10-Q 1 egy-20170930x10q.htm 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-Q

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(Mark One)

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

For the quarterly period ended September 30, 2017

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

For the transition period from _______ to _______

Commission file number 1-32167

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VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)

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

(713) 623-0801

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

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

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Large accelerated filer | ☐ |  | Accelerated filer | ☒
Non‑accelerated filer | ☐ | (Do not check if a smaller reporting company) | Smaller reporting company Emerging growth company | ☐ ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.☐

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ☐ No ☒

As of October 31, 2017, there were o utstanding 58,818,031 shares of common stock, $0.10 par value per share, of the registrant.

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Table of Contents

VAA LCO ENERGY, INC. AND SUBSIDIARIES

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﻿PART I. FINANCIAL INFORMATION |
﻿ITEM 1. C ONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited) |
﻿Condensed Consolidated Balance Sheets |
﻿September 30, 2017 and December 31, 20 16 | 3
﻿Condensed Consolidated Statements of Operations |
﻿Three and Nine Months Ended September 30, 2017 and 20 16 | 4
﻿Condensed Consolidated Statements of Cash Flows |
﻿Nine M onths E nded September 30, 2017 and 20 16 | 5
﻿Notes to Condensed Consolidated Financial Statements | 6
﻿ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 18
﻿ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 26
﻿ITEM 4. CONTROLS AND PROCEDURES | 26
﻿PART II. OTHER INFORMATION | 27
﻿ITEM 1. LEGAL PROCEEDINGS | 27
﻿ITEM 1A. RISK FACTORS | 28
﻿ITEM 6. E XHIBITS | 29

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

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PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

VAA LCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(U naudited)

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

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﻿ |  | September 30, 2017 |  | December 31, 2016
ASSETS |  |
Current assets: |  |  |  |  |  |
Cash and cash equivalents |  | $ | 18,863 |  | $ | 20,474
Restricted cash |  |  | 829 |  |  | 741
Receivables: |  |  |  |  |  |
Trade |  |  | 7,203 |  |  | 6,751
Accounts with partners, net of allowance of $0.5 million at September 30, 2017 and December 31, 2016 |  |  | 2,748 |  |  | 3,297
Other |  |  | 1 |  |  | 120
Crude oil inventory |  |  | 1,160 |  |  | 913
Prepayments and other |  |  | 2,952 |  |  | 4,040
Current assets - discontinued operations |  |  | 2,773 |  |  | 2,139
Total current assets |  |  | 36,529 |  |  | 38,475
Property and equipment - successful efforts method: |  |  |  |  |  |
Wells, platforms and other production facilities |  |  | 389,204 |  |  | 389,231
Undeveloped acreage |  |  | 10,000 |  |  | 10,000
Equipment and other |  |  | 10,318 |  |  | 9,779
﻿ |  |  | 409,522 |  |  | 409,010
Accumulated depreciation, depletion, amortization and impairment |  |  | (385,617) |  |  | (380,991)
Net property and equipment |  |  | 23,905 |  |  | 28,019
Other noncurrent assets: |  |  |  |  |  |
Restricted cash |  |  | 967 |  |  | 918
Value added tax and other receivables, net of allowance of $6.2 million and $4.7 million at September 30, 2017 and December 31, 2016, respectively |  |  | 6,624 |  |  | 5,110
Abandonment funding |  |  | 8,510 |  |  | 8,510
Total assets |  | $ | 76,535 |  | $ | 81,032
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LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT) |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |
Accounts payable |  | $ | 13,849 |  | $ | 19,096
Accrued liabilities and other |  |  | 10,098 |  |  | 10,506
Current portion of long term debt |  |  | 7,500 |  |  | 7,500
Current liabilities - discontinued operations |  |  | 15,400 |  |  | 18,452
Total current liabilities |  |  | 46,847 |  |  | 55,554
Asset retirement obligations |  |  | 19,202 |  |  | 18,612
Other long term liabilities |  |  | 284 |  |  | 284
Long term debt, excluding current portion |  |  | 3,483 |  |  | 6,940
Total liabilities |  |  | 69,816 |  |  | 81,390
Commitments and contingencies (Note 6) |  |  |  |  |  |
Shareholders’ equity (deficit): |  |  |  |  |  |
Preferred stock, none issued, 500,000 shares authorized, $25 par value |  |  | — |  |  | —
Common stock, 66,382,243 and 66,109,565 shares issued $0.10 par value, 100,000,000 shares authorized |  |  | 6,638 |  |  | 6,611
Additional paid-in capital |  |  | 71,106 |  |  | 70,268
Less treasury stock, 7,564,212 and 7,555,095 shares at cost |  |  | (37,941) |  |  | (37,933)
Accumulated deficit |  |  | (33,084) |  |  | (39,304)
Total shareholders' equity (deficit) |  |  | 6,719 |  |  | (358)
Total liabilities and shareholders' equity (deficit) |  | $ | 76,535 |  | $ | 81,032
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See notes to condensed consolidated financial statements.

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VA ALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share amounts)

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﻿ |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
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Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Oil and natural gas sales |  | $ | 18,178 |  | $ | 14,635 |  | $ | 59,869 |  | $ | 44,458
Operating costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Production expense |  |  | 10,336 |  |  | 7,162 |  |  | 28,148 |  |  | 25,756
Exploration expense |  |  | 4 |  |  | 2 |  |  | 4 |  |  | 4
Depreciation, depletion and amortization |  |  | 1,700 |  |  | 1,607 |  |  | 5,539 |  |  | 5,787
General and administrative expense |  |  | 2,463 |  |  | 1,588 |  |  | 8,654 |  |  | 7,839
Impairment of proved properties |  |  | — |  |  | 88 |  |  | — |  |  | 88
Other operating expense |  |  | — |  |  | 324 |  |  | — |  |  | 9,959
General and administrative related to shareholder matters |  |  | — |  |  | 85 |  |  | — |  |  | (350)
Bad debt expense and other |  |  | (49) |  |  | 63 |  |  | 232 |  |  | 577
Total operating costs and expenses |  |  | 14,454 |  |  | 10,919 |  |  | 42,577 |  |  | 49,660
Other operating income (expense), net |  |  | (3) |  |  | (26) |  |  | 164 |  |  | (8)
Operating income (loss) |  |  | 3,721 |  |  | 3,690 |  |  | 17,456 |  |  | (5,210)
Other expense: |  |  |  |  |  |  |  |  |  |  |  |
Interest expense, net |  |  | (327) |  |  | (327) |  |  | (1,108) |  |  | (2,285)
Other, net |  |  | (793) |  |  | (149) |  |  | (571) |  |  | (533)
Total other expense |  |  | (1,120) |  |  | (476) |  |  | (1,679) |  |  | (2,818)
Income (loss) from continuing operations before income taxes |  |  | 2,601 |  |  | 3,214 |  |  | 15,777 |  |  | (8,028)
Income tax expense |  |  | 2,749 |  |  | 2,198 |  |  | 9,039 |  |  | 6,884
Income (loss) from continuing operations |  |  | (148) |  |  | 1,016 |  |  | 6,738 |  |  | (14,912)
Loss from discontinued operations |  |  | (174) |  |  | (15,783) |  |  | (518) |  |  | (7,997)
Net income (loss) |  | $ | (322) |  | $ | (14,767) |  | $ | 6,220 |  | $ | (22,909)
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Basic net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Income (loss) from continuing operations |  | $ | 0.00 |  | $ | 0.02 |  | $ | 0.11 |  | $ | (0.25)
Loss from discontinued operations |  |  | (0.01) |  |  | (0.27) |  |  | (0.01) |  |  | (0.14)
Net income (loss) |  | $ | (0.01) |  | $ | (0.25) |  | $ | 0.10 |  | $ | (0.39)
Basic weighted average shares outstanding |  |  | 58,817 |  |  | 58,708 |  |  | 58,682 |  |  | 58,600
Diluted net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Income (loss) from continuing operations |  | $ | 0.00 |  | $ | 0.02 |  | $ | 0.11 |  | $ | (0.25)
Loss from discontinued operations |  |  | (0.01) |  |  | (0.27) |  |  | (0.01) |  |  | (0.14)
Net income (loss) |  | $ | (0.01) |  | $ | (0.25) |  | $ | 0.10 |  | $ | (0.39)
Diluted weighted average shares outstanding |  |  | 58,817 |  |  | 58,708 |  |  | 58,686 |  |  | 58,600

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See notes to condensed consolidated financial statements.

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VA ALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

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﻿ |  | Nine Months Ended September 30,
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CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |  |  |
Net income (loss) |  | $ | 6,220 |  | $ | (22,909)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: |  |  |  |  |  |
Loss from discontinued operations |  |  | 518 |  |  | 7,997
Depreciation, depletion and amortization |  |  | 5,539 |  |  | 5,787
Other amortization |  |  | 293 |  |  | 1,132
Unrealized foreign exchange (gain) loss |  |  | (512) |  |  | 2,175
Stock-based compensation |  |  | 933 |  |  | 93
Commodity derivatives loss |  |  | 971 |  |  | 772
Cash settlements received on matured derivative contracts |  |  | 195 |  |  | —
Bad debt provision |  |  | 232 |  |  | 577
Other operating (income) loss, net |  |  | (164) |  |  | 8
Impairment of proved properties |  |  | — |  |  | 88
Change in operating assets and liabilities: |  |  |  |  |  |
Trade receivables |  |  | (452) |  |  | (587)
Accounts with partners |  |  | 542 |  |  | 18,126
Other receivables |  |  | 274 |  |  | 12
Crude oil inventory |  |  | (247) |  |  | (131)
Value added tax and other receivables |  |  | (2,783) |  |  | (1,526)
Prepayments and other |  |  | 1,559 |  |  | (503)
Accounts payable |  |  | (5,250) |  |  | (24,339)
Accrued liabilities and other |  |  | (432) |  |  | 24
Net cash provided by (used in) continuing operating activities |  |  | 7,436 |  |  | (13,204)
Net cash provided by (used in) discontinued operating activities |  |  | (4,204) |  |  | 13,168
Net cash provided by (used in) operating activities |  |  | 3,232 |  |  | (36)
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |  |  |
(Increase) decrease in restricted cash |  |  | (137) |  |  | 15,260
Acquisitions |  |  | 64 |  |  | —
Property and equipment expenditures |  |  | (1,300) |  |  | (12,781)
Proceeds from the sale of oil and gas properties |  |  | 250 |  |  | —
Premiums paid |  |  | — |  |  | (824)
Net cash provided by (used in) continuing investing activities |  |  | (1,123) |  |  | 1,655
Net cash provided by discontinued investing activities |  |  | — |  |  | —
Net cash provided by (used in) investing activities |  |  | (1,123) |  |  | 1,655
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |  |  |
Proceeds from the issuances of common stock |  |  | 38 |  |  | —
Treasury shares |  |  | (8) |  |  | —
Debt issuance costs |  |  | — |  |  | (93)
Debt repayment |  |  | (7,917) |  |  | —
Borrowings |  |  | 4,167 |  |  | —
Net cash used in continuing financing activities |  |  | (3,720) |  |  | (93)
Net cash provided by discontinued financing activities |  |  | — |  |  | —
Net cash used in financing activities |  |  | (3,720) |  |  | (93)
NET CHANGE IN CASH AND CASH EQUIVALENTS |  |  | (1,611) |  |  | 1,526
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD |  |  | 20,474 |  |  | 25,357
CASH AND CASH EQUIVALENTS AT END OF PERIOD |  | $ | 18,863 |  | $ | 26,883
Supplemental disclosure of cash flow information: |  |  |  |  |  |
Interest paid, net of capitalized interest |  | $ | 811 |  | $ | 1,046
Income taxes paid |  | $ | 12,069 |  | $ | 6,930
Supplemental disclosure of non-cash investing and financing activities: |  |  |  |  |  |
Property and equipment additions incurred but not paid at period end |  | $ | 379 |  | $ | 1,990
Asset retirement obligations |  | $ | (103) |  | $ | 42

See notes to condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND ACCOUNTING POLICIES

VAALCO Energy, Inc. (together with its consolidated subsidiaries, “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 development activities in Gabon, West Africa. As non-operator, we have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, we have discontinued operations associated with our activities in Angola, West Africa.

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

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

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

Certain reclassifications have been made to prior period amounts related to reclassifying material and supplies to prepayments and other to conform to the current period presentation. These reclassifications did not affect our consolidated financial results.

Bad debt – Quarterly, we evaluate our accounts receivable balances to confirm collectability. When collectability is in doubt, we record an allowance against the accounts receivable and a corresponding income charge for bad debts, which appears in the “Bad debt expense and other” line item of the condensed consolidated statements of operations. The majority of our accounts receivable balances are with our joint venture partners and the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection effo rts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to us. Portions of our costs in Gabon (including our VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). As of September 30, 2017, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF 20.5 billion (XAF 6.9 billion, net to VAALCO). As of September 30, 2017, the exchange rate was XAF 555.742 = $1.00.

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

For the three and nine months ended September 30, 2017, we recorded allowances of $ (0.1) million and $0.2 million, respectively, related to VAT for which the government of Gabon has not reimbursed us. For the three and nine month periods ended September 30, 2016, we recorded allowances of $0.1 million and $0.6 million, respective ly. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on profit/loss. Such foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.

The following table provides a rollforward of the aggregate allowance:

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Allowance for bad debt |  |  |  |  |  |
Balance at beginning of year |  | $ | (5,211) |  | $ | (4,221)
Charge to cost and expenses |  |  | (232) |  |  | (577)
Reclassification related to Sojitz acquisition |  |  | (694) |  |  | —
Foreign currency loss |  |  | (583) |  |  | (84)
Balance at end of period |  | $ | (6,720) |  | $ | (4,882)
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General and administrative related to shareholder matters – General and administrative expenses related to sharehold er matters for the three and nine months ended September 30, 2016 represent costs incurred related to shareholder litigation that was settled in April 2016. For 2016, the amounts also include the offsetting insurance proceeds related to these matters.

2. NEW ACCOUNTING STANDARDS

Not yet adopted

In May 2017, the Financial Accounting Standards Board (“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. We are currently evaluating the provisions of ASU 2017-09 and are assessing its potential impact on our financial position, results of operations, cash flows and related disclosures.

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

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

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

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including our trade and partner 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 1 5, 2019, including interim periods within those fiscal years and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We are currently evaluating the provisions of ASU 2016-13 and are assessing its potential impact on our financial position, results of operations, cash flows and related disclosures.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which amends the accounting standards for leases. ASU 2016-02 retains a distinction between finance leases and operating leases. The primary change is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Certain aspects of lease accounting have been simplified and additional qualitative and quantitative disclosures are required along with specific quantitative disclosures required by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest

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period presented using a modified retrospective approach. The amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early application permitted. We are required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period presented in the financial statements. Early adoption is allowed. Assuming adoption January 1, 2019, we expect that leases in effect on January 1, 2017 and leases entered into after such date will be reflected in accordance with the new standard in the audited consolidated financial statements included in our Annual Report on Form 10-K for 2019, including comparative financial statements presented in such report. We are in the preliminary stages of our gap assessment, but we expect that leases treated as operating leases with terms greater than 12 months will be capitalized. We expect adoption of this standard to result in the recording of a right of use asset related to certain of our operating leases with a corresponding lease liability. This is expected to result in a material increase in total assets and liabilities as certain of our operating leases are significant as disclosed in our Annual Report on Form 10-K for 2016. We do not expect there will be a material overall impact on results of operations or cash flows. We are continuing to evaluate the impact of this new standard, and are in the process of developing our implementation plan.

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

Adopted

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

﻿

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3. AQUISITIONS AND DISPOSITIONS

Sojitz Acquisition

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

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

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

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

Sale of Certain U.S. Properties

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

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

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Summarized Results of Discontinued Operations

﻿

﻿ |  |  |  |  |  |  |  |  |  |  |  |
﻿ |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
﻿ |  | 2017 |  | 2016 |  | 2017 |  | 2016
﻿ |  | (in thousands)
Operating costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Exploration expense |  | $ | — |  | $ | 15,269 |  | $ | — |  | $ | 15,270
Depreciation, depletion and amortization |  |  | — |  |  | 3 |  |  | — |  |  | 9
General and administrative expense |  |  | 174 |  |  | 400 |  |  | 512 |  |  | 994
Bad debt recovery and other |  |  | — |  |  | — |  |  | — |  |  | (7,629)
Total operating costs, expenses and (recovery) |  |  | 174 |  |  | 15,672 |  |  | 512 |  |  | 8,644
Other operating loss, net |  |  | — |  |  | (7) |  |  | — |  |  | (28)
Operating loss |  |  | (174) |  |  | (15,679) |  |  | (512) |  |  | (8,672)
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |
Interest income |  |  | — |  |  | — |  |  | — |  |  | 3,201
Other, net |  |  | — |  |  | 6 |  |  | (3) |  |  | 551
Total other income (expense) |  |  | — |  |  | 6 |  |  | (3) |  |  | 3,752
Loss from discontinued operations before income taxes |  |  | (174) |  |  | (15,673) |  |  | (515) |  |  | (4,920)
Income tax expense |  |  | — |  |  | 110 |  |  | 3 |  |  | 3,077
Loss from discontinued operations |  | $ | (174) |  | $ | (15,783) |  | $ | (518) |  | $ | (7,997)

﻿

Assets and Liabilities Attributable to Discontinued Operations

﻿

﻿ |  |  |  |  |  |
﻿ |  | September 30, 2017 |  | December 31, 2016
﻿ |  | (in thousands)
ASSETS |  |  |  |  |  |
Current assets: |  |  |  |  |  |
Accounts with partners |  | $ | 2,773 |  | $ | 2,139
Total current assets |  |  | 2,773 |  |  | 2,139
Total assets |  | $ | 2,773 |  | $ | 2,139
﻿ |  |  |  |  |  |
LIABILITIES |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |
Accounts payable |  | $ | 215 |  | $ | 77
Foreign taxes payable |  |  | — |  |  | 3,078
Accrued liabilities and other |  |  | 15,185 |  |  | 15,297
Total current liabilities |  |  | 15,400 |  |  | 18,452
Total liabilities |  | $ | 15,400 |  | $ | 18,452

Drilling Obligation

Under the PSA, Vaalco A ngola 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 VAALCO Angola’s participating interest share would be $5.0 million per well. We have reflected an accrual of $15.0 million for a potential payment as of September 30, 2017 and December 31, 2016, respectively, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA. However, we are curre ntly engaged in discussions and meetings with newly appointed representatives from Sonangol E.P. regarding this potential payment and other possible solutions and believe th at the ultimate amount paid could be substantiall y less than the accrued amount.

Other Matters – Partner Receivable

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

On March 14, 2016, we received a $19.0 million payment from Sonangol P&P for the full amount owed us as of December 31, 2015, including the $7.6 million of pre-assignment costs and default interest of $3.2 million. The $7.6 million recovery is reflected in the “Bad debt recovery and other” line item of our summarized results of discontinued operations for the nine months ended September

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30, 2016. Default interest of $3.2 million is shown in the “Interest income” line item of our summarized results of discontinued operations for the nine months ended September 30, 2016.

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4. OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

We review our oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When an oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in our impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.

There was no triggering event in the third quarter of 2017 that would cause us to believe the value of oil and natural gas producing properties should be impaired. Factors considered included the fact that we incurred no capital expenditures in 2017 related to the field s in the Etame Marin block, the future strip prices for the third quarter of 2017 increased, and there were no indicators that adjustments were needed to the year-end reserve report.

Declining forecasted oil prices and other factors caused us to perform impairment reviews of our proved properties in the first quarter of 2016 for all fields in the Etame Marin block offshore Gabon and the Hefley field in North Texas. However, no impairment was required for the quarter ended March 31, 2016. During the second quarter of 2016, forecasted oil prices improved significantly, our negative price differential to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the impact on reserves of a well being shut-in in the Avouma field in the Etame Marine block offshore Gabon. After consider this factor, we determined that t he undiscounted future net cash flows for the Avouma field were in excess of the field’s carrying value. No impairment was required for the Avouma field, or any of our other fields, for the second quarter of 2016. During the third quarter of 2016, our negative price differential to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the impact on reserves of a second well being shut-in in the Avouma field. After considering this factor, we determined that t he undiscounted future net cash flows for the Avouma field were in excess of the field’s carrying value. No impairment was required for the Avouma field, or any of our other fields, for the third quarter of 2016.

5. DEBT

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

The Amended Term Loan Agreement also provided for an additional $5.0 million, which could be requested in a single draw, subject 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 will be repaid in five quarterly principal installments commencing June 30, 2017, together with interest which will accrue at LIBOR plus 5.75%.

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

Covenants

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

Interest

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

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

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

﻿ |  |  |  |  |  |  |  |  |  |  |  |
﻿ |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
﻿ |  | 2017 |  | 2016 |  | 2017 |  | 2016
﻿ |  | (in thousands)
Interest incurred, including commitment fees |  | $ | 222 |  | $ | 274 |  | $ | 796 |  | $ | 1,047
Deferred finance cost amortization |  |  | 91 |  |  | 56 |  |  | 293 |  |  | 262
Deferred finance cost write-off due to loan modification |  |  | — |  |  | — |  |  | — |  |  | 869
Other interest not related to debt |  |  | 14 |  |  | (3) |  |  | 19 |  |  | 107
Interest expense, net |  | $ | 327 |  | $ | 327 |  | $ | 1,108 |  | $ | 2,285
﻿ |  |  |  |  |  |  |  |  |  |  |  |
Average effective interest rate, excluding commitment fees |  |  | 6.54% |  |  | 6.38% |  |  | 6.87% |  |  | 5.04%

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6. COMMITMENTS AND CONTINGENCIES

Abandonment funding

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

Audits

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

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

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

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

Rig commitment

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

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

7. DERIVATIVES AND FAIR VALUE

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. While these 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. These changes in fair value have no cash flow impact. The impact to cash flow occurs upon settlement of the underlying contract. We do not enter into derivative instruments for speculative or trading proposes.

As of September 30, 2017, we had unexpired oil puts covering 18 0,000 barrels of anticipated sales volumes for the period from October 2017 through December 31, 2017 at a weighted average price of $50.00. Our put contracts are subject to agreements similar to a master netting agreement, under which we have the legal right to offset assets and liabilities. At September 30, 2017, our unexpired oil puts represented a fair value asset position of $0.1 million in the “Prepayments and other” line item of our condensed consolidated balance sheets.

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

﻿

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

The crude oil put 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 put contract 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 loss on derivative instruments in our condensed consolidated statements of operations:

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﻿ |  |  |  |  |  |  |  |  |  |  |  |  |  |
﻿ |  |  |  |
﻿ |  |  |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
Derivative Item |  | Statement of Operations Line |  | 2017 |  | 2016 |  | 2017 |  | 2016
﻿ |  |  |  | (in thousands)
Crude oil puts |  | Other, net |  | $ | (921) |  | $ | (194) |  | $ | (971) |  | $ | (772)

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8. STOCK-BASED COMPENSATION

Our stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of our Board of Directors to issue various types of incentive compensation. Currently, we have issued stock options, restricted shares and SARs under the 2014 Long-Term Incentive Plan (“2014 Plan”). At September 30, 2017, 2,126,942 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 three months ended September 30, 2017 and 2016, non-cash compensation expense was $0.2 million and $(1.3) million, respectively, related to the issuance of stock options and restricted stock. For the nine months ended September 30, 2017 and 2016, non-cash compensation was $0.9 million $0.1 million, respectively, related to the issuance of stock options and restricted stock. Because we do not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.

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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 immaterial cash proceeds from the exercise of stock options in the three and nine months ended September 30, 2017 and 2016. For the nine months ended September 30, 2017, options for 1,550,442 shares 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. Options for 465,950 shares were granted to our non-employee directors, which were fully vested upon their grant.

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

﻿

﻿ |  |  |  |  |
﻿ |  | Number of Shares Underlying Options |  | Weighted Average Exercise Price Per Share
﻿ |  | (in thousands) |  |  |
Outstanding at January 1, 2017 |  | 2,644 |  | $ | 3.92
Granted |  | 1,550 |  |  | 0.99
Exercised |  | (37) |  |  | 1.04
Forfeited/expired |  | (1,202) |  |  | 4.63
Outstanding at September 30, 2017 |  | 2,955 |  |  | 2.13

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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 of 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 th e nine months ended September 30, 2017.

﻿ |  |  |  |  |
﻿ |  | Restricted Stock |  | Weighted Average Grant Price
﻿ |  | (in thousands) |  |  |
Non-vested shares outstanding at January 1, 2017 |  | 252 |  | $ | 1.31
Awards granted |  | 386 |  |  | 0.98
Awards vested |  | (235) |  |  | 1.12
Awards forfeited |  | (41) |  |  | 1.00
Non-vested shares outstanding at September 30, 2017 |  | 362 |  |  | 1.12

In both the three months ended September 30, 2017 and 2016, 9,117 shares were added to treasury due to tax withholding as a result of the vesting of restricted shares. In the nine months ended September 30, 2017 and 2016, 9,117 shares and 40,926 shares, respectively, were added to treasury due to tax withholding as a result of the vesting of restricted shares.

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.

During the nine months ended September 30, 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; o ne-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds $1.50; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds $1.75. SARs granted in 2016 vest over a three year period with a life of 5 years; these SARs have a maximum spread equal to 300% of the $1.04 SAR price per share specified in a SAR award on the date of grant. The amounts of compensation payable related to these awards through September 30, 2017 have not been significant.

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SAR activity for the nine months ended September 30, 2017 is provided below:

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﻿ |  |  |  |  |
﻿ |  | Number of Shares Underlying SARs |  | Weighted Average Exercise Price Per Share
﻿ |  | (in thousands) |  |  |
Outstanding at January 1, 2017 |  | 180 |  | $ | 1.04
Granted |  | 1,050 |  |  | 1.20
Forfeited/expired |  | (153) |  |  | 1.20
Outstanding at September 30, 2017 |  | 1,077 |  |  | 1.17

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9. INCOME TAXES

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

As discussed further in the Notes to the consolidated financial statements in our Form 10-K for December 31, 2016, we have deferred tax assets related to foreign tax credits, alternative minimum tax credits, and domestic and foreign net operating losses (“NOLs”). Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. We do not anticipate utilization of the foreign tax credits prior to expiration nor do we expect to generate sufficient taxable income to utilize other deferred tax assets. On the basis of this evaluation, full valuation allowances have been recorded as of September 30, 2017 and December 31, 2016.

Income taxes attributable to continuing operations for the three and nine months ended September 30, 2017 and 2016 are attributable to foreign taxes payable in Gabon.

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

10. EARNINGS PER SHARE

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

A reconciliation from basic to diluted shares follows:

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﻿ |  |  |  |  |  |  |  |
﻿ |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
﻿ |  | 2017 |  | 2016 |  | 2017 |  | 2016
﻿ |  | (in thousands)
Basic weighted average shares outstanding |  | 58,817 |  | 58,708 |  | 58,682 |  | 58,600
Effect of dilutive securities |  | — |  | — |  | 4 |  | —
Diluted weighted average shares outstanding |  | 58,817 |  | 58,708 |  | 58,686 |  | 58,600
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive |  | 3,007 |  | 4,098 |  | 2,799 |  | 4,455

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11. SEGMENT INFORMATION

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

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

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

﻿

﻿

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

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

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

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﻿ |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
(in thousands) |  | Gabon |  | Equatorial Guinea |  | U.S. |  | Corporate and Other |  | Total
Total assets from continuing operations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
As of September 30, 2017 |  | $ | 61,694 |  | $ | 10,093 |  | $ | 83 |  | $ | 1,892 |  | $ | 73,762
As of December 31, 2016 |  |  | 64,478 |  |  | 10,122 |  |  | 382 |  |  | 3,911 |  |  | 78,893

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

| · |  | our ability to meet the financial covenants of our Amended Term Loan A greement;

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

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

| · |  | our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements through Dec ember 31, 2018;

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

| · |  | our ability to replace our Amended Term Loan A greement facility with another credit facility to help fund our future capital requirements;

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

| · |  | the uncertainty of estimates of oil and natural gas reserves;

| · |  | the impact of competition;

| · |  | the availability and cost of seismic, drilling and other equipment;

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

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

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

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

| · |  | timing and amount of future production of oil and natural gas;

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

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

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

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

| · |  | changes in customer demand and producers’ supply;

| · |  | future capital requirements and our ability to attract capital;

| · |  | currency exchange rates;

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

| · |  | actions by our venture partners;

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

| · |  | the outcome of any governmental audit;

| · |  | actions of operators of our oil and natural gas properties;

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

| · |  | weather conditions.

The information contained in this report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Form 10-K”) identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements which are included in this report and the 2016 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this report.

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

IN TRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct development activities in Gabon, West Africa. We have opportunities to participate in development and exploration activities as a non-operator in Equatorial Guinea, West Africa. As discussed further in Note 3 to the condensed consolidated financial statements, we have discontinued operations associated with our activities in Angola, West Africa, and in April 2017 we completed the sale of our interests in Montana.

A significant component of our results of operations is dependent upon the difference between prices received for our offshore Gabon oil production and the costs to find and produce such oil. Oil and natural gas prices have been volatile and subject to fluctuations based on a number of factors beyond our control. Beginning in the third quarter of 2014, the global prices for oil and natural gas began a dramatic decline which contin ued through 2015 and into 2016. During this period, we scaled back our global operations, divested non-core assets, amended our credit agreement and focused on reducing costs and maximizing our cash flows. Current prices, while higher than those in early 2016, are significantly less than they were in the several years prior to mid-2014. A decline in oil and natural gas prices and a sustained period of oil and natural gas prices at depressed levels could have a material adverse effect on our financial condition.

CURRENT DEVELOPMENTS

During 2016, the global oil supply continued to outpace demand, having a dampening effect on the recovery of real ized crude oil prices. While global oil supply and d emand were closer to being balanced during the first nine months of 2017, no assurances can be made that this trend will continue. Prices for crude oil improved during the second half of 2016 (ICE Dated Brent crude oil prices increased from approximately $36 per Bbl in early January 2016 to approximately $55 per Bbl at the end of 2016, and fluctuated between $44 and $6 1 per Bbl from January 2017 through October 2017).

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

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Our common stock is listed and traded on the NYSE. On April 6 and June 28, 2017, we received notices from the NYSE that we were not in compliance with a provision of the NYSE’s continued listing standards that require the average closing price of our common stock to be at least $1.00 per share over a consecutive 30-trading-day period. T he 30 trading-day average closing price o f the Company’s common stock for these notices had been $0.9 9 per share. We have responded to the se notification s, and will have six months from our receipt of the June 28, 2017 notice (which may be extended to our next annual shareholder meeting) to regain compliance with the minimum share price rule. This notice from the NYSE does not affect our business operations or trigger any default or other violation of our debt or other material obligations. In addition, we received a notification from the NYSE on November 30, 2016 that our market capitalization had fallen below the NYSE’s continued listing standard because our average market capitalization had fallen below $50 million over a trailing 30 trading-day period and our last reported stockholders’ equity was less than $50 million.

ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of four companies. As of September 30, 2017, production operations in the Etame Marin block included seven platform wells, plus three subsea wells across all fields tied back by pipelines to deliver oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased Floating, Production, Storage and Offloading vessel (“FPSO”) anchored to the seabed on the block. The FPSO has production limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day. During the nine months ended September 30, 2017 and 2016, production from the block was approximately 4,268 MBbls (1,154 MBbls net) and 4,835 MBbls (1,181 MBbls net), respectively.

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

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

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

During July 2017, production was temporarily shut-in for periodic maintenance, and as a result, production volumes were lower in the three months ended September 30, 2017 and our production expense increase d as a result of the maintenance-related costs.

Equatorial Guinea

We have a 31% working interest in an undeveloped portion of a block offshore Equatorial Guinea that we acquired in 2012. It is currently unlikely that we will be making any near-term expenditures with respect to any development of this property. Before beginning exploration, we and our partners will need to evaluate the timing and budgeting for development and exploration activities under a development and production area in the block, including the approval of a development and production plan. Our production sharing contract covering this development and production area provides for a development and production period of 25 years from the date of approval of a development and production plan. We are in continued discussions with the Minister of the Ministry of Mines and Hydrocarbons regarding the timing of any possible development plan.

Discontinued Operations - Angola

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

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Drilling Obligation

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

Other Matters – Partner Receivable

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

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

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash flows for the nine months ended September 30, 2017 and 2016 are as follows:

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

The increase in net cash provided by our operating activities for the nine months ended September 30, 2017 compared to the same period of 2016 was primarily related to a $20.6 million increase in cash generated by continuing operations which in large part was the result of higher 2017 crude oil prices and lower operating costs and expenses. This overall improvement was offset by a reduction in cash generated by our disconti nued operation for the first nine months of 2017 totaling $17.4 million. The decrease in cash generated by discontinued operations was the result of a benefit received in the nine months September 30, 2016 of $19.0 million f rom our Angolan joint interest partner in payment of partner receivables.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. During the nine months ended September 30, 2017, these expenditures on a cash basis were $1.3 million, primarily related to equipment purchases. This compares to $12.8 million in property and equipment expenditures included in capital expenditures for the nine months ended September 30, 2016. See “Capit al Expenditures” below for further discussion. Net cash provided by investing activities for the 2016 period also included a $15.3 million benefit from the decrease in restricted cash.

Capital Expenditures

During the nine months ended September 30, 2017, we made accrual basis capital expenditures of $1.1 million. At September 30, 2017, we had no material commitments for capital expenditures to be made in 2017 and in future years. We expe ct any capital expenditures made during 2017 will be funded by cash on hand and cash flow from operations.

Abandonment Obligations

We have an agreed cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. Based upon the abandonment study completed in January 2016, the abandonment cost estimate used for this purpose is approximately $61.1 million ($19.0 million net to VAALCO) on an undiscounted basis. The obligation for abandonment of the Gabon offshore facilities is included in the “Asset retirement obligations” line item on our condensed consolidated balance sheet s. Through September 30, 2017, $27.4 million ($8.5 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheet. The next funding

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is expected to be $7.4 million ($2.3 million net to VAALCO) and paid in December 2017; however, future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.

Capital Resources

Credit Facility

Historically, our primary sources of capital have been cash flows from operating activities, borrowings under the credit facility with the IFC and cash balances on hand. The current $11.2 million in principal outstanding under our Amended Term Loan Agreement matures in June 2019, and requires quarterly principal and interest payments on the amounts currently outstanding continuing through June 30, 2019. Interest accrues on the unpaid balance at the per annum rate of LIBOR plus 5.75%. The current portion of the outstanding debt was $7.5 million as of September 30, 2017. Our repayment obligations under this facility require us to pay installments of principal totaling $2.0 million for the remainder of 2017, $6.7 million in 2018 and $2.5 million in 2019. We may make no further borrowings under the terms of the Amended Term Loan Agreement.

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

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

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

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

C ash on Hand

At September 30, 2017, we had unrestricted cash of $18.9 million. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, we enter into project related activities on behalf of our working interest partners. We generally obtain advances from partners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations for the foreseeable future.

We currently sell our crude oil production from Gabon under a term contract that ends in January 2018. Pric ing under the contract is based upon an average of Dated Brent prices in the month of lifting, adjusted for location and market factors. We expect that we will be able to extend or enter into a new contract on comparable terms on or before January 2018.

Liquidity

As discussed above, our revenues, cash flow, profitability, oil and natural gas reserve values and future rates of growth are substantially dependent upon prevailing prices for oil and natural gas. Our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and natural gas prices. After a period of low commodity prices, o il and gas prices have stabilized at levels which are currently adequate to generate cash from operating activities for our continuing operations. We believe that at current prices, cash generated from continuing operations together with cash on hand at September 30, 2017 are adequate to support our operations and cash requirements during the remainder of 2017 and through December 31, 2018.

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

A ll of our proved reserves are related to the Etame Marin block offshore Gabon. The current term for exploitation of the reserves in the Etame Marin block ends in June 2021, and we are focused on extending the license for the block, which, if accompanied by a successful drilling program, could favorably improve our long-term liquidity. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced, which would negatively impact our long-term liquidity. In addition, our short-term and long-term liquidity are impacted by the changes in crude oil prices.

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OFF-BALANCE SHEET ARRANGEMENTS

In connection with the charter of the FPSO (see “— Activities by Asset — Gabon — Offshore-Etame Marin Block”), we, as operator of the Etame Marin block, guaranteed all of the lease payments under the charter through its contract term, which expires in September 2020. At our election, the charter may be extended for two one-year periods beyond September 2020. We obtained guarantees from each of our partners for their respective shares of the payments. Our net share of the charter payment is 31.1%, or approximately $9.7 million per year. Although we believe the need for performance under the charter guarantee is remote, we recorded a liability of $0.5 million and $0.7 million as of September 30, 2017 and December 31, 2016, respectively, representing the guarantee’s fair value. The guarantee of the offshore Gabon FPSO lease has $93.1 million in remaining gross minimum obligations for the total amount of charter payments at September 30, 2017. There have been no other material off-balance sheet arrangements entered into since December 31, 2016.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

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

CRITICAL ACCOUNTING POLICIES

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

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three months ended September 30, 2017 compared to the three months ended September 30, 2016

We reported net loss for the three months ended September 30, 2017 of $0.3 million compared to a net loss of $14.8 million for the sam e period of 2016. The net loss for the three months ended September 30, 2017 is inclusive of the loss from discontinued operations for the same period of $0.2 million. The net loss for the three months ended September 30, 2016 was inclusive of the loss from discontinued operations for the same period of $15.8 million. Further discussion of results by significant line item follows.

Oil and natural gas revenues increased $3.5 million, or approximately 24.2%, during the three months ended September 30, 2017 compared to the same period of 2016. The increase in revenue is attributable to higher realized oil prices, due to increases in the Dated Brent market price as well as higher volumes attributable to the Sojitz acquisition. This was offset in part by a n overall decrease in sales volumes.

The revenue chan ges in the three months ended September 30, 2017 compared to the three months ended September 30, 2016, identified as related to changes in price or volume, are shown in the table below:

﻿

﻿

﻿ |  |  |  |  |  |
(in thousands) |  |  |  |  |
Price |  |  |  |  | $ | 3,730
Volume |  |  |  |  |  | (396)
Other |  |  |  |  |  | 209
﻿ |  |  |  |  | $ | 3,543

﻿

﻿

﻿ |  |  |  |  |  |
﻿ |  | Three Months Ended September 30,
﻿ |  | 2017 |  | 2016
Gabon net oil production (MBbls) |  |  | 341 |  |  | 347
﻿ |  |  |  |  |  |
Gabon net oil sales (MBbls) |  |  | 336 |  |  | 343
U.S. net oil sales (MBbls) |  |  | — |  |  | 1
Net oil sales (MBbls) |  |  | 336 |  |  | 344
Net natural gas sales (MMcf) |  |  | — |  |  | 32
Net oil equivalents (MBOE) |  |  | 336 |  |  | 349
﻿ |  |  |  |  |  |
Average realized oil price ($/Bbl) |  | $ | 51.10 |  | $ | 40.00
Average realized natural gas price ($/Mcf) |  |  | — |  |  | 2.37
Weighted average realized price ($/BOE) |  |  | 51.10 |  |  | 39.61
Average Dated Brent spot* ($/Bbl) |  |  | 52.10 |  |  | 45.80
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

﻿

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Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made three liftings in the third quarters of both 2017 and 2016. Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 42,000 and 39,000 barrels at September 30, 2017 and 2016, respectively.

Production expenses increased $3.2 million, or approximately 44.3%, in the three months ended September 30, 2017 compared to the same period of 2016. Excluding workovers (a component of total production expenses), the increase is primarily the result of: our increased ownership interest in the Etame Marin block of Gabon after the November 2016 Sojitz acquisition, costs related to the planned maintenance turnaround, asset integrity work performed during the planned turnaround and costs associated with certain regulatory requirements in Gabon. Workover costs were minimal in the 2017 period, whereas for the 2016 period we had an adjustment for estimated costs.

Depreciation, depletion and amortization (“DD&A”) costs were not materially different from the three months ended September 30, 2017 compared to the same period of 2016.

General and administrative expenses increased $0.9 million, or approximately 55.1% in the three months ended September 30, 2017 comp ared to the same period of 2016. Personnel costs were higher in 2017 as a result of higher stock-based compensation as 2016 included the benefit related to employee forfeitures. This was offset by lower wages and employee benefits in 2017.

Bad debt expense and othe r was not materially different for the three months ended September 30, 2017 and 2016 related primarily to the allowance for the Value added tax receivable (“VAT”).

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

Interest expense for the three months ended September 30, 2017 and 2016 relates to our “Term Loan” as discussed in Note 5 to the condensed consolidated financial statement.

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

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

L oss from discontinued operations for the three months ended September 30, 2017 and 2016 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The small loss from discontinued operations for the three months ended September 30, 2017 was related to ongoing administration costs. The loss from discontinued operations for the three months ended September 30, 2016 was primarily related to the $15.0 million accrual for the potential payment of the drilling obligations in exploration costs and $0.4 million in ongoing administration costs.

Nine months ended September 30, 2017 compared to the nine months ended September 30, 2016

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

Oil and natural gas revenues increased $15.4 million, or approximately 34.7%, during the nine months ended September 30, 2017 compared to the same period of 2016. A substantial portion of the increase in revenue is related to higher realized oil prices as well as higher volumes attributable to the Sojitz acquisition. This was offset in part by a n overall decrease in sales volumes.

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

﻿

﻿ |  |  |  |  |  |
﻿ |  |  |  |  |
(in thousands) |  |  |  |  |
Price |  |  |  |  | $ | 15,808
Volume |  |  |  |  |  | (832)
Other |  |  |  |  |  | 435
﻿ |  |  |  |  | $ | 15,411

﻿

﻿

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﻿ |  |  |  |  |  |
﻿ |  | Nine Months Ended September 30,
﻿ |  | 2017 |  | 2016
Gabon net oil production (MBbls) |  |  | 1,154 |  |  | 1,181
﻿ |  |  |  |  |  |
﻿ |  |  | 1,143 |  |  | 1,159
U.S. net oil sales (MBbls) |  |  | — |  |  | 2
Net oil sales (MBbls) |  |  | 1,143 |  |  | 1,161
Net natural gas sales (MMcf) |  |  | — |  |  | 99
Net oil equivalents (MBOE) |  |  | 1,143 |  |  | 1,178
﻿ |  |  |  |  |  |
Average realized oil price ($/Bbl) |  | $ | 49.86 |  | $ | 36.03
Average realized natural gas price ($/Mcf) |  |  | — |  |  | 1.85
Weighted average realized price ($/BOE) |  |  | 49.86 |  |  | 35.68
Average Dated Brent spot* ($/Bbl) |  |  | 51.75 |  |  | 41.86
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus crude oil sales do not always coincide with volumes produced in any given quarter. We made nine liftings for the nine months ended September 30, 2017 and 2016. Our share of oil inventory aboard the FPSO, excluding royalty barrels, was approximately 42,000 and 39,000 barrels at September 30, 2017 and 2016, respectively.

Production expenses increased $2.4 million, or approximately 9.3%, in the nine months ended September 30, 2017 compared to the same period of 2016, primarily as a result of our increased ownership in the Etame Marin block of Gabon after the November 2016 Sojitz acquisition, costs related to the planned maintenance turnaround, asset integrity work performed during the planned turnaround, costs associated with certain regulatory requirements in Gabon, custom fees and FPSO cost escalation.

Depreciation, depletion and amortization (“DD&A”) decreased $0.2 million, or approximately 4.3%, in the nine months ended September 30, 2017 compared to the same period of 2016 d ue to the fa vorable impact of depleting our cos ts over a higher reserve base as a result of improvements in estimated reserves identified at December 31, 2016 as well as lower production.

General and administrative expenses increased $0.8 million, or approximately 10.4% in the nine months ended September 30, 2017 compared to the same period of 2016. The increase was primarily related to higher legal fees and accounting and auditing costs offset by lower personnel costs. Personnel costs were lower in 2017 as a result of lower wages and employee benefits offset by higher stock-based compensation as 2016 included the benefit related to employee forfeitures.

Bad debt expense and other for the nine months ended September 30, 2017 and 2016 related primarily to the allowance on the Value added tax (“VAT”) receivable.

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

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

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

﻿

Interest expense for the nine months ended September 30, 2017 and 2016 relates to our “T erm Loan” as discussed in Note 5 to the condensed consolidated financial statement.

Income tax expense increased $2.2 million in the nine months ended September 30, 2017 compared to the same period of 2016. Income tax expense in both periods is primarily attributable to our operations in Gabon and is higher in 2017 than income tax for the comparable 2016 period as a result of higher revenues.

﻿

L oss from discontinued operations for the nine months ended September 30, 2017 is attributable to our Angola segment as discussed further in Note 3 to the condensed consolidated financial statements. The loss from discontinued operations for the 2017 period is related to ongoing administrative costs. For the nine months ended September 30, 2016, we reported loss from discontinued operations primarily as a result of $3.1 million of income tax on financial gains and $15.0 million accrual for the potential payment of drilling obligations offset by $7.6 million of bad debt recovery and $3.2 million of collected default interest.

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ITE M 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

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

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While oil sales a re denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Fran, or XAF), and our VAT receivable in Gabon is also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and ot her factors beyond our control.

I nterest Rate Risk

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

COUNTERPARTY Risk

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

Commodity Price Risk

Our major market risk exposure continues to be the prices received for our oil and natural gas production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for oil and natural gas have been volatile and unpredictable in recent years, and this volatility may continue. Beginning in the third quarter of 2014, the prices for oil and natural gas began a dramatic decline which continued through the first half of 2016. C urrent prices remain significantly l ower than they were in years prior to 2015. Sustained low oil and natural gas prices or a resumption of the decreases in oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms. If oil sales were to remain constant at the most recent quarterly sales volumes of 336 MBbls, a $5 per Bbl decrease in oil price would be expected to cause a $1.7 million decrease per quarter ($6.8 million annualized) in revenues and operating income (loss) and a $1.4 million decrease per quarter ($5.8 million annualized) in net income.

As of September 30, 2017, we had unexpired oil puts with a fair value asset position of $0.1 million. While these crude oil derivative contracts are intended to be an economic hedge, they are not designated as hedges for accounting purposes. The contracts are measured at fair value at the end of each quarter, with changes in value flowing through net income. See Note 7 to the condensed consolidated financial statements for further information about these contracts, their fair value and their impact on our net income.

ITEM 4. CO NTRO LS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

﻿

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

﻿

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

﻿

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DESCRIPTION OF MATERIAL WEAKNESSES

﻿

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

﻿

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

﻿

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

﻿

REMEDIATION EFFORTS TO ADDRESS MATERIAL WEAKNESSES

﻿

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

﻿

| · |  | Hired additional permanent employees for key roles in accounting and finance, which had previous ly been performed by professional consultants.

| · |  | I mprove d the timing of the periodic financial close, reporting process and analysis of results through the use of a detailed f inancial close plan and expanding reporting of financial data to senior management.

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

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

﻿

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

﻿

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

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

﻿

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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ITEM 1A. RISK FACTORS

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

For a discussion of our potential risks and uncertainties, see the information in Item 1A “Risk Factors” in our 2016 Form 10-K. There have been no material changes in our risk factors from those described in our 2016 Form 10-K.

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ITE M 6. EXHIBITS

(a) Exhibits

﻿ |
﻿3.1 | Certificate of Incorporation as amended through May 7, 2014 (filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014, and incorporated herein by reference).
﻿3.2 | Second Amended and Restated Bylaws (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on September 28, 2015, and incorporated herein by reference).
﻿3.3 | First Amendment to the Second Amended and Restated Bylaws (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 23, 2015, and incorporated herein by reference).
﻿31.1(a) | Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
﻿31.2(a) | Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
﻿32.1(b) | Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
﻿32.2(b) | Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a) | XBRL Instance Document.
101.SCH(a) | XBRL Taxonomy Schema Document.
101.CAL(a) | XBRL Calculation Linkbase Document.
101.DEF(a) | XBRL Definition Linkbase Document.
101.LAB(a) | XBRL Label Linkbase Document.
101.PRE(a) | XBRL Presentation Linkbase Document.

(a) Filed herewith

(b) Furnished herewith

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SIGNATURE

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

VAALCO ENERGY, INC.

(Registrant)

﻿ |  |
﻿ By | : | /s/ Philip F. Patman, Jr.
|  | Philip F. Patman, Jr.
|  | Chief Financial Officer (on behalf of the Registrant)

﻿

Dated: November 8, 2017

﻿

﻿

﻿

﻿

﻿

﻿

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