0.02
|
|
$
|
1.28
|
|
$
|
0.17
|
Basic income from continuing operations per share
|
|
$
|
0.15
|
|
$
|
0.02
|
|
$
|
1.31
|
|
$
|
0.17
|
Diluted income from continuing operations per share
|
|
$
|
0.15
|
|
$
|
0.02
|
|
$
|
1.28
|
|
$
|
0.17
|
As discussed further in Note 8, deferred income tax expense (benefit) for the three months ended
September 30 and December 31, 2018 included $(66.6) million and $9.0 million, respectively, related to the recognition of deferred tax assets as well as adjustments to valuation allowances.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
(in thousands of dollars except per share information)
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
21,266
|
|
$
|
20,425
|
|
$
|
18,178
|
|
$
|
17,156
|
Total operating costs and expenses
|
|
|
13,055
|
|
|
15,068
|
|
|
14,454
|
|
|
14,413
|
Operating income
|
|
|
8,148
|
|
|
5,587
|
|
|
3,721
|
|
|
2,495
|
Income (loss) from continuing operations
|
|
|
4,435
|
|
|
2,451
|
|
|
(148)
|
|
|
3,534
|
Loss from discontinued operations
|
|
|
(176)
|
|
|
(168)
|
|
|
(174)
|
|
|
(103)
|
Net income (loss)
|
|
|
4,259
|
|
|
2,283
|
|
|
(322)
|
|
|
3,431
|
Basic net income (loss) per share
|
|
$
|
0.07
|
|
$
|
0.04
|
|
$
|
0.00
|
|
$
|
0.06
|
Diluted net income (loss) per share
|
|
$
|
0.07
|
|
$
|
0.04
|
|
$
|
0.00
|
|
$
|
0.06
|
Basic income (loss) from continuing operations per share
|
|
$
|
0.07
|
|
$
|
0.04
|
|
$
|
0.00
|
|
$
|
0.06
|
Diluted income (loss) from continuing operations per share
|
|
$
|
0.07
|
|
$
|
0.04
|
|
$
|
0.00
|
|
$
|
0.06
|
As discussed in Note 2, s
ubsequent to the issuance of our condensed consolidated fi
nancial statements for the three
months ended September 30, 2018, we identified an
error related to a gross up in oil and natural gas properties for the establishment of a deferred tax liability of $18.6 million as a result of differences between the book basis attributable to leasehold costs incurred in connection with the extension of the Etame Marin block production sharing contract with Gabon entered into on September 25, 2018 and the tax basis in these costs
.
The condensed consolidated balance sheet below reflects the impact of this error as of September 30, 2018.
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2018
|
|
|
As Previously Reported
|
|
Adjustments
|
|
As Restated
|
ASSETS
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
33,715
|
|
$
|
—
|
|
$
|
33,715
|
Restricted cash
|
|
|
1,025
|
|
|
—
|
|
|
1,025
|
Receivables:
|
|
|
|
|
|
|
|
|
|
Trade
|
|
|
—
|
|
|
—
|
|
|
—
|
Accounts with joint venture owners, net of allowance of $0.5 million
|
|
|
931
|
|
|
—
|
|
|
931
|
Other
|
|
|
408
|
|
|
—
|
|
|
408
|
Crude oil inventory
|
|
|
2,232
|
|
|
—
|
|
|
2,232
|
Prepayments and other
|
|
|
3,058
|
|
|
—
|
|
|
3,058
|
Current assets - discontinued operations
|
|
|
3,222
|
|
|
—
|
|
|
3,222
|
Total current assets
|
|
|
44,591
|
|
|
—
|
|
|
44,591
|
Oil and natural gas properties, at cost - successful efforts method:
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
398,072
|
|
|
11,539
|
|
|
409,611
|
Unproved properties
|
|
|
16,698
|
|
|
7,073
|
|
|
23,771
|
Equipment and other
|
|
|
8,821
|
|
|
—
|
|
|
8,821
|
|
|
|
423,591
|
|
|
18,612
|
|
|
442,203
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(388,660)
|
|
|
—
|
|
|
(388,660)
|
Net oil and natural gas properties, equipment and other
|
|
|
34,931
|
|
|
18,612
|
|
|
53,543
|
Other noncurrent assets:
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
918
|
|
|
—
|
|
|
918
|
Value added tax and other receivables, net of allowance of $2.1 million
|
|
|
2,306
|
|
|
—
|
|
|
2,306
|
Deferred tax assets
|
|
|
68,807
|
|
|
(18,612)
|
|
|
50,195
|
Abandonment funding
|
|
|
10,808
|
|
|
—
|
|
|
10,808
|
Total assets
|
|
$
|
162,361
|
|
$
|
—
|
|
$
|
162,361
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
7,219
|
|
$
|
—
|
|
$
|
7,219
|
Accounts with joint venture owners
|
|
|
5,496
|
|
|
—
|
|
|
5,496
|
Accrued liabilities and other
|
|
|
17,662
|
|
|
—
|
|
|
17,662
|
Foreign taxes payable
|
|
|
1,775
|
|
|
—
|
|
|
1,775
|
Current portion of long term debt
|
|
|
—
|
|
|
—
|
|
|
—
|
Current liabilities - discontinued operations
|
|
|
15,191
|
|
|
—
|
|
|
15,191
|
Total current liabilities
|
|
|
47,343
|
|
|
—
|
|
|
47,343
|
Asset retirement obligations
|
|
|
14,459
|
|
|
—
|
|
|
14,459
|
Other long-term liabilities
|
|
|
1,264
|
|
|
—
|
|
|
1,264
|
Long term debt, excluding current portion, net
|
|
|
—
|
|
|
—
|
|
|
—
|
Total liabilities
|
|
|
63,066
|
|
|
—
|
|
|
63,066
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
Shareholders’ equity:
|
|
|
|
|
|
|
|
|
|
Preferred stock, none issued, 500,000 shares authorized, $25 par value
|
|
|
—
|
|
|
—
|
|
|
—
|
Common stock, $0.10 par value; 100,000,000 shares authorized, 67,092,825 shares issued and 59,538,878 shares outstanding
|
|
|
6,709
|
|
|
—
|
|
|
6,709
|
Additional paid-in capital
|
|
|
72,229
|
|
|
—
|
|
|
72,229
|
Less treasury stock, 7,553,947 shares at cost
|
|
|
(37,798)
|
|
|
—
|
|
|
(37,798)
|
Retained earnings
|
|
|
58,155
|
|
|
—
|
|
|
58,155
|
Total shareholders' equity
|
|
|
99,295
|
|
|
—
|
|
|
99,295
|
Total liabilities and shareholders' equity
|
|
$
|
162,361
|
|
$
|
—
|
|
$
|
162,361
|
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
This supplemental information is presented in accordance with certain provisions of ASC Topic 932 –
Extractive Activities- Oil and Natural Gas
. The geographic areas reported are the U.S. (North America), which includes our producing properties in the state of Texas, and International, which includes our producing properties offshore Gabon (Africa).
Costs Incurred for Acquisition, Exploration and Development Activities
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Costs incurred during the year:
|
|
(in thousands)
|
International:
|
|
|
|
|
|
|
|
|
|
Exploration costs - capitalized
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
Exploration costs - expensed
|
|
|
14
|
|
|
7
|
|
|
5
|
Acquisition of properties
|
|
|
36,239
|
|
|
—
|
|
|
5,754
|
Development costs
|
|
|
—
|
|
|
—
|
|
|
—
|
Total
|
|
$
|
36,253
|
|
$
|
7
|
|
$
|
5,759
|
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Capitalized costs pertain to our producing activities in Gabon and the U.S. and to undeveloped leasehold in Gabon, Equatorial Guinea and the U.S.
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2018
|
|
2017
|
Capitalized costs:
|
|
(in thousands)
|
Properties not being amortized
|
|
$
|
30,059
|
|
$
|
15,668
|
Properties being amortized
(1)
|
|
|
409,487
|
|
|
389,935
|
Total capitalized costs
|
|
$
|
439,546
|
|
$
|
405,603
|
Less accumulated depletion, amortization and impairment
|
|
|
(387,868)
|
|
|
(384,014)
|
Net capitalized costs
|
|
$
|
51,678
|
|
$
|
21,589
|
(1)
Includes $7.8 million and $11.0 million asset retirement cost in 2018 and 2017, respectively
.
During the year ended December 31, 2018, we recorded a downward revision of $6.5 million to the ARO liability as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame PSC was extended to at least September 16, 2028 as discussed further in Note 9.
Results of Operations for Oil and Natural Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
U.S.
|
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
Crude oil and natural gas sales
|
|
$
|
104,938
|
|
$
|
76,978
|
|
$
|
59,460
|
|
$
|
5
|
|
$
|
47
|
|
$
|
324
|
Production costs and other expense
(1)
|
|
|
(37,865)
|
|
|
(41,558)
|
|
|
(38,160)
|
|
|
(13)
|
|
|
(26)
|
|
|
(166)
|
Depreciation, depletion, amortization
|
|
|
(5,176)
|
|
|
(6,196)
|
|
|
(6,531)
|
|
|
(162)
|
|
|
(1)
|
|
|
(151)
|
Exploration expenses
|
|
|
(14)
|
|
|
(7)
|
|
|
(5)
|
|
|
—
|
|
|
—
|
|
|
—
|
Impairment of proved properties
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(88)
|
Other operating expense
|
|
|
—
|
|
|
—
|
|
|
(8,853)
|
|
|
—
|
|
|
—
|
|
|
—
|
Bad debt recovery (expense)
|
|
|
77
|
|
|
(452)
|
|
|
(1,222)
|
|
|
—
|
|
|
—
|
|
|
—
|
Income tax benefit (expense)
|
|
|
(37,591)
|
|
|
(11,638)
|
|
|
(9,248)
|
|
|
36
|
|
|
1,260
|
|
|
—
|
Results from oil and natural gas producing activities
|
|
$
|
24,369
|
|
$
|
17,127
|
|
$
|
(4,559)
|
|
$
|
(134)
|
|
$
|
1,280
|
|
$
|
(81)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes local general and administrative expenses, but excludes corporate general and administrative expenses and allocated corporate overhead.
Estimated Quantities of
Proved Reserves
The estimation of net recoverable quantities of crude oil and natural gas is a highly technical process which is based upon several underlying assumptions that are subject to change. See “
Item 1A. Risk Factors
” and “
Item 7. Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Critical Accounting Policies and Estimates – Successful Efforts Method of Accounting for Oil and Natural Gas Activities.”
For a discussion of our reserve estimation process, including internal controls, see “
Item 1. Business – Reserve Information
.”
|
|
|
|
|
|
|
Oil
|
|
Natural
|
Proved reserves:
|
|
(MBbls)
|
|
Gas (MMCF)
|
Balance at January 1, 2016
|
|
2,855
|
|
1,053
|
Production
|
|
(1,518)
|
|
(124)
|
Purchases of minerals in place
|
|
308
|
|
—
|
Sales of minerals in place
|
|
(12)
|
|
(929)
|
Revisions of previous estimates
|
|
1,009
|
|
—
|
Balance at December 31, 2016
|
|
2,642
|
|
—
|
Production
|
|
(1,518)
|
|
—
|
Revisions of previous estimates
|
|
1,925
|
|
—
|
Balance at December 31, 2017
|
|
3,049
|
|
—
|
Production
|
|
(1,369)
|
|
—
|
Additions associated with PSC Extension
|
|
2,235
|
|
—
|
Revisions of previous estimates
|
|
1,455
|
|
—
|
Balance at December 31, 2018
|
|
5,370
|
|
—
|
|
|
|
|
|
|
|
Oil
|
|
Natural
|
Proved developed reserves:
|
|
(MBbls)
|
|
Gas (MMCF)
|
Balance at January 1, 2016
|
|
2,855
|
|
1,053
|
Balance at December 31, 2016
|
|
2,642
|
|
—
|
Balance at December 31, 2017
|
|
3,049
|
|
—
|
Balance at December 31, 2018
|
|
3,388
|
|
—
|
Our proved developed reserves are located offshore Gabon.
In 2018, we replaced 270% of production by adding a total of 3.7 MMBbls of proved reserves including 2.2 MMBbls of proved reserves additions as a result of extending the Etame PSC in Gabon. We also added 1.1 MMBbls of proved reserves as a result of improved reservoir performance and another 0.4 MMBbls of proved reserves as a result of higher oil pricing. The upward revision of the previous estimates in 2017 was primarily a result of improved well performance and to a lesser degree the higher average crude oil prices.
Reserves in 2018 also increased as a result of the PSC Extension.
In 2016, reserves increased as a result of estimated proved reserve quantities related to our acquisition of the Sojitz working interest in Etame Marin block (308 MBbls) as well as upward revisions to our estimated proved reserve quantities as a result of cost cutting efforts that had the impact of driving down operating cost projections and extending economic limits, demonstration of the effectiveness of deploying lower cost hydraulic workover units to conduct workovers during 2016 and success in production optimization produced better-than-forecasted results from the prior year’s development program (1,575 MBbls).
We maintain a policy of not booking proved reserves on discoveries until such time as a development plan has been prepared for the discovery indicating that the development well will be drilled within five years from the date of its initial booking. Additionally, the development plan is required to have the approval of our joint owners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves
The information that follows has been developed pursuant to procedures prescribed GAAP and uses reserve and production data estimated by independent petroleum consultants. The information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating us or our performance.
In accordance with the guidelines of the SEC, our estimates of future net cash flow from our properties and the present value thereof are made using oil and natural gas contract prices using a twelve month average of beginning of month prices and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The future cash flows are also based on costs in existence at the dates of the projections, excluding Gabon royalties, and the interests of other Consortium members. Future production costs do not include overhead charges allowed under joint operating agreements or headquarters general and administrative overhead expenses. However, all future costs related to future property abandonment when the wells become uneconomic to produce are included in future development costs for purposes of calculating the standardized measure of discounted net cash flows. There were no discounted future net cash flows attributable to U.S. properties as of December 31, 2018, 2017 and 2016.
|
|
|
|
|
|
|
|
|
|
|
|
International
|
(In thousands)
|
|
2018
|
|
2017
|
|
2016
|
Future cash inflows
|
|
$
|
387,415
|
|
$
|
165,341
|
|
$
|
106,583
|
Future production costs
|
|
|
(228,999)
|
|
|
(108,387)
|
|
|
(71,260)
|
Future development costs
(1)
|
|
|
(27,151)
|
|
|
(8,803)
|
|
|
(10,887)
|
Future income tax expense
|
|
|
(38,512)
|
|
|
(24,798)
|
|
|
(16,346)
|
Future net cash flows
|
|
|
92,753
|
|
|
23,353
|
|
|
8,090
|
Discount to present value at 10% annual rate
|
|
|
(12,697)
|
|
|
(863)
|
|
|
1,351
|
Standardized measure of discounted future net cash flows
|
|
$
|
80,056
|
|
$
|
22,490
|
|
$
|
9,441
|
(1)
Includes costs expected to be incurred to abandon the properties.
International income taxes represent amounts payable to the Government of Gabon on profit oil as final payment of corporate income taxes, and domestic income taxes (including other expenses treated as taxes).
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in standardized measure of discounted future net cash flows as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
Balance at beginning of period
|
|
$
|
22,490
|
|
$
|
9,441
|
|
$
|
27,141
|
Sales of oil and natural gas, net of production costs
|
|
|
(71,962)
|
|
|
(37,328)
|
|
|
(22,198)
|
Net changes in prices and production costs
|
|
|
55,468
|
|
|
35,257
|
|
|
(25,958)
|
Revisions of previous quantity estimates
|
|
|
33,344
|
|
|
18,743
|
|
|
19,558
|
Purchases
|
|
|
43,236
|
|
|
—
|
|
|
3,400
|
Divestitures of reserves
|
|
|
—
|
|
|
—
|
|
|
(835)
|
Changes in estimated future development costs
|
|
|
1,075
|
|
|
(692)
|
|
|
—
|
Development costs incurred during the period
|
|
|
763
|
|
|
2,298
|
|
|
—
|
Accretion of discount
|
|
|
4,530
|
|
|
2,482
|
|
|
4,657
|
Net change of income taxes
|
|
|
(8,889)
|
|
|
(7,432)
|
|
|
4,052
|
Change in production rates (timing) and other
|
|
|
1
|
|
|
(279)
|
|
|
(376)
|
Balance at end of period
|
|
$
|
80,056
|
|
$
|
22,490
|
|
$
|
9,441
|
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown for Gabon are recoverable under a service contract and the reserves in place at the end of the contract period remain the property of the Gabon government.
In accordance with the current guidelines of the SEC, estimates of future net cash flow from our properties and the present value thereof are made using an unweighted, arithmetic average of the first-day-of-the-month price for each of the 12 months of the year adjusted for quality, transportation fees and market differentials. Such prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For 2018, the average of such prices reflected a 32% increase during the year and were $70.83 per Bbl for crude oil from Gabon when compared to the average of such prices for 2017 of $53.49 per Bbl for crude oil from Gabon.
Under the Etame PSC in Gabon, the Gabonese government is the owner of all oil and natural gas mineral rights. The right to produce the oil and natural gas is stewarded by the Directorate Generale de Hydrocarbures and the Etame PSC was awarded by a decree from . Pursuant to the contract, the Gabon government receives a fixed royalty rate of 13%. Originally, under the Etame PSC, Gabonese government was not anticipated to take physical delivery of its allocated production. Instead, we were authorized to sell the Gabonese government’s share of production and remit the proceeds to the Gabonese government. Beginning in February 2018, the Gabonese government elected to take physical delivery of its allocated production volumes for Profit Oil (see discussion in Note 7 above).
The Consortium maintains a Cost Account, which entitles it to receive a portion of the production remaining after deducting the 13% royalty so long as there are amounts remaining in the Cost Account (“Cost Recovery”).
Prior to the PSC Extension, the Consortium was entitled to a 70% Cost Recovery Percentage. Under the PSC Extension, the Cost Recovery Percentage is increased to 80% for the ten-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%.
At December 31,
2018, there was $65.5 million in the Cost Account
, net to our interest. As payment of corporate income taxes, the Consortium pays the government an allocation of the remaining Profit Oil production from the contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and Cost Recovery. The percentage of Profit Oil paid to the government as tax is a function of production rates. However, when the Cost Account becomes substantially recovered, we only recover ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. Also because of the nature of the Cost Account, decreases in oil prices result in a higher number of barrels required to recover costs.
The Etame PSC allows for exploitation period through the carve-out of development areas which include all producing fields in the Etame Marin block as well as additional undeveloped areas where reserves may exist.
The PSC Extension extends the term for each of the three exploitation areas in the Etame Marin block for a period of ten years with effect from September 17, 2018, the effective date of the PSC Extension. Prior to the PSC Extension, the exploitation periods for the three exploitation areas in the Etame Marin block would expire beginning in June 2021. The PSC Extension also grants the Consortium the right for two additional extension periods of five years each.
This compares to the economic end date of reserves under the current reserve report prepared by our independent reserve engineering firm of Netherland, Sewell & Associates, Inc.
The PSC for Block P in Equatorial Guinea entitles us to receive up to 70% of any future production after royalty deduction so long as there are amounts remaining in the Cost Account. Royalty rates are 10-16% depending on production rates. The Consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 10% to 60% of the oil remaining after deducting the royalty and Cost Recovery. The percentage of “profit oil” paid to the government as tax is a function of cumulative production. In addition, Equatorial Guinea imposes a 25% income tax on net profits. The Block P PSC provides for a discovery to be reclassified into a development area with a term of 25 years. At December 31, 2018, we have no proved reserves related to Block P in Equatorial Guinea.