NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND ACCOUNTING
POLICIES
VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO,” or the “Company”)
is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration 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 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, 2017, which includes a summary of the significant accounting policies.
Reclassifications
– Certain reclassifications have been made to prior period amounts to conform to the current period presentation related to the adoption of Accounting Standards Update (“
ASU”) No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”)
. These reclassifications did not affect our consolidated financial results. See Note 2 – New Accounting Standards for further information associated with ASU 2016-18.
Restricted cash and abandonment funding
– Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at
September 30, 2018
and
December 31, 2017
each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long term amounts at
September 30, 2018
and
December 31, 2017
include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 9. We invest restricted and excess cash in readily redeemable money market funds.
We are required under the Exploration and Production Sharing Contract entitled “Etame Marin No. G4-160”, dated as of July 7, 1995, as amended, (the “PSC”) for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was
completed in January 2016.
This cash
funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments. See Note 9 for further discussion.
Asset retirement obligations (“ARO”)
– We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and natural gas properties. We use current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to oil and natural gas properties.
To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate.
Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time.
Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain.
At September 30, 2018, we recorded a downward revision of
$
6.5
million to the ARO liability
as a result of a change in the expected timing of the abandonment costs when the period of exploitation under the Etame Marin PSC was extended to at least September 16, 2028 as discussed further in
Note 7.
Bad debts
–
Quarterly, we evaluate our accounts receivable balances to confirm collectability. When collectability is in doubt, we record an allowance against the accounts receivable, purchases of production 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 owners and the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed 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, 2018
, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF
6.9
billion (XAF
2.3
billion, net to VAALCO). The VAT receivable balance was reduced by
XAF14.1
billion (XAF
4.7
billion, net to VAALCO or
$4.2
million) associated with a signing bonus as part of the Sixth Amendment to the PSC executed on September 17, 2018. See Note 7
to the financial statements
for further discussion. As of
September 30, 2018
, the exchange rate
was XAF
565.129
= $1.00.
For the three and
nine
months ended
September 30, 2018
, we recorded a
net recovery
of
$0.2
million and
$
0.1
million
, respectively,
related to the allowance for bad debt for VAT for which the government of Gabon has not reimbursed us. For the three and
nine
months ended
September 30, 2017
, we recorded an allowance of $
(0.1)
million and $
0.2
million, respectively
.
The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on profit/loss. Such foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.
The following table provides a rollforward of the aggregate allowance:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
|
2017
|
|
2018
|
|
2017
|
|
(in thousands)
|
Allowance for bad debt
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of period
|
$
|
(6,948)
|
|
$
|
(5,874)
|
|
$
|
(7,033)
|
|
$
|
(5,211)
|
Bad debt recovery (charge)
|
|
159
|
|
|
49
|
|
|
68
|
|
|
(232)
|
Reclassification to leasehold costs related to signing bonus
|
|
4,197
|
|
|
—
|
|
|
4,197
|
|
|
—
|
Reclassification related to Sojitz acquisition
|
|
—
|
|
|
(694)
|
|
|
—
|
|
|
(694)
|
Foreign currency gain (loss)
|
|
11
|
|
|
(201)
|
|
|
187
|
|
|
(583)
|
Balance at end of period
|
$
|
(2,581)
|
|
$
|
(6,720)
|
|
$
|
(2,581)
|
|
$
|
(6,720)
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
– Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in our internally developed present value of future cash flows model that underlies the fair-value measurement).
Fair value of financial instruments
– Our current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, liabilities for stock appreciation rights (“SARs”) and a guarantee. Derivative assets and liabilities are measured and reported at fair value using level 2 inputs each period with changes in fair value recognized in net income.
SARs
liabilities are measured and reported at fair value using level 3 inputs each period with changes in fair value recognized in net income.
With respect to our other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. There were
no
transfers between levels during the three and
nine
months ended September 30, 2018 or 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2018
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
(in thousands)
|
Recurring
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
SARs liability
|
|
$
|
—
|
|
$
|
—
|
|
$
|
3,111
|
|
$
|
3,111
|
Derivative liability swaps
|
|
|
—
|
|
|
2,064
|
|
|
—
|
|
|
2,064
|
|
|
$
|
—
|
|
$
|
2,064
|
|
$
|
3,111
|
|
$
|
5,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
(in thousands)
|
Recurring
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
SARs liability
|
|
$
|
—
|
|
$
|
—
|
|
$
|
146
|
|
$
|
146
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
146
|
|
$
|
146
|
As of September 30, 2018, the fair value of our SARs liability awards and derivative liability swaps of $
2.1
million and $
2.1
million
, respectively,
were included accrued liabilities. As of September 30, 2018, the fair value of our long-term SARs of $
1.0
million were include in other long-term liabilities. As of December 31, 2017, the fair value of our SARs liability awards were included in accrued liabilities.
Foreign currency transactions –
The U.S. dollar is the functional currency of our foreign operating subsidiaries. Gains and losses on foreign currency transactions are included in income. Within the condensed consolidated statements of operations line item “Other income (expense)—Other, net,” we
recognized losses on foreign
currency transactions of $
0.0
thousand and $
0.1
million during the three and
nine
months ended
September 30, 2018
, respectively. Within the condensed consolidated statements of operations line item “Other income (expense)—Other, net,” we recognized gains on foreign currency transactions of $
0.2
million and $
0.5
million during the three and
nine
months ended
September 30, 2017
, respectively.
2. NEW ACCOUNTING STANDARDS
Adopted
In March 2018, the
Financial Accounting Standards Board (“FASB”)
issued ASU 2018-05, “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118” (“ASU 2018-05”). ASU 2018-05 adds the
Securities and Exchange Commission’s (“SEC”)
guidance released on December 22, 2017 in
Staff Accounting Bulletin number 118 “(SAB 118”)
regarding the Tax Reform Act to the FASB Accounting Standards Codification. The Company adopted ASU 2018-05 in March 2018. The income tax effects recorded in the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2017 as well as for the three and
nine
months ended
September 30, 2018
as a result of the Tax Reform Act are provisional in accordance with ASU 2018-05 as discussed further in Note 12.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Beginning January 1, 2018, we adopted ASU No. 2014-09, and the related additional guidance provided under ASU No. 2016-10, 2016-11 and 2016-12 (together with ASU 2014-09, “Revenue Recognition ASU”). This new standard replaced most existing revenue recognition guidance in U.S. GAAP. The core principle of the Revenue Recognition ASU requires companies to reevaluate when revenue is recorded on a transaction based upon newly defined criteria, either at a point in time or over time as goods or services are delivered. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and estimates, and changes in those estimates. We adopted the Revenue Recognition ASU via the modified retrospective transition method, taking advantage of the allowed practical expedient that states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. This standard applies to revenues from contracts with customers. In addition, we recognize other items from carried interest recoupment and royalties paid which are reported in revenues but are not considered to be revenues from contracts with customers. For revenues from contracts with customers, adoption of this standard did not result in a change in the timing or amount of revenue recognized, and therefore the adoption of this standard did not have a material impact on our financial position, results of operations, debt covenants or business practices. The adoption did result in expanded disclosures related to the nature of our sales contracts and other matters related to revenues and the accounting for revenues, which are reflected in Note 6. In addition, we implemented new internal controls and procedures associated with revenue recognition and disclosures related to revenues.
In November 2016, the FASB issued ASU No. 2016-18, which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents.
Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted ASU 2016-18 beginning January 1, 2018 with retroactive application to prior periods. Due to the nature of this accounting standards update, this had an impact on items reported in our statements of cash flows and related disclosures, but no impact on our financial position and results of operations.
The following tables provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows:
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
December 31, 2017
|
|
|
(in thousands)
|
Cash and cash equivalents
|
|
$
|
33,715
|
|
$
|
19,669
|
Restricted cash - current
|
|
|
1,025
|
|
|
842
|
Restricted cash - non-current
|
|
|
918
|
|
|
967
|
Abandonment funding
|
|
|
10,808
|
|
|
10,808
|
Total cash, cash equivalents and restricted cash shown in the condensed consolidated statements of cash flows
|
|
$
|
46,466
|
|
$
|
32,286
|
|
|
|
|
|
|
|
In May 2017, the FASB issued ASU No. 2017-09, Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting (“ASU 2017-09”) to clarify when to account for a change to the terms or conditions of a share-based payment award as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments in ASU 2017-09 are effective for all entities for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to an award modified on or after the adoption date. The adoption of ASU 2017-09 has not had a material impact on our
financial position, results of operations, cash flows and related disclosures
.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The purpose of the amendment is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public entities, the amendments in ASU 2017-01 are effective for interim and annual reporting periods beginning after December 15, 2017. The amendments in this update are to be applied prospectively to acquisitions and disposals completed on or after the effective date, with no disclosures required at transition. The adoption of ASU 2017-01 has not had a material impact on our
financial position, results of operations, cash flows and related disclosures
.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) related to how certain cash receipts and payments are presented and classified in the statement of cash flows. These cash flow issues include debt prepayment or extinguishment costs, settlement of zero-coupon debt, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of ASU 2016-15 has not had a material impact on our
financial position, results of operations, cash flows and related disclosures
.
Not yet adopted
In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in ASC 350, Intangibles - Goodwill and Other
,
in making the
determin
ation as to
which implementation costs
are to be
capitalize
d
as assets
and which costs are to be
expense
d
as incurred. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted
,
and an entity can elect to apply the new guidance on a prospective or retrospective basis. The Company is currently evaluating the impact of adopting this guidance.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). This ASU modifies the disclosure requirements for fair value measurements. ASU
2018-13
removes the requirement to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements. ASU 2018-13 requires disclosure of changes in unrealized gains and losses for the period included in other comprehensive income (loss) for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For all entities, ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. We are currently evaluating the effect that this guidance will have on our
consolidated financial statements and disclosures.
In July 2018, the FASB issued ASU 2018-09, Codification Improvements (“ASU 2018-09”). ASU 2018-09 amends a variety of topics in the FASB’s Accounting Standards Codification. The transition and effective date of the guidance are based on the facts and circumstances of each amendment. Some of the amendments in ASU 2018-09 do not require transition guidance and were effective
upon issuance of ASU 2018-09. However, many of the amendments include transition guidance with effective dates for annual periods beginning after December 15, 2018.
We
do not believe the adoption of ASU 2018-09 will have a material impact on
our
consolidated financial statements and disclosures.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including our trade and joint venture owners receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date which is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model which increases the allowance when losses are probable. This change is effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We are currently evaluating the provisions of ASU 2016-13 and are assessing its potential impact on our
financial position, results of operations, cash flows and related disclosures
.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which amends the accounting standards for leases. This accounting standard w
as further clarified by ASU 2018-10,
Codification Improvements
to Topic 842
and ASU 2018-11, Leases (Topic 842): Targeted Improvements, both of which were issued in July 2018. 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. The amendments are e
ffective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early application permitted. In transition, lessees and lessors may use either a prospective approach in which they recognize and measure leases at the date of adoption and recognize a cumulative effect adjustment to the opening balance of retained earnings or they may use a modified retrospective approach in which leases are recognized and measured at the beginning of the earliest period presented. We intend to use the prospective approach when we adopt the new standard.
Leases with terms greater than 12 months, which are currently treated as operating leases, will be capitalized. The adoption of this standard will result in the recording of a right of use asset related to certain of our operating leases with a corresponding lease liability. This will result in a
n
increase in total assets and liabilities and a decrease in working capital.
In connection with our implementation plan, we
have reviewed
our lease contracts and have been evaluating other contracts to identify embedded leases to determine the appropriate accounting treatment. We are revising our processes and procedures as well as the internal controls related to the proper accounting for leases under the new standard
.
3. DISPOSITIONS
Discontinued Operations - Angola
In November 2006, we
signed a production sharing contract for Block 5 offshore Angola (“PSA”).
Our
working interest is
40%
, and we carry Sonangol P&P, for
10%
of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016,
we
notified the national concessionaire, Sonangol E.P., that we were withdrawing from the PSA. Further to the decision to withdraw from Angola,
we
have taken actions to close our office in Angola and reduce future activities in Angola. As a result of this strategic shift, we classified all the related assets and liabilities as those of discontinued operations in the 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, 2018
and
December 31, 2017
and its results of operations for the three and
nine
months ended
September 30, 2018
and 2017.
Summarized Results of Discontinued Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(in thousands)
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense
|
$
|
23
|
|
$
|
174
|
|
$
|
387
|
|
$
|
512
|
Total operating costs and expenses
|
|
23
|
|
|
174
|
|
|
387
|
|
|
512
|
Operating loss
|
|
(23)
|
|
|
(174)
|
|
|
(387)
|
|
|
(512)
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
2
|
|
|
—
|
|
|
(29)
|
|
|
(3)
|
Total other expense
|
|
2
|
|
|
—
|
|
|
(29)
|
|
|
(3)
|
Loss from discontinued operations before income taxes
|
|
(21)
|
|
|
(174)
|
|
|
(416)
|
|
|
(515)
|
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
Loss from discontinued operations
|
$
|
(21)
|
|
$
|
(174)
|
|
$
|
(416)
|
|
$
|
(518)
|
Assets and Liabilities Attributable to Discontinued Operations
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
December 31, 2017
|
|
|
(in thousands)
|
ASSETS
|
|
|
|
|
|
|
Accounts with joint venture owners
|
|
$
|
3,222
|
|
$
|
2,836
|
Total current assets
|
|
|
3,222
|
|
|
2,836
|
Total assets
|
|
$
|
3,222
|
|
$
|
2,836
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
32
|
|
$
|
158
|
Accrued liabilities and other
|
|
|
15,159
|
|
|
15,189
|
Total current liabilities
|
|
|
15,191
|
|
|
15,347
|
Total liabilities
|
|
$
|
15,191
|
|
$
|
15,347
|
Drilling Obligation
Under the PSA, we and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases identified in the PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of
$10.0
million for each of the three exploration wells for which a drilling obligation remains unfulfilled under the terms of the PSA, of which our participating interest share would be
$5.0
million per well. We have reflected an accrual of
$15.0
million for a potential payment as of
September 30, 2018
and December 31, 2017, respectively, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA. We are currently engaged in discussions with recently appointed representatives from Sonangol E.P. regarding a possible resolution to this potential payment.
4
. SEGMENT INFORMATION
Our operations are based in Gabon and Equatorial Guinea.
Each of our
two
reportable operating segments is organized and managed based upon geographic location. Our Chief Executive Officer, who is the chief operating decision maker, and 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, 2018
and
2017
as well as long-lived assets and segment assets at
September 30, 2018
and
December 31, 2017
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
25,265
|
|
$
|
—
|
|
$
|
1
|
|
$
|
25,266
|
Operating income (loss)
|
|
|
19,826
|
|
|
(159)
|
|
|
(2,347)
|
|
|
17,320
|
Other, net
|
|
|
3
|
|
|
—
|
|
|
(1,032)
|
|
|
(1,029)
|
Income tax expense (benefit)
|
|
|
(42,141)
|
|
|
—
|
|
|
(20,083)
|
|
|
(62,224)
|
Additions to property and equipment - accrual
|
|
|
17,983
|
|
|
—
|
|
|
3
|
|
|
17,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
77,333
|
|
$
|
—
|
|
$
|
4
|
|
$
|
77,337
|
Operating income (loss)
|
|
|
45,670
|
|
|
(274)
|
|
|
(9,315)
|
|
|
36,081
|
Other, net
|
|
|
(127)
|
|
|
(3)
|
|
|
(2,054)
|
|
|
(2,184)
|
Income tax expense (benefit)
|
|
|
(34,517)
|
|
|
—
|
|
|
(20,083)
|
|
|
(54,600)
|
Additions to property and equipment - accrual
|
|
|
18,938
|
|
|
—
|
|
|
17
|
|
|
18,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
18,162
|
|
$
|
—
|
|
$
|
16
|
|
$
|
18,178
|
Operating income (loss)
|
|
|
6,067
|
|
|
(44)
|
|
|
(2,302)
|
|
|
3,721
|
Other, net
|
|
|
142
|
|
|
4
|
|
|
(939)
|
|
|
(793)
|
Income tax expense (benefit)
|
|
|
2,749
|
|
|
—
|
|
|
—
|
|
|
2,749
|
Additions to property and equipment - accrual
|
|
|
237
|
|
|
—
|
|
|
60
|
|
|
297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
59,823
|
|
$
|
—
|
|
$
|
46
|
|
$
|
59,869
|
Operating income (loss)
|
|
|
25,117
|
|
|
(97)
|
|
|
(7,564)
|
|
|
17,456
|
Other, net
|
|
|
441
|
|
|
13
|
|
|
(1,025)
|
|
|
(571)
|
Income tax expense (benefit)
|
|
|
9,039
|
|
|
—
|
|
|
—
|
|
|
9,039
|
Additions to property and equipment - accrual
|
|
|
1,051
|
|
|
—
|
|
|
60
|
|
|
1,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
Corporate and Other
|
|
Total
|
Long-lived assets from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2018
|
|
$
|
24,526
|
|
$
|
10,000
|
|
$
|
405
|
|
$
|
34,931
|
Balance at December 31, 2017
|
|
|
12,638
|
|
|
10,000
|
|
|
583
|
|
|
23,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2018
|
|
$
|
104,574
|
|
$
|
10,088
|
|
$
|
44,477
|
|
$
|
159,139
|
Balance at December 31, 2017
|
|
|
63,122
|
|
|
10,095
|
|
|
3,580
|
|
|
76,797
|
Information about our most significant customers
For the period
from August of 2015 through September
2018, we sold our crude oil production from Gabon under a term contract with Glencore Energy UK Ltd. (“Glencore”) with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The contract with Glencore ends in January 2019. Sales of oil to Glencore were approximately
100%
of total revenues for the three and
nine
months ended
September 30, 2018
and 2017.
We expect to be able to enter into a new contract with Glencore or other third party on competitive terms
prior to the expiration of the current contract
.
5
.
EARNINGS PER SHARE
Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, we assume that restricted stock is outstanding on the date of vesting, and we assume the issuance of shares from
the exercise of stock options using the treasury stock method.
A reconciliation of reported net income (loss) to net income (loss) used in calculating EPS as well as a reconciliation from basic to diluted shares follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
|
|
|
(in thousands)
|
Net income (loss) (numerator):
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
78,626
|
|
$
|
(148)
|
|
$
|
88,224
|
|
$
|
6,738
|
Less: Income (loss) from continuing operations attributable to unvested shares
|
|
|
(766)
|
|
|
—
|
|
|
(820)
|
|
|
(39)
|
Numerator for basic
|
|
|
77,860
|
|
|
(148)
|
|
|
87,404
|
|
|
6,699
|
Less: Income (loss) from continuing operations attributable to unvested shares
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
Numerator for dilutive
|
|
$
|
77,860
|
|
$
|
(148)
|
|
$
|
87,404
|
|
$
|
6,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations
|
|
$
|
(21)
|
|
$
|
(174)
|
|
$
|
(416)
|
|
$
|
(518)
|
Less: Loss from discontinued operations attributable to unvested shares
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
3
|
Numerator for basic
|
|
|
(21)
|
|
|
(174)
|
|
|
(412)
|
|
|
(515)
|
Less: Loss from discontinued operations attributable to unvested shares
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
Numerator for dilutive
|
|
$
|
(21)
|
|
$
|
(174)
|
|
$
|
(412)
|
|
$
|
(515)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
78,605
|
|
$
|
(322)
|
|
$
|
87,808
|
|
$
|
6,220
|
Less: Net income (loss) attributable to unvested shares
|
|
|
(766)
|
|
|
—
|
|
|
(816)
|
|
|
(36)
|
Numerator for basic
|
|
|
77,839
|
|
|
(322)
|
|
|
86,992
|
|
|
6,184
|
Less: Net income (loss) attributable to unvested shares
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
Numerator for dilutive
|
|
$
|
77,839
|
|
$
|
(322)
|
|
$
|
86,992
|
|
$
|
6,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares (denominator):
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
59,481
|
|
|
58,817
|
|
|
59,147
|
|
|
58,682
|
Effect of dilutive securities
|
|
|
1,337
|
|
|
—
|
|
|
699
|
|
|
4
|
Diluted weighted average shares outstanding
|
|
|
60,818
|
|
|
58,817
|
|
|
59,846
|
|
|
58,686
|
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive
|
|
|
244
|
|
|
3,007
|
|
|
1,223
|
|
|
2,799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6. REVENUE
Substantially all of our revenues are attributable to our Gabon operations. Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPA”). These contracts have been and will be renewed or replaced from time to time either with the current buyer or another buyer. Since August 2015, the COSPA has been executed with the same buyer, initially for a
one
-year period, with amendments to extend the period through January 31, 2018. Beginning February 1, 2018 through January 31, 2019, a new COSPA was entered into with this same customer.
The COSPA with the third party is renegotiated near the end of the contract term and may be entered into with a different buyer or the same buyer going forward. Except for internal costs (which are expensed as incurred), there are no upfront costs associated with obtaining a new COSPA.
Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take
one
to
two
days to complete. The intervals between liftings are generally
30
days; however, changes in the timing of liftings will impact the number of liftings which occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations.
W
e have utilized the practical expedient in ASC Topic 606-10-50-14(a) which states
that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
Previously, we followed the sales method of accounting to account for crude oil production imbalances. In conjunction with our adoption of Accounting Standards Codification (“ASC”) Topic 606 on January 1, 2018, we will continue to account for production imbalances as a reduction in reserves. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property, and we would recognize a liability if our existing proved reserves were not adequate to cover an imbalance.
For each lifting completed under the COSPA, payment is made by the customer in U.S. Dollars by electronic transfer thirty days after the date of the bill of lading. For each lifting of oil, the price is determined based on a formula using published Dated Brent prices as well as market differentials plus a fixed contract differential.
Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, we deem this situation to be characterized as a fixed price situation.
In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. This contract is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. The terms of the PSC includes provisions for payments to the government of Gabon for: royalties based on
13%
of production at the published price and a shared portion of “Profit Oil” determined based on daily production rates, as well as a gross carried working interest of
7.5%
(i
ncreasing to
10%
beginning June 20, 2026) for all costs
.
For both royalties and Profit Oil, the PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments.
To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment. Payments for royalties are reflected as a reduction in revenues from customers. Should the government elect to take the production attributable to its royalty in-kind, we would no longer have sales to customers associated with production assigned to royalties.
With respect to the government’s share of Profit Oil, the PSC provides that corporate income tax is satisfied through the payment of profit oil. In the condensed consolidated statements of operations, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. Prior to February 1, 2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February 1, 2018, these are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the PSC is reflected as revenue with an offsetting amount reported in current income tax expense. Payments of the income tax expense will be reported in the period in which the government takes its Profit Oil in-kind, i.e. the period in which it lifts the crude oil. The in-kind payment related to the September lifting was $9.4 million. As of
September 30, 2018
, the foreign taxes payable attributable to this obligation is
$1.8
million.
Certain amounts associated with the carried interest in the Etame Marin block discussed above are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs which would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues.
The following table presents revenues from contracts with customers as well as revenues associated with the obligations under the PSC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(in thousands)
|
Revenue from customer contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Glencore oil revenue
|
|
$
|
18,931
|
|
$
|
17,757
|
|
$
|
74,587
|
|
$
|
57,913
|
Gabonese government share of Profit Oil
|
|
|
—
|
|
|
2,749
|
|
|
2,193
|
|
|
9,039
|
U.S. oil and natural gas revenue
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
46
|
Other items reported in revenue not associated with customer contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gabonese government share of Profit Oil taken in-kind
|
|
|
9,385
|
|
|
—
|
|
|
9,385
|
|
|
—
|
Carried interest recoupment
|
|
|
573
|
|
|
431
|
|
|
1,929
|
|
|
1,818
|
Royalties
|
|
|
(3,623)
|
|
|
(2,775)
|
|
|
(10,757)
|
|
|
(8,947)
|
Total revenue, net
|
|
$
|
25,266
|
|
$
|
18,178
|
|
$
|
77,337
|
|
$
|
59,869
|
7
. OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT
Extension of Term of Etame
Marin Block
PSC
On September 25, 2018, VAALCO together with the other joint owners in the Etame Marin block (the “consortium”) received an implementing Presidential Decree from the government of Gabon authorizing a Sixth Amendment (the “PSC Extension”) to the Etame Marin block PSC. Our subsidiary, VAALCO Gabon S.A., has a
33.575%
“Participating Interest” (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.
The PSC Extension extends the term for each of the
three
exploitation areas in the Etame Marin block for a period of
ten
years with effect from September 17, 2018, the effective date of the PSC Extension. Prior to the PSC Extension, the exploitation periods for the three exploitation areas in the Etame Marin block would expire beginning in June 2021. The PSC Extension also grants the consortium the right for
two
additional extension periods of
five
years each. The PSC Extension further allows the consortium to explore the potential for resources within the area of each Exclusive Exploitation Authorization as defined in the PSC Extension.
In consideration for the PSC Extension, the consortium agreed to a signing bonus of
$65.0
million (
$21.8
million net to VAALCO) payable to the government of Gabon (the “signing bonus”). The consortium paid
$35.0
million (
$11.8
million net to VAALCO) in cash on September 26, 2018 and paid
$25.0
million (
$8.4
million net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the consortium as of the effective date. An additional
$5.0
million (
$1.7
million net to VAALCO) is to be paid in cash by the consortium following the end of the drilling activities described below. We have accrued our $1.7 million share of this remaining payment as of September 30, 2018. The amount paid through a reduction in VAT has been recorded
at
$4.2
million which represents
the book value of the receivable, net of the valuation allowance. We have allocated our share of the signing bonus between proved and unproved leasehold costs
using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas resulting in
$10.9
million being attributed to proved leasehold costs and
$6.7
million attributed to unproved
leasehold costs.
Under the PSC Extension, by September 16, 2020, the consortium is required to drill
two
wells and
two
appraisal well bores
. We estimate the cost of these wells will be
approximately
$61.2
million (
$20.5
million, net to VAALCO). If the wells are not drilled, then the consortium must pay the difference between the amounts spent on any wells that were drilled and the estimated costs of the wells as set forth in the Work Program and Budget as approved by the government of Gabon. The consortium is planning to drill these wells in the second and third quarters of 2019. The consortium is also required to complete two technical
studies by September 16, 2020 at an estimated cost of
$1.3
million gross (
$0.4
million net to VAALCO).
Prior to the PSC Extension, the consortium was entitled to take up to
70%
of production remaining after the
13%
royalty (“Cost Recovery Percentage”) to recover its costs so long as there are amounts remaining in the Cost Account. Under the PSC Extension, the Cost Recovery Percentage is increased to
80%
for the
ten
-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%.
Prior to the PSC Extension, the PSC provided for the
government
of Gabon to take a
7.5%
gross
working interest carried by the consortium. The
government
of Gabon transferred this interest to a
third party. Pursuant to the PSC Extension, the government of Gabon will acquire from the consortium an additional
2.5%
gross working interest carried by the consortium effective June 20, 2026. VAALCO’s share of this interest to be transferred to the government of Gabon is
0.8%
.
Depletion and Impairment
Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are calculated on a field basis under the unit-of-production method based upon estimates of total proved reserves.
Support equipment and leasehold improvements related to oil and natural gas producing activities, as well as property, plant and equipment unrelated to oil and natural gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically
five
years for office and miscellaneous equipment and
five
to
seven
years for leasehold improvements.
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 2018 that would cause us to believe the value of
oil and natural gas producing properties
should be impaired. While there were capital expenditures during the quarter related to the signing
bonus for the PSC Extension, the value of the extended exploitation period and the
increase
in
the
Cost Recovery
Percentage
exceeded the consideration given. Other factors considered included the fact that the future strip prices for the third quarter of 2018 modestly increased from the second quarter of 2018, and there were no indicators that downward adjustments were needed to the 2017 year-end reserve report.
With respect to current reserve estimates, we estimate that reserves have increased as a result of the PSC extension
and the
wells planned for 2019.
There was no triggering event in the third quarter of 2017 that caused us to believe the value of
oil and natural gas producing properties
should be impaired.
During the third quarter of 2017, prices remained stable 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 all of our fields.
8. DEBT
On May 22, 2018, we terminated an amended term loan agreement
we had with the
International Finance Corporation (the “IFC”) (the “Amended Term Loan Agreement”)
by prepaying the outstanding principal and accrued interest.
We did
not
incur any termination or prepayment penalties as a result of the termination of the Amended Term Loan Agreement.
We entered into the Amended Term Loan Agreement o
n June 29, 2016 through the execution of a Supplemental Agreement with the IFC which, among other things, amended and restated our existing loan agreement to convert
$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 Term Loan Agreement was
secured by the assets of our Gabon subsidiary,
VAALCO Gabon S.A. and was guaranteed by VAALCO as the parent company
. The Amended Term Loan Agreement provided for quarterly principal and interest payments on the amounts outstanding, with interest accruing at a rate of LIBOR plus
5.75%
.
The Amended Term Loan Agreement also provided for an additional borrowing of up to
$5.0
million, which could be requested in a single draw, subject to the IFC’s approval, through March 15, 2017. On March 14, 2017, we borrowed
$4.2
million under this provision of the Amended Term Loan Agreement. The additional borrowings were to be repaid in
five
quarterly principal installments commencing June 30, 2017, together with interest accruing at LIBOR plus 5.75%.
Interest
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 income (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,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(in thousands)
|
Interest expense related to debt, including commitment fees
|
$
|
—
|
|
$
|
(222)
|
|
$
|
(257)
|
|
$
|
(796)
|
Deferred finance cost amortization
|
|
—
|
|
|
(92)
|
|
|
(191)
|
|
|
(293)
|
Other interest expen
se not related to debt
|
|
—
|
|
|
(16)
|
|
|
33
|
|
|
(23)
|
Interest income
|
|
111
|
|
|
3
|
|
|
142
|
|
|
4
|
Interest income (expense), net
|
$
|
111
|
|
$
|
(327)
|
|
$
|
(273)
|
|
$
|
(1,108)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average effective interest rate, excluding commitment fees
|
|
|
|
|
6.54%
|
|
|
7.09%
|
|
|
6.87%
|
9
. COMMITMENTS AND CONTINGENCIES
Drilling
and other
commitment
s
In connection with the PSC
Extension
, the Etame
Marin
block joint owners
are committed to drill
two
wells and
two
appraisal well
bore
s by September 1
6
, 2020.
The estimated cost for these
wells is approximately
$
6
1.
2
million (
$
20.5
million, net to VAALCO).
In
addition to the drilling commitment, the Etame
Marin
block joint owners
are required to pay
$
5.0
million (
$1.7
million
,
net to VAALCO)
in
cash to the
government
of Gabon following the end of the drilling activities for the two wells
.
A
s the payment is not contingent on the success of these wells and at least $5.0 million
would be paid if no wells are drilled, we have accrued a liability for our net $1.7 million share as of September 30, 2018
.
The joint owners are also obligated to perform two technical studies estimated to
cost
$1.3
million (
$
0
.4
million, net to VAALCO).
The costs related to these studies will be recognized in future periods when the studies are performed.
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, 2018
,
$34.8
million (
$10.8
million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” on our condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.
FPSO charter
In connection with the charter of the FPSO, 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 the joint venture owners for their respective shares of the payments. Our net share of the charter payment is
31.1%
, or approximately
$9.7
million per year. Although we believe the need for performance under the charter guarantee is remote, we recorded
a liability of $
0.4
million as o
f
September 30, 2018
and
$0.5
million as of December 31, 2017 representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO lease has $
61.8
million and $
85.2
million in remaining gross minimum obligations as of
September 30, 2018
and
December 31, 2017
, respectively.
Regulatory and Joint Interest Audits
We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements.
In 2016, the government of Gabon conducted an audit of our operations in Gabon, covering the years 2013 through 2014. We received the findings from this audit and responded to the audit findings in January 2017. Since providing our response, there have been changes in the Gabonese officials responsible for the audit. We are currently working with the newly appointed representatives to resolve the audit findings. We do not anticipate that the ultimate outcome of this audit will have a material effect on our financial condition, results of operations or liquidity.
In 2017, the government of Gabon conducted a tax audit of our Gabon subsidiary covering the years 2013 through 2016, and in December 2017, we received a report on their findings. In April 2018, we reached a final settlement of the audit resulting in a payment for taxes of
$0.2
million and penalties of
$0.2
million, net to VAALCO. At December 31, 2017, we had an accrual of
$0.5
million, net to VAALCO, for the estimated additional taxes along with penalties in the “Accrued liabilities and other” line item of our consolidated balance sheets.
At
September 30, 2018
and December 31, 2017, we had accrued
$1.3
million
, net to VAALCO, in “Accrued liabilities and other” on our condensed consolidated balance sheets for potential fees which may result from a customs audit.
10. DERIVATIVES AND FAIR VALUE
We use derivative financial instruments to achieve a more predictable cash flow from oil production by reducing our exposure to price fluctuations.
Commodity Swaps -
In June 2018, we entered into
commodity
swaps at a Dated Brent weighted average of
$74
per barrel for the period from and including June 2018 through June 2019 for a quantity of approximately
400,000
barrels. If a liability position exceeds
$10.0
million, we would be required to provide a bank letter of credit or deposit cash into an escrow account for the amount by which the liability exceeds $10.0 million. These swaps settle on a monthly basis. At
September 30, 2018
, our unexpired
commodity
swaps were for an underlying quantity of
285,000
barrels and had a fair value liability position
of
$2.1
million
reflected in “Accrued liabilities and other” line of our condensed consolidated balance sheet.
Put options
-
During 2016, we executed crude oil put contracts as market conditions allowed in order to economically hedge anticipated 2016 and 2017 cash flows from crude oil producing activities. At December 31, 2017, our crude oil put contracts expired.
While these commodity swaps and crude oil puts are intended to be an economic hedge to mitigate the impact of a decline in oil prices, we have not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. We do not enter into derivative instruments for speculative or trading proposes.
We record balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in fair value of derivative instruments and cash
settlements on commodity derivatives are presented in the “Other, net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
Derivative Item
|
|
Statement of Operations Line
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
(in thousands)
|
Crude oil puts
|
|
Other, net
|
|
|
—
|
|
|
(921)
|
|
$
|
—
|
|
$
|
(971)
|
Crude oil swaps
|
|
Other, net
|
|
|
(1,026)
|
|
|
—
|
|
|
(2,036)
|
|
|
—
|
11
.
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 stock appreciation rights from the 2014 Long-Term Incentive Plan (“2014 Plan”). At
September 30, 2018
,
1,112,527
shares were authorized for future grants under the 2014 plan.
For each stock option granted, the number of authorized shares under the 2014 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2014 Plan will be reduced by twice the number of restricted shares. We have no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.
We record compensation expense related to stock-based compensation as general and administrative expense. For the three months ended
September 30, 2018
and 2017, stock-based compensation was $
1.1
million and $
0.2
million, respectively, related to the issuance of stock options, restricted stock and S
ARs
. For the
nine
months ended
September 30, 2018
and
2017
, stock-based compensation was $
3.8
million and $
0.9
million, respectively, related to the issuance of stock options, restricted stock and SARs. Because we do not pay significant United States federal income taxes,
no
amounts were recorded for future tax benefits.
Stock options
Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of our Board of Directors, which in the past has been a
five
-
year life, with the options vesting over a service period of up to
five
years. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. There were
$
0.5
million and
$38
thousand in cash proceeds from the exercise of stock options in the
nine
months ended
September 30, 2018
and 2017, respectively. During the
nine
months ended
September 30, 2018
, options for
494,941
shares were granted to employees; these options vest over a
three
-year period, vesting in three equal parts on the first, second and third anniversaries after the date of grant and have an exercise price of
$0.86
per share. During the
nine
months ended
September 30, 2018
, options for
175,644
shares were granted to directors; these options vested immediately on the date of grant and have an exercise price of
$1.60
per share.
Stock option activity for the
nine
months ended
September 30, 2018
is provided below:
|
|
|
|
|
|
|
|
Number of Shares Underlying Options
|
|
Weighted Average Exercise Price Per Share
|
|
|
(in thousands)
|
|
|
|
Outstanding at January 1, 2018
|
|
2,597
|
|
$
|
1.77
|
Granted
|
|
671
|
|
|
1.05
|
Exercised
|
|
(528)
|
|
|
1.02
|
Forfeited/expired
|
|
(139)
|
|
|
5.60
|
Outstanding at September 30, 2018
|
|
2,601
|
|
|
1.54
|
Exercisable at September 30, 2018
|
|
1,498
|
|
|
1.98
|
Restricted shares
Restricted stock granted to employees will vest over a period determined by the Compensation Committee which is generally a
three
-
year period, vesting in three equal parts on the first three anniversaries following the date of the grant. Share grants to directors vest immediately and are not restricted. During the
nine
months ended
September 30, 2018
, the
Company
issued
323,474
shares
of service based restricted stock to employees with a grant date fair value of
$0.86
per share. The vesting of these shares is dependent upon the employee’s continued service with the Company. The shares will vest in three equal parts over three years
from the date of the grant
.
The following is a summary of activity in unvested restricted stock in the
nine
months ended
September 30, 2018
. During
the
nine
months ended
September 30, 2018
, restricted stock for
75,000
shares were granted to directors; these shares vested immediately on the date of grant and had a grant date fair value of
$1.60
per share.
|
|
|
|
|
|
|
|
Restricted Stock
|
|
Weighted Average Grant Price
|
|
|
(in thousands)
|
|
|
|
Non-vested shares outstanding at January 1, 2018
|
|
340
|
|
$
|
1.10
|
Awards granted
|
|
398
|
|
|
1.00
|
Awards vested
|
|
(155)
|
|
|
1.07
|
Awards forfeited
|
|
—
|
|
|
—
|
Non-vested shares outstanding at September 30, 2018
|
|
583
|
|
|
1.04
|
During the three and
nine
months ended
September 30, 2018
,
8
,
117
shares
were added to treasury as a result of tax withholding on vestings of restricted shares. During the three and
nine
months ended
September 30, 2017
,
9,117
shares were added to treasury as a result of tax withholding on vestings of restricted shares.
Stock appreciation rights
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, 2018
,
2,373,411
SARs were granted to employees which vest over a
three
-year period with a life of
5
years and have a
$0.86
SAR price per share specified in a SAR award on the date of grant. With respect to SARs granted in 2017, one-third of the SARs are to vest on or after the first anniversary of the grant date at such time when the market price per share of our common stock exceeds
$1.30
; one-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds
$1.50
; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds
$1.75
.
The vesting requirements for two-thirds of the SARs
granted
in 2017 have been met.
SAR activity for the
nine
months ended
September 30, 2018
is provided below:
|
|
|
|
|
|
|
|
Number of Shares Underlying SARs
|
|
Weighted Average Exercise Price Per Share
|
|
|
(in thousands)
|
|
|
|
Outstanding at January 1, 2018
|
|
1,076
|
|
$
|
1.17
|
Granted
|
|
2,373
|
|
|
0.86
|
Exercised
|
|
(47)
|
|
|
1.20
|
Forfeited/expired
|
|
(33)
|
|
|
0.86
|
Outstanding at September 30, 2018
|
|
3,369
|
|
|
0.95
|
Exercisable at September 30, 2018
|
|
371
|
|
|
1.15
|
12. 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.
On December 22, 2017, the United States government enacted the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act includes significant changes to the U.S. income tax system including but not limited to: a federal corporate rate reduction from
35%
to
21%
; limitations on the deductibility of interest expense and executive compensation; repeal of the Alternative Minimum Tax (“AMT”); full expensing provisions related to business assets; creation of new minimum taxes such as the base erosion anti-abuse tax (“BEAT”) and Global Intangible Low Taxed Income (“GILTI”) tax; and the transition of U.S. international taxation from a worldwide tax system to a modified territorial tax system, which will result in a one time U.S. tax liability on those earnings which have not previously been repatriated to the U.S. (the “Transition Tax”). The provisional impacts of this legislation are outlined below:
|
·
|
|
Beginning January 1, 2018, the U.S. corporate income tax rate will be 21%. The Company is required to recognize the impacts of this rate change on its deferred tax assets and liabilities in the period
enacted.
A
s the Company ha
d
a full valuation allowance on its net deferred tax asset
as of December 31, 2017
, there was no overall impact to the financial statements in 2017 due to this change in rate.
However, as discussed further below, during the three months ended September 30, 2018, t
he Company
reversed a portion of its
valuation allowance on its net deferred tax asset
attributable to U.S. taxable income. As a result of the reduction in the corporate income tax rate, the benefit from this reversal was
$19
.
9
million l
ess than it would have been at the previous 35% corporate income tax rate
.
|
|
·
|
|
The Tax Reform Act also repealed the corporate AMT for tax years beginning on or after January 1, 2018 and provides for existing alternative minimum tax credit carryovers to be refunded beginning in 2018. The Company has approximately
$1.4
million in refundable credits, and it expects that a substantial portion will be refunded between 2018 and 2021. As such, most of the valuation allowance in place at the end of 2017 related to these credits has been released and a deferred tax asset of
$1.3
million is reflected related to the expected benefit in future years.
|
|
·
|
|
The Transition Tax on unrepatriated foreign earnings is a tax on previously untaxed accumulated and current earnings and profits ("E&P") of the Company's foreign subsidiaries. To determine the amount of the Transition Tax, the Company must determine, among other factors, the amount of post-1986 E&P of its foreign subsidiaries, as well as the amount of non-U.S. income taxes paid on such earnings. Based on the Company’s reasonable estimate of the Transition Tax, there is no provisional Transition Tax expense. The Company has not completed its accounting for the income tax effects of the transition tax and is continuing to evaluate this provision of the Tax Act.
|
|
·
|
|
The Tax Reform Act creates a new requirement that GILTI income earned by foreign subsidiaries must be included currently in the gross income of the U.S. shareholder. Due to the complexity of the new GILTI tax rules, the Company is continuing to evaluate this provision of the Tax Act. Under U.S. GAAP, the Company is permitted to make an accounting policy election to either treat taxes due on future inclusions in U.S. taxable income related to GILTI as a current period expense when incurred or to factor such amounts into the Company's measurement of its deferred taxes. In addition, we are waiting for further interpretive guidance in connection to the GILTI tax. For these reasons, the Company has not yet completed its analysis of the GILTI tax rules and is not yet able to reasonably estimate the effect of this provision of the Tax Act or make an accounting policy election for the accounting treatment whether to record deferred taxes attributable to the GILTI tax. The Company has not recorded any amounts related to potential GILTI tax in the Company’s financial statements.
|
Other provisions in the legislation, such as interest deductibility and changes to executive compensation plans are not expected to have material implications to the Company’s financial statements. The income tax effects recorded in the Company’s financial statements as a result of the Tax Reform Act are provisional in accordance with ASU 2018-05 as the Company has not yet completed its evaluation of the impact of the new law. ASU 2018-05 allows for a measurement period of up to one year after the enactment date of the Tax Reform Act to finalize the recording of the related tax impacts. The Company does not believe potential adjustments in future periods would materially impact the Company’s financial condition or results of operations.
Additionally, the Tax Reform Act may further limit the Company’s ability to utilize foreign tax credits in the future. The Tax Reform Act introduces a new credit limitation basket for foreign branch income. Income from foreign branches would now be allocated to this specific tax credit limitation basket which cannot offset income in other baskets of foreign income. Under the Tax Reform Act, foreign taxes imposed on the foreign branch profits will not offset U.S. non-branch related foreign source income. Additional guidance is needed to determine how this will impact the Company and any future utilization of foreign tax credit carryforwards.
Income taxes attributable to continuing operations for the three months ended
September 30, 2018
and
2017
are attributable to foreign taxes payable in Gabon. The Company has not recorded any measurement period adjustments under ASU 2018-05 during the three and nine months ended
September 30, 2018
.
Provision
(benefit)
for income taxes related to income (loss) from continuing operations consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
(in thousands)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(in thousands)
|
U.S. Federal:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
(406)
|
|
$
|
—
|
|
$
|
(406)
|
|
$
|
—
|
Deferred
|
|
|
(19,677)
|
|
|
—
|
|
|
(19,677)
|
|
|
—
|
Foreign:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
4,373
|
|
|
2,749
|
|
|
11,997
|
|
|
9,039
|
Deferred
|
|
|
(46,514)
|
|
|
—
|
|
|
(46,514)
|
|
|
—
|
Total
|
|
$
|
(62,224)
|
|
$
|
2,749
|
|
$
|
(54,600)
|
|
$
|
9,039
|
As of December 31, 2017, the Company had deferred tax assets of
$154.5
million primarily attributable to U.S. federal taxes related to basis differences in fixed assets, foreign tax credit carryforwards, and net operating loss carryforwards as well as foreign net operating losses for foreign jurisdictions. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. As of December 31, 2017, the Company was in a cumulative three year pre-tax loss position for both the U.S. and Gabon jurisdictions. As of December 31, 2017, we did not anticipate utilization of the foreign tax credits prior to expiration nor did we expect to generate sufficient taxable income to utilize other deferred tax assets. On the basis of this evaluation, valuation allowances of
$153.2
million were recorded as of December 31, 2017. Valuation allowances reduce the deferred tax assets to the amount that is more likely than not to be realized.
Taxes paid in Gabon with respect to earnings from the Etame Marin block are determined under the provisions of the Etame Marin PSC. In accordance with the Etame Marin PSC, the consortium maintains a “Cost Account” which accumulates capital costs and
operating expenses (“Recoverable Costs”) that are deductible against revenues, net of royalties, in determining taxable profits. For each calendar year, the consortium is entitled to receive a percentage of the production (“Cost Recovery Percentage”) remaining after deducting royalties so long as there are amounts remaining in the Cost Account. Prior to the PSC Extension, the Cost Recovery Percentage was 70%. As a result of the PSC Extension, the Cost Recovery Percentage has been increased to 80% for the period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%. The difference between revenues, net of royalties, and the costs recovered for the period is “Profit Oil.” As payment of corporate income taxes, the consortium pays the government an allocation of the remaining Profit Oil production from the contract area ranging from
50%
to
60%
. The percentage of Profit O
il
paid to the government as tax is a function of production rates. When the Cost Account is less than the entitled recovery percentage (either
70%
or
80%
, depending on the period),
Profit Oil
as a percentage of revenues increases and Gabon taxes paid increase as a percentage of revenues. At December 31, 2017, there was
$97.6
million remaining in the portion of the Cost Account associated with our interest.
Prior to the PSC Extension, the Cost Recovery Percentage was 70
%, and the exploitation periods ended
beginning in
June 2021
. F
uture proved reserves did not extend beyond 2021.
Opportunities for increasing reserves by drilling wells were limited, and while oil prices had improved since 2016, they were not at the levels needed to recover VAALCO’s Cost Account.
As a result of these factors, the
ability to recognize the benefit from the
potential deferred tax asset related to the difference between
VAALCO’s Cost Account
and the book basis of the Etame
Marin block
assets was
deemed to be remote, and the deferred tax asset was
not recognized.
As a result of the PSC Extension during the three months ended September 30, 2018, the Cost Recovery Percentage increased to 80% and the exploitation periods were extended to at least September 16, 2028, and if the two five-year option periods are elected the period would extend to September 16, 2038. In addition to the benefits under the PSC Extension, we expect higher future oil prices based on current Brent futures strip pricing over the next few years and we expect future production from the planned drilling of
two
to
three
wells in 2019. Given these factors, we determined that the potential for a recovery of our Cost Account was no longer remote, and therefore we recorded a deferred tax asset of
$46.5
million related to the excess of the Cost Account over the book basis of the Etame Marin block assets. In addition, as a result of recording the deferred tax asset of $46.5 million related to our Cost Account, we recorded the corresponding deferred tax liability of
$9.8
million attributable to the U.S. federal income tax impact.
We also evaluated the amount of the valuation allowance needed related to deferred tax assets recognized related to U.S. federal income taxes. In making this evaluation, we considered the impact on future taxable income of increased earnings as a result of the PSC Extension as well as increases in oil prices during the year, including current oil prices as well as Brent futures strip pricing over the next few years and the future production from the planned drilling of two to three wells in 2019. We also considered the pattern of earnings over the past three years. On the basis of these factors, we determined that it is more likely than not that we will realize a portion of the benefit from the deferred tax assets related to the fixed asset basis differences as well as the net operating losses. Accordingly, we reversed
$29.9
million of the valuation allowance recorded in prior periods.
As a result of the 2017 tax legislation enacted in the U.S., we expect to realize the benefit from our AMT credit carryforwards. The valuation allowance recorded related to AMT credits in previous periods was reversed in 2017 with the exception for a reserve for the possible sequestration of the credits. The
$1.3
million reversal was recorded as a deferred income tax benefit during the fourth quarter of 2017.
The Company recognizes the financial statement benefit of a tax position only after determining that they are more likely than not to sustain the position following an audit. The Company believes that its income tax positions and deductions will be sustained on audit and therefore no reserves for uncertain tax positions have been established. Accordingly,
no
interest or penalties have been accrued as of December 31, 2017 and 2016. The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense.