NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
VAALCO Energy, Inc. and 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 exploration 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
5
below, we have discontinued operations associated with our
activities in Angola, West Africa.
Our consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon),
Inc., VAALCO Gabon S.A., VAALCO
Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., VAALCO International, Inc., VAALCO Energy (EG), Inc., VAALCO Energy
Mauritius (EG) Limited and VAALCO Energy (USA), Inc.
2. LIQUIDITY
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, oil and gas prices have stabilized at levels which are currently adequate to generate cash from operating activities for our continuing operations.
In addition to the impact of oil and gas prices on our access to capital markets, the availability of capital resources on attractive terms may be limited due to the geographic location of our primary producing assets. W
e
may
drill two
or three
development wells in 2018. Any drilling program we enter into would require approval of our partners and the government of Gabon.
We expect any capital expenditures made during 2018 will be funded by cash on hand, cash flow from operations and cash raised from debt and/or equity issuances.
We believe that at current prices, cash generated from continuing operations together with cash on hand at December 31, 2017 are adequate to support our operations and cash requirements during 2018 and through March 31, 2019
.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation
– The accompanying consolidated financial statements
(“Financial Statements”)
include the accounts of VAALCO and its wholly owned subsidiaries.
Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.
All intercompany transactions within the consolidated group have been eliminated in consolidation.
Reclassifications
– Certain reclassifications have been made to prior period amounts to conform to the current period presentation
related to
reclassifying material and supplies to prepayments and other.
These reclassifications did not affect our consolidated financial results.
Use of estimates
– The preparation of
the Financial Statements
in conformity with generally accepted accounting principles in the United States (“GAAP”) requires estimates and assumptions that affect the reported amounts of assets and liabilities
and the disclosure of contingent assets and liabilities as of the date of the
Financial Statements
and the reported amounts of revenues and expenses during the respective reporting periods.
Our
Financial Statements
include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
Estimates of oil and natural gas reserves used to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures.
D
ue to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available.
Cash and cash equivalents
–
Cash and cash equivalent
s
include
s
deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
Restricted cash and abandonment funding
– Restricted cash includes cash that is contractually restricted. Restricted cash is classified
as a current or non-current asset based on its designated purpose and time duration. Current amounts in restricted cash at December 31,
2017
and
2016
each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long term amounts at December 31,
2017
and
2016
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 certificates of deposit and commercial paper issued by banks with maturities typically not exceeding 90 days.
Accounts with partners
– Accounts with partners represent
the excess of charges billed over
cash calls paid by the partners for exploration, development and production expenditures mad
e by us as an operator
.
B
ad debts
– Quarterly, we evaluate our accounts receivable bala
nces to confirm collectability.
When collectability is in doubt, we record an allowance against the accounts receivable and a corresponding income charge for bad debts which appears in
the “Bad debt expense and other” line
item
of the consolidated statement
s
of operations. The majority of our accounts receivable balances are with our joint venture partners, purchasers of our production and the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed us.
Portions of our costs in Gabon (including our VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”).
As of
December 31, 2017
, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately XAF
21.2
billion (XAF
7.1
billion, net to VAALCO). As of
December 31, 2017
, the exchange rate was XAF
547.5
= $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 of XAF
16.3
billion (XAF
4.9
billion, net to VAALCO), representing the outstanding balance as of December 31, 2015, in
thirty-six
monthly installments of
$0.
3
million net to VAALCO. We received one monthly installment payment in July 2016; however, no further payments have been received
as of December 31, 2017
.
We are in discussions with t
he Gabonese government
regarding the timing of the resumption of
payments
.
In
2017
,
2016
and
2015
, we recorded allowances of
$
0.4
million,
$
0.7
million and
$
2.7
million, respectively, related to VAT which the government of Gabon has not reimbursed. The receivable amount, net of allowances, is reported as a
non-current asset
in the
“
Value added tax
and other
receivable
s”
line
item
in the consolidated balance sheet
s
. Because both the VAT receivable and the related allowance are denominated in
XAF
, the
exchange rate
revaluation of these balances into U.S. dollars at
the end of
each
reporting
period
also has an impact on profit/loss. Such foreign currency gains/(losses) are reported separately in the
“
Other, net
”
line
item
of the
consolidated
statement
s
of operations.
The
following
table provides a
n analysis of the change in
the
allowance
:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(in thousands)
|
Allowance for bad debt
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year
|
|
$
|
(5,211)
|
|
$
|
(4,221)
|
|
$
|
(2,400)
|
Charge to cost and expenses
|
|
|
(452)
|
|
|
(1,222)
|
|
|
(2,699)
|
Reclassification related to Sojitz acquisition
|
|
|
(694)
|
|
|
—
|
|
|
—
|
Foreign currency gain (loss)
|
|
|
(676)
|
|
|
232
|
|
|
878
|
Balance at end of period
|
|
$
|
(7,033)
|
|
$
|
(5,211)
|
|
$
|
(4,221)
|
|
|
|
|
|
|
|
|
|
|
Crude oil inventory
–
Crude oil inventories are carried at the lower of cost or market and represent our share of crude oil produced and stored on the FPSO, but unsold at the end of the period.
Materials and supplies
– Materials and supplies,
which are included in the “Prepayments and other” line item of the consolidated balance sheet,
are primarily used for production related activities
. These assets
are valued at the lower of cost, determined by the weighted-average method, or market.
Property and equipment
–
We use the successful efforts method of accounting for oil and natural gas producing activities.
Capitalizati
on – Leasehold acquisition costs are initially capitalized. Costs to drill exploratory wells are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved reserves, the associated costs are charged to exp
loration expense at that time.
Exploration costs, other than the cost of drilling exploratory wells, which can include geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are charged to exploration expense as incurred. All development costs, including developmental dry hole costs, are capitalized.
Impairment
– We review our oil and natural gas producing properties for impairment on a field-by-field basis
quarterly or
whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset.
We evaluate our
undeveloped oil and natural gas leases for impairment periodically by considering numerous factors that could include nearby drilling results, seismic interpretations, market values of similar assets, existing contracts
, lease expiration terms
and future plans for exploration or development. When undeveloped oil and natural gas leases are deemed to be impaired, exploration expense is charged. Capitalized equipment inventory is reviewed regularly for obsolescence. We identified equipment inventory in Gabon that we do not expect to use an
d charged
$0.3 million,
$0.3
million and
$1.5
million to
the “
Other operating loss, net
” line item of the consolidated statement of operations
in the years ended December 31,
2017,
2016
and
2015
, respectively.
Depreciation, depletion and amortization
– Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a field basis under the unit-of-production method based upon estimates of proved reserves.
Support equipment 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.
Capitalized interest
–
Interest costs
and commitment fees
from external borrowings are capitalized on
exploration and development projects that are not subject to current depletion
.
Interest and commitment fees are capitalized only for the period that activities are in progress to bring
these projects to their intended use
.
Capitalized interest is added to the cost of the underlying asset and is depleted on the unit-of-production method in the same manner as the underlying asset
s
.
We capitalized
no
interest costs for the years ended December 31,
2017
or
2016
. We capitalized $0.8 million in interest costs during the year ended December 31, 2015.
Asset retirement obligations (“ARO”)
– We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and natural gas properties. We use current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to oil and natural gas properties.
To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate.
Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and natural gas production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. See Note
7
for disclosures regarding our asset retirement obligations.
Revenue recognition
– We recognize oil and natural gas revenues when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured.
We follow the sales method of accounting for crude oil and natural gas production imbalances. W
e recognize revenues on the volumes sold based on the provisional sales prices. 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.
As of December 31,
2017
and
2016
, we had
no
recorded oil and natural gas imbalances.
Major maintenance activities
– Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and our labor costs.
Stock based compensation
- We measure
the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. Grant date fair value for options is estimated using the Black-Scholes option pricing model.
The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award
. For restricted stock, grant date fair value is determined using the market value of our common stock on the date of grant.
The fair value of stock appreciation rights (“SARs”) is based on a Monte Carlo simulation at grant date and at each subsequent reporting date. The Monte Carlo simulation to value our SARs uses the following inputs: (i) the quoted market price of our common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term which is based on the contractual term, (iv) the expected volatility which is based on the historical volatility of the our stock for the length of time corresponding to the expected term of the SARs, (v) the expected dividend yield is based on our anticipated dividend payments, (vi) the risk-free interest rate which is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the SARs.
Our stock-based compensation expense is recognized based on the awards as they vest, using the straight-line attribution method over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
When awards are forfeited before they vest, previously recognized expense related to such forfeitures is reversed in the period in which the forfeiture occurs.
Foreign currency transactions
–
The U
.S. dollar is the functional currency of our foreign operating subsidiaries
. Gains and losses on foreign currency transactions are included in income. Within the consolidated statements of operations line
item “
Other income (expense)—Other, net,
”
we recognized gains on foreign currency transactions of $
0.5
million in
2017
, while we recognized losses on foreign currency transactions of $
30
thousand
and
$0.8
million in
2016
and
2015
,
respectively.
Income taxes
– We account for income taxes under an asset and liability approach that recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the
Financial Statements
and tax bases of assets and
liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. We
report
interest related to income tax liabilities
in the
“
Interest expense
” line item
on the consolidated statements of operations
, and we report
penalties
in the “
Other, net
” line item
on the consolidated statements of operations.
Derivative Instruments and Hedging Activities
– We use derivative financial instruments to achieve a more predictable cash flow from oil production by reducing our exposure to price fluctuations. Our derivative instruments at December 31
, 2016
consisted of fixed price oil puts, which give us the option to sell a contracted volume of oil at a contracted price on a contracted date in the future.
All of our
oil
put contracts, which provided for settlement based upon reported the Brent price, had expired as of December 31, 2017.
We record balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Other, net” line item located within the “Other income (expense)” section of the consolidated statements of operations.
We received cash settlements of
$0.2
million during
the year ended December 31, 2017 related to matured derivative contracts.
Fair Value
– Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in our internally developed present value of future cash flows model that underlies the fair-value measurement).
Fair value of financial instruments
– Our current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable
, derivative assets,
accounts
payable
and guarantee
.
As discussed further in Note 10, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. With respect to our other financial instruments included in current assets and liabilities, t
he carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. The carrying value of our long-term debt approximates fair value, as the interest rates are adjusted based on
market
rates currently in effect.
General and administrative related to shareholder matters
–
Amounts related to shareholder matters for the years ended December 31, 2016 and 2015 relate to costs incurred related to shareholder litigation that was settled in 2016. For 2016, the amounts also include the offsetting insurance proceeds related to these matters.
Other, net
–
“Other, net” in non-operating income and expenses includes gains and losses from derivatives and foreign currency transactions as discussed above. In addition, “Other, net” for the year ended December 31, 2017 includes $2.6 million
related
to the reversal of accruals for liabilities we are no longer obligated to pay.
4
. 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
.
It has not been the Company’s practice to make modifications to share-based payment awards which would have been impacted by this standard, and while there can be no assurance that this will not occur in future periods, we do not expect adoption of this standard to have 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 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 y
ears. Early adoption is permitted.
We
do not plan to early adopt this standard. Restricted cash will be included as a component of Cash, cash equivalents and restricted cash on our Consolidated Statement of Cash Flows for all periods presented. Due to the nature of this accounting standards update, this will 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
. 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 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, wi
th 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 presente
d in the financial statements.
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 state
ments presented in such report.
We are in the early stages of our gap assessment, but we expect that leases
with terms greater than 12 months which are currently
treated as operating leases 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 Note 9. We do not expect there will be a material overall impact on results of operations or cash flows
.
We have developed an implementation plan related to this new standard. In connection with our implementation plan, w
e
will be
reviewing
our lease contracts
and evaluating other contracts to identify
embedded leases
and determining the appropriate accounting treatment, and we will be evaluating the impact on processes and procedures as well as the internal controls related to the proper accounting for leases under the new standard.
I
n 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 d
id
not early adopt the standard. We adopt
ed
the Revenue Recognition ASU
via the
modified
retrospective transition method. We
have
complete
d
our gap assessment and have determined that we qualify for point in time recognition for essentially all of our sales. As such, the Company
’s
adoption of this standard
did not
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, results of operations, debt covenants or business practices
.
As required by the new standard, we will
have expanded disclosures related to the nature of our sales contracts and other matters related to revenues and the accounting for revenues
. In addition, for the periods beginning January 1, 2018, we have
implemented new internal controls and procedures associated with 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.
5. ACQUISITIONS AND DISPOSITIONS
Sojitz Acquisition
On
November
2
2
, 2016, we
closed on the
purchase
of
an additional
2.98%
working interest (
3.23%
p
articipating 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 ha
d
an effective date of August 1, 2016
and was funded with cash on hand
.
The following amounts represent the fair value of identifiable assets
acquired and liabilities assumed
in the
Sojitz acquisition
.
|
|
|
|
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
Et
ame
Marin b
lock
, 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 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. These assumptions represent Level 3 inputs, as further discussed in Note 3.
The actual impact of the Sojitz Acquisition was an increase to “Total revenues” in the consolidated statement of operations of
$0.2
million for the year ended December 31, 2016 and a minimal decrease to “Net loss” in the consolidated statement of operations for the year ended December 31, 2016. The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on our results of operations for the years ended December 31, 2016 and 2015 as if it had been consummated on January 1, 2015. The unaudited pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
(in thousands)
|
Pro forma (unaudited)
|
|
|
|
|
|
Oil and natural gas sales
|
$
|
65,427
|
|
$
|
88,940
|
Operating loss
|
|
(4,295)
|
|
|
(101,494)
|
Loss from continuing operations
|
|
(19,232)
|
|
|
(120,546)
|
Basic and diluted net loss per share:
|
|
|
|
|
|
Loss from continuing operations
|
$
|
(0.33)
|
|
$
|
(2.07)
|
Net loss
|
$
|
(0.47)
|
|
$
|
(2.72)
|
Sale of Certain U.S. Properties
During 2015, we completed the sale of our interests in various wells in Texas and Alabama for $0.4 million resulting in a minimal loss. In
December 2016, we completed the sale
of
our interests in
two
wells in the Hefley field in North Texas for
$0.8
million
resulting in a minimal loss.
In April 2017, we completed the sale of our interests in the East Poplar Dome field in Montana for
$0.3
million, resulting in a gain of approximately
$0.3
million
reported on the line “Other operating income (expense), net” in our results of operations for the year
ended December 31, 2017.
Discontinued Operations - Angola
In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). The four year primary term, referred to as the Initial Exploration Phase (“IEP”), with an optional three year extension, awarded us 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, we entered into the Subsequent Exploration Phase (“SEP”) which extended the exploration period to November 30, 2017 and required us and the co-participating interest owner, the Angolan national oil company, Sonangol P&P, to drill
two
additional exploration wells. Our working interest is
40%
, and it carries 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 assets and liabilities as of December 31, 2017 and 2016 and its results of operations for the years ended December 31, 2017, 2016 and 2015.
Summarized Results of Discontinued Operations
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in thousands)
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Exploration expense
|
$
|
—
|
|
$
|
15,137
|
|
$
|
36,044
|
Depreciation, depletion and amortization
|
|
—
|
|
|
9
|
|
|
12
|
General and administrative expense
|
|
615
|
|
|
1,269
|
|
|
2,535
|
Bad debt recovery and other
|
|
—
|
|
|
(7,629)
|
|
|
—
|
Total operating costs, expenses and (recovery)
|
|
615
|
|
|
8,786
|
|
|
38,591
|
Other operating loss, net
|
|
—
|
|
|
(172)
|
|
|
(1,856)
|
Operating loss
|
|
(615)
|
|
|
(8,958)
|
|
|
(40,447)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income
|
|
—
|
|
|
3,201
|
|
|
—
|
Other, net
|
|
(3)
|
|
|
552
|
|
|
2,345
|
Total other income (expense)
|
|
(3)
|
|
|
3,753
|
|
|
2,345
|
Loss from discontinued operations before income taxes
|
|
(618)
|
|
|
(5,205)
|
|
|
(38,102)
|
Income tax expense
|
|
3
|
|
|
3,078
|
|
|
—
|
Loss from discontinued operations
|
$
|
(621)
|
|
$
|
(8,283)
|
|
$
|
(38,102)
|
Assets and Liabilities Attributable to Discontinued Operations
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
|
|
(in thousands)
|
ASSETS
|
|
|
|
|
|
|
Accounts with partners
|
|
$
|
2,836
|
|
$
|
2,139
|
Total current assets
|
|
|
2,836
|
|
|
2,139
|
Total assets
|
|
$
|
2,836
|
|
$
|
2,139
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
158
|
|
$
|
77
|
Foreign taxes payable
|
|
|
—
|
|
|
3,078
|
Accrued liabilities and other
|
|
|
15,189
|
|
|
15,297
|
Total current liabilities
|
|
|
15,347
|
|
|
18,452
|
Total liabilities
|
|
$
|
15,347
|
|
$
|
18,452
|
Drilling Obligation
Under the PSA, we
and the other participating interest owner, Sonangol P&P, were obligated to perform exploration activities that included specified seismic activities and drilling a specified number of wells during each of the exploration phases identified in the PSA. The specified seismic activities were completed, and one well, the Kindele #1 well, was drilled in 2015. The PSA provides a stipulated payment of
$10.0
million for each exploration well for which a drilling obligation remains under the terms of the PSA, of which our participating interest share would be
$5.0
million per well. We have reflected an accrual of
$15.0
million for a potential payment as of December 31, 2017 and 2016, respectively, which represents what we believe to be the maximum potential amount attributable to VAALCO Angola’s interest under the PSA.
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 defa
ulted partner were abandoned in
2012. The available
40%
working interest in Block 5, offshore Angola was assigned to Sonangol P&P e
ffective on January 1, 2014. We
invoiced Sonangol P&P for the unpaid delinquent amounts from the defaulted partner plus the amounts incu
rred during the period prior to
assignment of the working interest totaling
$7.6
million plus interest in April 2014. Because this amoun
t 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 o
wed 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 re
covery is reflected in the “Bad
debt expense and other” line
item in
our summarized results of discontinued operations. Default interest of $3.2 million is shown in
the “Interest income” line
item in
our summarized results of discontinued operations.
6
. OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT
Proved Properties
We review our oil and natural gas producing properties for impairment
quarterly or
whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable.
When an oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in our impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.
Declining forecasted oil prices in 2015 caused us to perform impairment reviews of our proved properties in each quarter of 2015 for all fields in the Etame Marin block offshore Gabon and the Hefley field in North Texas. For the Etame Marin fields, we recorded an aggregate impairment charge of
$78.1
million for 2015, reducing the aggregate carrying value of these fields to an aggregate fair value of
$12.7
million. For the U.S. fields, we recorded an impairment charge of
$3.2
million for 2015 reducing the aggregate carrying value of the field to
$1.2
million.
During
2016
, our negative price differential to Brent narrowed and we incurred no significant capital spending. We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for most of our fields, with the exception of the Avouma field in the Etame Marine block offshore Gabon.
A
t the Avouma field, the electrical submersible pumps (“ESPs”) in the South Tchibala 2-H well and the Avouma 2-H well failed, and these wells were temporarily shut
in. After utilizing a hydraulic workover unit to replace the failed ESP systems, the South Tchibala 2-H and the Avouma 2-H wells resumed production in December 2016 and January 2017, respectively. The reserves used in our impairment evaluation of the Avouma field prior to the fourth quarter of 2016 were revised to reflect the impact of this lost production for several months and the impact of the forward price curve. The undiscounted future net cash flows for the Avouma field were in excess
of the field’s carrying value
at December 31, 2016
.
As a result, no impairment was required for the Avouma field, or any of our other fields in Gabon, for
2016.
There was no triggering event in the year ended December 31, 2017 that would cause us to believe the value of oil and natural gas producing properties should be impaired.
Undeveloped Leasehold Costs
We have a 31% working interest in an undeveloped portion of Block P offshore Equatorial Guinea that we acquired in 2012 for which we have $10.0 million capitalized in undeveloped acreage. It is currently unlikely that we will be making any near-term expenditures with respect to any development of this property. We and our partners will need to evaluate the timing and budgeting for exploration
and development activities under a development and production area in the block, including the approval of a development and production plan to develop the Venus discovery on the block. 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.
In September 2011, we acquired an interest in the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana. Exploratory drilling required by terms of the acquisition was unsuccessful. Due to the sustained low oil prices and forward oil prices, we charged the full
$1.2
million
undeveloped leasehold
to exploration expense in 2015.
Capitalized Exploratory Well Costs
At December 31, 2014, the drilling costs of the N’Gongui No. 2 discovery that was drilled in the third and fourth quarters of 2012 in the Mutamba Iroru block onshore Gabon were capitalized pending the determination of proved reserves.
Since th
is
discovery, we
have
performed quarterly evaluations of the capitalized exploratory well costs for the N’Gongui No. 2 discovery to determine whether sufficient progress had been made towards development, as well as the economic and operational viability of the project. The evaluation of economic viability takes into account a number of factors, including alternative development scenarios, estimated reserves, projected drilling and development costs and projected oil price data. As a result of lower projected oil price data at September 30, 2015, the results from the economic modeling indicated that the costs for this well did not continue to meet the criteria for suspended well costs. Accordingly, all capitalized costs related to the project, including capitalized exploratory well costs were charged to exploration expense in the third quarter of 2015.
Capitalized Equipment Inventory
Capitalized
e
quipment inventory in Gabon related to Mutamba was written off
in 2015
because further drilling in the prospect is uneconomic, while equipment inventory related to the Etame Marin block was reduced in value due to obsolescence of some items.
7
. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in our asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
Balance at January 1
|
|
$
|
18,612
|
|
$
|
16,166
|
|
$
|
14,846
|
Accretion
|
|
|
951
|
|
|
903
|
|
|
778
|
Additions
|
|
|
—
|
|
|
—
|
|
|
1,085
|
Acquisitions and dispositions
|
|
|
(103)
|
|
|
1,544
|
|
|
—
|
Revisions
|
|
|
703
|
|
|
(1)
|
|
|
(543)
|
Balance at December 31
|
|
$
|
20,163
|
|
$
|
18,612
|
|
$
|
16,166
|
Accretion is recorded in the line item “Depreciation, depletion and amortization” o
f
our consolidated statements of operations.
We are required under the Etame PSC to conduct regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block.
The most recently completed abandonment study was in
January 2016
. The final results of the abandonment study resulted in an increase in the costs necessary to fund future abandonment obligations.
8
. DEBT
In January 2014, we executed a loan agreement with the International Finance Corporation (“IFC credit facility”) for a
$65.0
million revolving credit facility,
which
wa
s secured by the assets of our Gabon subsidiary
.
O
n June 29, 2016, we executed a supplemental a
greement with the IFC which, among other things, amended
and restated our existing loan
agreement to convert
the
$20.0
million revolving portion of the credit facility, to
a term loan
with
$15.0
million
outstanding
(“Amended Term Loan Agreement”)
. The
Amended Loan A
greement
is secured by the assets of our Gabon subsidiary, VAALCO
Gabon
S.A.,
and is guaranteed
by VAALCO as the parent company
. The
A
mended
Term L
oan
A
greement 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%
.
T
he estimated fair value of the borrowings under the Amended Term Loan Agreement is $
9.2
million when measured using a discounted cash flow model over the life of the current borrowings at forecasted interest rates. The inputs to this model are Level 3 in the fair value hierarchy.
Covenants
Under the Amended Term Loan Agreement, the ratio of quarter-end net debt to EBITDAX (as defined in the Amended Term Loan Agreement) must be no more than
3.0
to 1.0. Additionally, our debt service coverage ratio must be greater than
1.2
to 1.0 at each semi-annual review period. Certain of VAALCO’s subsidiaries are contractually prohibited from making payments, loans or transferring assets to VAALCO or other affiliated entities. Specifically, under the Amended Term Loan Agreement, VAALCO Gabon S.A. could be restricted from transferring assets or making dividends, if the positive and negative covenants are not in compliance with the Amended Term Loan Agreement. We were in compliance with all financial covenants as of
December 31, 2017
.
Interest
Until June 29, 2016, u
nder the terms of the original IFC
credit facility, we paid commitment fees on t
he undrawn portion of the total
commitment. Commitment fees
had been
equal to
1.5%
of the unused balance of the senior tranche of
$50.0
million and
2.3%
of the unused
balance of the subordinated tranche of
$15.0
million when a commitment was available for utilization.
With the execution of the
Amended Term Loan Agreement
with the IFC in June 2016, beginning on June
29, 2016,
and continuing through March 14, 2017, commitment fees wer
e equal to 2.3% of the undrawn term l
oan amount of $5.0 million. There are no further commitment fees owing after March 14, 2017.
The table below shows the components of the
“
Interest expense
”
line
item
of our consolidated statement
s of operations and the average
effective interest rate, excluding commitment fees, on our
borrowings:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(in thousands)
|
Interest incurred, including commitment fees
|
$
|
997
|
|
$
|
1,353
|
|
$
|
1,496
|
Deferred finance cost amortization
|
|
369
|
|
|
319
|
|
|
304
|
Deferred finance cost write-off due to loan modification
|
|
—
|
|
|
869
|
|
|
—
|
Capitalized interest
|
|
—
|
|
|
—
|
|
|
(771)
|
Other interest not related to debt
(a)
|
|
48
|
|
|
72
|
|
|
296
|
Interest expense, net
|
$
|
1,414
|
|
$
|
2,613
|
|
$
|
1,325
|
|
|
|
|
|
|
|
|
|
Average effective interest rate, excluding commitment fees
|
|
6.72%
|
|
|
5.52%
|
|
|
4.09%
|
(a)
The “Other interest not related to debt” line item i
ncludes
interest income
.
9
. COMMITMENTS AND CONTINGENCIES
Litigation
Butcher settlement
On October 3, 2016, the Court approved a Stipulation and Order of Dismissal entered into by the parties in a stockholder class action lawsuit against the Company and all of its directors alleging that a previously terminated shareholder rights agreement, no longer in effect, and certain provisions of the former Chief Executive Officer’s and former Chief Financial Officer’s employment agreements securing change-in-control severance benefits were invalid under Delaware law, case number C.A. No. 12277-VCL, filed on April 29, 2016, in the Court. After the Company and its directors moved to dismiss the lawsuit, the Plaintiff Daniel Butcher agreed to dismiss the lawsuit as moot, and the Company agreed to settle Plaintiff’s application for an award of attorneys’ fees, all of which were covered by our directors and officers insurance as a covered claim.
McDonough litigation
On December 7, 2016, a lawsuit was filed against the Company alleging that a former worker on the Company’s oil and gas platforms off the coast of Gabon was terminated because of his age in violation of the Age Discrimination in Employment Act and the Texas
Commission on Human Rights Act.
The Plaintiff
sought
damages for lost wages and benef
its as well as attorneys’ fees.
The case
wa
s pending in the U.S. District Court for the Southern District of Texas styled as
McDonough v. VAALCO Energy, Inc.
, No. 4:17-cv-
00361
. In a February 2017 demand letter, the plaintiff made a demand for
$361,000
to settle this claim.
On June 22, 2017, the court entered a final order of dismissal, pursuant to the plaintiff’s motion for voluntary dismissal, and entered final judgment in favor of the Company. This matter is now resolved, and ha
d
no material effect on our financial condition, results of operations or liquidity.
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 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
December 31, 2017
and
December 31, 2016
, respectively, representing the guarantee’s
estimated
fair value. The guarantee of the offshore Gabon FPSO lease has
$85.2
million in remaining gross minimum obligations
as of
December 31, 2017
.
Estimated future minimum obligations through the end of the FPSO charter are as follows:
|
|
|
|
|
|
|
|
|
Full
|
|
|
|
|
|
Charter
|
|
VAALCO
|
(in thousands)
|
|
Payment
|
|
Net
|
Year
|
|
|
|
|
|
|
2018
|
|
|
31,294
|
|
|
9,719
|
2019
|
|
|
31,294
|
|
|
9,719
|
2020
|
|
|
22,634
|
|
|
7,029
|
Total
|
|
$
|
85,222
|
|
$
|
26,467
|
The charter payment includes a
$0.93
per barrel charter fee for production up to 20,000 barrels of oil per day and a
$2.50
per barrel
charter fee for those barrels produced in excess of 20,000 barrels of oil per day. VAALCO’s net share of payments was
$12.8
million,
$11.2
million and
$10.9
million for the years ended December 31,
2017
,
2016
and
2015
, respectively.
Other lease obligations
In addition to the FPSO, we have operating lease obligations, as follows:
|
|
|
|
|
|
|
|
|
Gross
|
|
VAALCO
|
(in thousands)
|
|
Obligation
|
|
Net
|
Year
|
|
|
|
|
|
|
2018
|
|
|
6,101
|
|
|
2,176
|
2019
|
|
|
407
|
|
|
407
|
2020
|
|
|
340
|
|
|
340
|
2021
|
|
|
—
|
|
|
—
|
2022
|
|
|
—
|
|
|
—
|
Thereafter
|
|
|
—
|
|
|
—
|
Total
|
|
$
|
6,848
|
|
$
|
2,923
|
We incurred rent
expense of $2.4 million
,
$4.5
million and
$4.3
million under operating leases
for the years ended December 31,
2017
,
2016
and
2015
.
Rig commitment
In 2014, we entered into a long-term contract for the Constellation II drilling rig that was under a long-term contract for the multi-well development drilling campaign offshore Gabon. The campaign included the drilling of development wells and workovers of existing wells in the Etame Marin block. We 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
con
solidated statement of operations for the year ended December 31, 2016.
Gabon domestic market obligation and other investment obligations
Under the terms of the Etame PSC, effective in April 2016, the consortium is required to provide to the local government refinery a volume of crude at a
15%
discount to market price (the “Gabon DMO”). Prior to April 2016, the discount was
25%
. The volume required to be furnished is the amount of the Etame Marin block production divided by total Gabon production times the volume of oil refined by the refinery per year
. In 201
7
, we
paid $
1.2
million for our
share of the 201
6
obligation.
In 2016, we paid
$
1.7
million for our share of the 2015 obligation. In 2015, we paid
$2.3
million for our share of the 2014 obligation.
We accrue an amount for the Gabon DMO based on management’s best estimate of the volume of crude required, because the refinery does not publish throughput figures. The amount accrued at
December 31, 2017
, for our share of the
2017
obligation was
$1.3
million. The amount accrued at
December 31, 2016
, for our share of the
2016
obligation was
$1.1
million. These costs are cost recoverable under the terms of the
Etame PSC. Also, beginning in April 2016, the consortium is required to pay an additional
1%
of revenues for provisions for diversified investments (“PID”) and for investments in hydrocarbons (“PIH”). The amount accrued at
December 31, 2017
, for our share of the
2017
obligation was
$1.4
million. The amount accrued at
December 31, 2016
, for our share of the
2016
obligation was
$0.4
million.
75%
of PID and PIH costs are cost recoverable under the terms of the Etame PSC
.
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 2011) providing for annual funding over a period of
ten
years at
12.14%
of the total abandonment estimate for the first
seven
years
, with annual payments for the remaining unfunded estimated costs spread over
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
December 31, 2017
,
$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”
in the
“Abandonment funding”
line item of
our consolidated balance sheet. Future changes to the anticipated abandonment
cost estimate could change our asset retirement obligation and the amount of future abandonment funding payments.
Regulatory and Joint Interest A
udits
We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements.
As of December 31, 2016, we had accrued
$1.0
million net to
VAALCO in the “Accrued liabilities and other” line item of our consolidated balance sheet for certain payroll taxes in Gabon which were not paid pertaining to labor provided to us over a number of years by a third-party contractor. While the payroll taxes were for individuals who were not our employees, we could be deemed liable for these expenses as the end user of the services provided. These liabilities were substantially resolved at the accrued amount in January 2017.
In 2016, the government of Gabon conducted an audit of our operations in Gabon, covering the years 2013 through 2014. We received the findings from this audit and responded
to the audit findings in January 2017.
Since providing our response, there have been changes in the Gabonese officials responsible for the audit. We are 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, an
d in December 2017, we received a report on their findings. We have evaluated the results of this audit, and have made an accrual
of
$0.5
million, net to VAALCO, for the estimated additional taxes along with penalties in the “Accrued liabilities and other” line item of
our consolidated balance sheet.
At
December 31, 2017
, we had
accrued
$1.3
million net
to VAALCO in
the
“Accrued liabilities and other”
line item of
our
c
onsolidated balance sheet for potential fees which may result from
a customs
audit.
Employment agreements
Our Chief Executive Officer
and Chief Financial Officer
have employment agreements which provide for payments of annual salary, incentive compensation and certain other benefits if their employme
nt is terminated without cause.
10. DERIVATIVES AND FAIR VALUE
As of Dec
ember 31, 2017, we had no derivative instruments outstanding. During the year ended December 31, 2017 and 2016, we had o
il puts
outstanding for
anticipated sales volumes for the period from
April
22, 2016 through
December 31, 2017
.
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 December 31, 2016, the fair value of all
of the put contracts were an asset of $1.2 million
.
The following table sets forth, by level within the fair value hierarchy and location on our consolidated balance sheets, the reported
fair
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 December 31, 2017
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
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 gain (loss) on derivative instruments on our consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
Derivative Item
|
|
Statement of Operations Line
|
|
2017
|
|
2016
|
|
2015
|
|
|
|
|
(in thousands)
|
Crude oil puts
|
|
Other, net
|
|
$
|
(1,032)
|
|
$
|
(1,711)
|
|
$
|
—
|
11. SHAREHOLDERS’ EQUITY (DEFICIT)
Preferred stock
–
Authorized preferred stock consists of
500,000
shares with a par value of
$25
per share. No shares of preferred stock were
issued
and
outstanding
as of December 31,
2017
or
2016
.
Treasury stock
–
In the years ended December 31,
2017
,
2016
and
2015
, we withheld
26,000
,
40,926
and
120,455
shares, respectively,
in
connection with
cashless stock option exercises and
restricted stock vestings
to satisfy tax withholding obligations related to stock option exercises.
12
.
STOCK-BASED
COMPENSATION
AND OTHER BENEFIT PLANS
Our stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of our Board of Directors to
issue
various typ
es of incentive compensation. Currently, we have issued stock options, restricted shares and SARs from the 2014 Long-Term Incentive Plan (“2014 Plan”).
At
December 31,
2017
,
2,404,442
shares
were authorized for future grants under this plan.
For each stock option granted, the number of authorized shares under the 2014 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2014 Plan will be reduced by twice the number of restricted shares.
We have no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.
We record non-cash compensation expense related to stock-based compensation as general and administrative expense.
For the years ended December
31,
2017
,
2016
and
2015
, non-cash compensation expense was
$1.1
million,
$0.2
million and
$3.8
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 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
$39
thousand in cash proceeds received from the exercise of stock options in 2017.
For 2016
and 2015
there were
no
cash proceeds
received
from the exercise of stock options.
During 2017
,
o
ptions for
1,162,930
shares
were granted to employees; these options vest over a
three
-year period, vesting in three equal parts on the first, second and third anniver
saries after the date of grant.
Options
for
465,950
shares
also
were granted
in 2017
to our non-employee directors, which were fully vested upon their grant.
We use the Black-Scholes model to calculate the grant date fair value of stock option awards. This fair value is then amortized to expense over the vesting period of the option. During 2017, 2016 and 2015, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants. Because we have not paid cash dividends and do not anticipate paying cash dividends on the common stock in the foreseeable future, no expected dividend yield was input to the Black-Scholes model.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
|
2015
|
Weighted average exercise price - ($/share)
|
$
|
0.99
|
|
$
|
1.14
|
|
$
|
4.41
|
|
Expected life in years
|
|
3.2
|
|
|
3.0
|
|
|
2.5
|
|
Average expected volatility
|
|
73
|
%
|
|
71
|
%
|
|
61
|
%
|
Risk-free interest rate
|
|
1.51
|
%
|
|
1.10
|
%
|
|
0.88
|
%
|
Weighted average grant date fair value - ($/share)
|
$
|
0.49
|
|
$
|
0.49
|
|
$
|
1.65
|
|
Stock option activity for the year
ended
December 31, 2017
is provided
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares Underlying Options
|
|
Weighted Average Exercise Price Per Share
|
|
|
Weighted Average Remaining Contractual Term
|
|
|
Aggregate Intrinsic Value
|
|
|
(in thousands)
|
|
|
|
|
|
(in years)
|
|
|
(in thousands)
|
Outstanding at January 1, 2017
|
|
2,644
|
|
$
|
3.92
|
|
|
|
|
|
|
Granted
|
|
1,629
|
|
|
0.99
|
|
|
|
|
|
|
Exercised
|
|
(37)
|
|
|
1.04
|
|
|
|
|
|
|
Forfeited/expired
|
|
(1,639)
|
|
|
4.48
|
|
|
|
|
|
|
Outstanding at December 31, 2017
|
|
2,597
|
|
|
1.77
|
|
|
3.53
|
|
$
|
—
|
Exercisable at December 31, 2017
|
|
1,506
|
|
|
2.30
|
|
|
3.28
|
|
$
|
—
|
The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.
T
he intrinsic value of stock options exercised in
2017
and
2015
was $0.0 million and
$
0.3
million
, respectively.
There were
no
exercises of
stock options in
2016
.
On February 28, 2018, the Company granted stock options for 494,941 shares with an exercise price of $0.86 per share.
As of
December 31, 2017
, unrecognized compensation cost related to
outstanding
stock options was
$0.3
million which is expected to be recognized over a weighted average period of
1.5
years.
Restricted shares
Restricted stock granted to employees will vest over a period determined by the Compensation Committee which is generally a
three
-
year period, vesting in three equal parts on the first three anniversaries
following
the date of the grant. Share grants to directors vest immediately and are not restricted. The following is a summary of activity in unvested restricted stock in
2017
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock
|
|
Weighted Average Grant Price
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
Non-vested shares outstanding at January 1, 2017
|
|
252
|
|
$
|
1.31
|
|
|
|
|
|
|
Awards granted
|
|
426
|
|
|
0.98
|
|
|
|
|
|
|
Awards vested
|
|
(297)
|
|
|
1.12
|
|
|
|
|
|
|
Awards forfeited
|
|
(41)
|
|
|
1.00
|
|
|
|
|
|
|
Non-vested shares outstanding at December 31, 2017
|
|
340
|
|
|
1.10
|
|
|
|
|
|
|
The total vest-date fair value of restricted stock awards which vested during
2017
,
2016
and
2015
was
$0.3
million,
$0.6
million and
$0.7
million, respectively. The weighted average grant date fair value per share of restricted stock awards was
$0.98
,
$1.11
and
$3.34
for the years ended December 31,
2017
,
2016
and
2015
, respectively.
On February 28, 2018, the Company issued 323,474 shares of service based restricted stock 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.
As of
December 31, 2017
, unrecognized compensation cost related to restricted stock totaled
$0.2
million and is expected to be recognized over a weighted average period of
1.6
years.
Stock appreciation rights (“SARs”)
SARs are granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR price per share specified in a SAR award on the date of grant (which may not be less than the fair market value of our common stock on the date of grant) and the fair market value per share on the date of exercise of the SAR. SARs granted to participants will
become exercisable over a period determined by the Compensation Committee of our Board of Directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of our Board of Directors.
The
815,355
SARs granted in the three months ended March 31, 2016 vest over a
three
-year period with a life of
5
years and have a maximum spread of
300%
of the
$1.04
SAR price per share specified in a SAR award on the date of grant.
The compensation expense related to these awards through December 31, 2016 was $25 thousand.
On February 28, 2018, 2,373,411 SARs were granted which vest over a three-year period with a life of 5 years and have a $0.86 SAR price per share
specified in a SAR award on the date of grant
.
For the year ended
December 31, 2017
,
1,049,528
SARs were granted, all having an exercise price of
$1.20
per share. One-third of the SARs are to vest on or after the first anniversary of the grant date at such time when the market price per share of our common stock exceeds
$1.30
; one-third of the SARs are to vest on or after the second anniversary of the grant date at such time when the share price exceeds
$1.50
; and one-third of the SARs are to vest on or after the third anniversary of the grant date at such time when the share price exceeds
$1.75
. SARs granted in 201
7
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 compensation expense related to these awards through
December 31, 2017
was $0.1 million.
SAR activity for the year ended
December 31, 2017
is provided
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares Underlying SARs
|
|
Weighted Average Exercise Price Per Share
|
|
Term
|
|
|
Value
|
|
|
(in thousands)
|
|
|
|
|
(in years)
|
|
|
(in thousands)
|
Outstanding at January 1, 2017
|
|
180
|
|
$
|
1.04
|
|
|
|
|
|
Granted
|
|
1,049
|
|
|
1.20
|
|
|
|
|
|
Exercised
|
|
—
|
|
|
—
|
|
|
|
|
|
Forfeited/expired
|
|
(153)
|
|
|
1.20
|
|
|
|
|
|
Outstanding at December 31, 2017
|
|
1,076
|
|
|
1.17
|
|
3.21
|
|
$
|
—
|
Exercisable at December 31, 2017
|
|
60
|
|
|
1.04
|
|
3.21
|
|
$
|
—
|
Other benefit plans
We sponsor a 401(k) plan, with a company match feature, for our employees. Costs incurred in the years ended December 31,
2017
,
2016
and
2015
for administering the plan, including the company match feature, were
approximately
$0.2
million
,
$0.3
million and
$0.4
million
, respectively
.
13
. 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. However, as the Company has a full valuation allowance on its net deferred tax asset, any deferred tax recognized due to the change in rate will be offset with a change in the valuation allowance. Therefore, there was no overall impact to the Financial Statements in 2017 due to this change in rate.
|
|
·
|
|
The Tax Reform Act also repealed the corporate AMT for tax years beginning on or after January 1, 2018 and 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 our 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. 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 the Securities and Exchange Commission’s Staff Accounting Bulletin number 118 “(SAB 118”) as the Company has not yet completed its evaluation of the impact of the new law. SAB 118 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.
In April 2017,
the Company
w
as
notified by the U.S. Internal Revenue Service (“IRS”) that they would be conducting an audit of
its
2014 U.S. federal tax return. The audit
was concluded in 2018, and there were no significant findings as a result
.
Provision for income taxes
related to income (loss) from continuing operations
consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
U.S. Federal:
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
Deferred
|
|
|
(1,260)
|
|
|
—
|
|
|
1,349
|
Foreign:
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
11,638
|
|
|
9,248
|
|
|
13,238
|
Deferred
|
|
|
—
|
|
|
—
|
|
|
—
|
Total
|
|
$
|
10,378
|
|
$
|
9,248
|
|
$
|
14,587
|
|
|
|
|
|
|
|
|
|
|
The primary differences between the financial statement and tax bases of assets and liabilities resulted in deferred tax assets
associated with continuing operations
at
December 31,
2017
and
2016
are as
follows:
|
|
|
|
|
|
|
|
|
As of December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
Deferred tax assets:
|
|
|
|
|
|
|
Basis difference in fixed assets
|
|
$
|
46,929
|
|
$
|
89,016
|
Foreign tax credit carryforward
|
|
|
48,071
|
|
|
50,339
|
Alternative minimum tax credit carryover
|
|
|
1,349
|
|
|
1,349
|
U.S. federal net operating losses
|
|
|
22,490
|
|
|
30,230
|
Foreign net operating losses
|
|
|
26,371
|
|
|
25,543
|
Asset retirement obligations
|
|
|
4,234
|
|
|
6,514
|
Basis difference in receivables
|
|
|
1,331
|
|
|
1,824
|
Other
|
|
|
3,690
|
|
|
6,952
|
Total deferred tax assets
|
|
|
154,465
|
|
|
211,767
|
Valuation allowance
|
|
|
(153,205)
|
|
|
(211,767)
|
Net deferred tax assets
|
|
$
|
1,260
|
|
$
|
—
|
|
|
|
|
|
|
|
Foreign tax credits will expire between the years 2018 and 2024. The
alternative minimum tax credits do not expire, and foreign net operating losses (“NOLs”) are not subject to expiry dates. The NOL for our United
Kingdom subsidiary can be carried forward indefinitely, while the NOLs for our Gabon subsidiaries are included in the respective subsidiaries’ cost oil accounts, which will be offset against future taxable revenues
. The U.S federal NOL
will expire between
203
5 and 2037
.
The ability to utilize NOLs and other tax attributes could be subject to a limitation if the Company were to undergo an ownership change as defined in Section 382 of the Tax Code.
Management
assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. We do not anticipate utilization of the foreign tax
credits prior to expiration nor do 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,
$211.8
million and
$210.7
million have been recorded as of
December 31, 2017
,
2016
and
2015
, respectively. Valuation allowances reduce the deferred tax asset
s
to the amount that is more likely than not to be realized.
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.
Income (loss)
from continuing operations
before income taxes is attributable as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
United States
|
|
$
|
(9,453)
|
|
$
|
(9,893)
|
|
$
|
(15,177)
|
Foreign
|
|
|
30,103
|
|
|
874
|
|
|
(90,790)
|
|
|
$
|
20,650
|
|
$
|
(9,019)
|
|
$
|
(105,967)
|
The reconciliation
of income tax expense attributable to income (loss) from continuing operations
to
income tax on income (loss) from continuing operations at
the U.S. statutory rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
Tax provision computed at U.S. statutory rate
|
|
$
|
7,228
|
|
$
|
(3,156)
|
|
$
|
(37,089)
|
Foreign taxes not offset in U.S. by foreign tax credits
|
|
|
6,775
|
|
|
6,319
|
|
|
(394)
|
Impact of Tax Reform Act
|
|
|
52,449
|
|
|
—
|
|
|
—
|
Effect of change in foreign statutory rates
|
|
|
—
|
|
|
2,394
|
|
|
3,014
|
Permanent differences
|
|
|
309
|
|
|
4,505
|
|
|
1,803
|
Foreign tax credit adjustments
|
|
|
2,394
|
|
|
—
|
|
|
—
|
Increase/(decrease) in valuation allowance
|
|
|
(58,777)
|
|
|
(802)
|
|
|
47,253
|
Other
|
|
|
—
|
|
|
(12)
|
|
|
—
|
Total income tax expense
|
|
$
|
10,378
|
|
$
|
9,248
|
|
$
|
14,587
|
|
|
|
|
|
|
|
|
|
|
At
December 31,
2017
,
2016
and
2015
, we were subject
to foreign and U.S. federal taxes only, with no allocations made to state and local taxes. The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
|
|
|
|
|
|
Jurisdiction
|
|
Years
|
United States
|
|
2008-2017
|
Gabon
|
|
2013-2017
|
14
. 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:
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(in thousands)
|
Basic weighted average shares outstanding
|
|
58,717
|
|
58,384
|
|
58,289
|
Effect of dilutive securities
|
|
3
|
|
—
|
|
—
|
Diluted weighted average shares outstanding
|
|
58,720
|
|
58,384
|
|
58,289
|
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive
|
|
2,823
|
|
4,363
|
|
5,586
|
Because we
recognized net losses for
the years
ended December 31, 2016 and 2015,
there were
no
dilutive securities for these years.
15
. 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 m
anagement review and evaluate the operation of each geographic segment separately primarily based on Operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the loca
tion of hydrocarbon production.
Corporate and other is primarily corporate and operations support
costs which are
not allocated to the reportable operating segments.
Segment activity
of continuing operations
for the years
ended Dec
ember 31,
2017
,
2016
and
2015
and long-lived assets and segment assets at December 31,
2017
and
2016
are as follow
s
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2017
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
U.S.
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
76,978
|
|
$
|
—
|
|
$
|
47
|
|
$
|
—
|
|
$
|
77,025
|
Depreciation, depletion and amortization
|
|
|
6,196
|
|
|
—
|
|
|
1
|
|
|
260
|
|
|
6,457
|
Bad debt expense and other
|
|
|
452
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
452
|
Operating income (loss)
|
|
|
28,488
|
|
|
(122)
|
|
|
352
|
|
|
(8,767)
|
|
|
19,951
|
Other, net
|
|
|
3,142
|
|
|
15
|
|
|
—
|
|
|
(1,044)
|
|
|
2,113
|
Interest expense, net
|
|
|
(1,414)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,414)
|
Income tax expense (benefit)
|
|
|
11,638
|
|
|
—
|
|
|
—
|
|
|
(1,260)
|
|
|
10,378
|
Additions to property and equipment - accrual
|
|
|
1,576
|
|
|
—
|
|
|
—
|
|
|
126
|
|
|
1,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
U.S.
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
59,460
|
|
$
|
—
|
|
$
|
324
|
|
$
|
—
|
|
$
|
59,784
|
Depreciation, depletion and amortization
|
|
|
6,531
|
|
|
—
|
|
|
151
|
|
|
244
|
|
|
6,926
|
Impairment of proved properties
|
|
|
—
|
|
|
—
|
|
|
88
|
|
|
—
|
|
|
88
|
Bad debt expense and other
|
|
|
1,222
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,222
|
Other operating expense
|
|
|
8,853
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,853
|
Operating income (loss)
|
|
|
3,901
|
|
|
(384)
|
|
|
(72)
|
|
|
(7,836)
|
|
|
(4,391)
|
Other, net
|
|
|
(22)
|
|
|
(8)
|
|
|
—
|
|
|
(1,985)
|
|
|
(2,015)
|
Interest expense, net
|
|
|
(2,614)
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(2,613)
|
Income tax expense
|
|
|
9,248
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,248
|
Additions to property and equipment - accrual
|
|
|
(4,242)
|
|
|
—
|
|
|
—
|
|
|
181
|
|
|
(4,061)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
U.S.
|
|
Corporate and Other
|
|
Total
|
Revenues-oil and natural gas sales
|
|
$
|
79,947
|
|
$
|
—
|
|
$
|
498
|
|
$
|
—
|
|
$
|
80,445
|
Depreciation, depletion and amortization
|
|
|
32,125
|
|
|
—
|
|
|
633
|
|
|
240
|
|
|
32,998
|
Impairment of proved properties
|
|
|
78,080
|
|
|
—
|
|
|
3,242
|
|
|
—
|
|
|
81,322
|
Bad debt expense and other
|
|
|
2,968
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,968
|
Operating income (loss)
|
|
|
(87,243)
|
|
|
(1,342)
|
|
|
(4,366)
|
|
|
(10,155)
|
|
|
(103,106)
|
Other, net
|
|
|
(1,034)
|
|
|
(33)
|
|
|
—
|
|
|
(469)
|
|
|
(1,536)
|
Interest expense, net
|
|
|
(1,144)
|
|
|
—
|
|
|
—
|
|
|
(181)
|
|
|
(1,325)
|
Income tax expense
|
|
|
13,238
|
|
|
—
|
|
|
—
|
|
|
1,349
|
|
|
14,587
|
Additions to property and equipment - accrual
|
|
|
66,269
|
|
|
—
|
|
|
—
|
|
|
150
|
|
|
66,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gabon
|
|
Equatorial Guinea
|
|
U.S.
|
|
Corporate and Other
|
|
Total
|
Long-lived assets from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
$
|
12,638
|
|
$
|
10,000
|
|
$
|
—
|
|
$
|
583
|
|
$
|
23,221
|
As of December 31, 2016
|
|
|
17,291
|
|
|
10,000
|
|
|
—
|
|
|
728
|
|
|
28,019
|
Information about our most significant customers
For the period from the second quarter of 2014 and through April 2015, our crude oil from Gabon was sold under a contract with The Vitol Group at the spot market for a fixed per barrel fee. Beginning in May 2015, we sold our crude oil production from Gabon under a term contract with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.
The contracted purchasers were TOTSA Total Oil Trading SA (“Total”) for May through July of 2015 and Glencore Energy UK Ltd. (“Glencore”) for August of 2015 through December of 201
7
. The contract with Glencore U.K.
ends in January 201
9
. Sales
of oil to Glencore were
approximately
100
%
of total revenues for 201
7
.
16. SUBSEQUENT EVENTS
The last lifting in 2017 was not completed until January 1, 2018 due to unsafe weather conditions. Net revenues of
$6.5
million
associated with net volumes delivered to the buyer on January 1, 2018
of 95,525 barrels will be reported
as revenue in 2018. The 7.1% increase in the January 2018 lifting price over the December 2017 lifting price positively impacted January’s revenue by $0.5 million.
17.
SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Our unaudited quarterly results for years
ended
December 31, 2017
and
2016
were prepared
in accordance with
GAAP
, and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. These adjustments are of a normal recurring nature. Quarterly income per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
(in thousands of dollars except per share information)
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
21,266
|
|
$
|
20,425
|
|
$
|
18,178
|
|
$
|
17,156
|
Total operating costs and expenses
|
|
|
13,055
|
|
|
15,068
|
|
|
14,454
|
|
|
14,413
|
Operating income (loss)
|
|
|
8,148
|
|
|
5,587
|
|
|
3,721
|
|
|
2,495
|
Income (loss) from continuing operations
|
|
|
4,435
|
|
|
2,451
|
|
|
(148)
|
|
|
3,534
|
Loss from discontinued operations
|
|
|
(176)
|
|
|
(168)
|
|
|
(174)
|
|
|
(103)
|
Net income (loss)
|
|
|
4,259
|
|
|
2,283
|
|
|
(322)
|
|
|
3,431
|
Basis net income (loss) per share
|
|
$
|
0.07
|
|
$
|
0.04
|
|
$
|
(0.01)
|
|
$
|
0.06
|
Diluted net income (loss) per share
|
|
$
|
0.07
|
|
$
|
0.04
|
|
$
|
(0.01)
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
(in thousands of dollars except per share information)
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
10,976
|
|
$
|
18,847
|
|
$
|
14,635
|
|
$
|
15,326
|
Total operating costs and expenses
|
|
|
24,509
|
|
|
14,232
|
|
|
10,919
|
|
|
14,249
|
Operating income (loss)
|
|
|
(13,515)
|
|
|
4,615
|
|
|
3,690
|
|
|
819
|
Income (loss) from continuing operations
|
|
|
(15,430)
|
|
|
(498)
|
|
|
1,016
|
|
|
(3,355)
|
Loss from discontinued operations
|
|
|
7,806
|
|
|
(20)
|
|
|
(15,783)
|
|
|
(286)
|
Net income (loss)
|
|
|
(7,624)
|
|
|
(518)
|
|
|
(14,767)
|
|
|
(3,641)
|
Basis net income (loss) per share
|
|
$
|
(0.13)
|
|
$
|
(0.01)
|
|
$
|
(0.25)
|
|
$
|
(0.06)
|
Diluted net income (loss) per share
|
|
$
|
(0.13)
|
|
$
|
(0.01)
|
|
$
|
(0.25)
|
|
$
|
(0.06)
|
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
This supplemental information is presented in accordance with certain provisions of ASC Topic 932 –
Extractive Activities- Oil and Natural Gas
. The geographic areas reported are the United States (North America), which includes our producing properties in the state of Texas, and International, which includes our producing properties offshore Gabon (Africa).
Costs Incurred for Acquisition, Exploration and Development Activities
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Costs incurred during the year:
|
|
(in thousands)
|
International:
|
|
|
|
|
|
|
|
|
|
Exploration costs - capitalized
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
Exploration costs - expensed
|
|
|
7
|
|
|
5
|
|
|
170
|
Acquisition of properties
|
|
|
—
|
|
|
5,754
|
|
|
—
|
Development costs
|
|
|
—
|
|
|
—
|
|
|
60,397
|
Total
|
|
$
|
7
|
|
$
|
5,759
|
|
$
|
60,567
|
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
Capitalized costs pertain to our producing activities in Gabon and the U.S and to undeveloped leasehold in Gabon, Equatorial Guinea and the U.S.
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
Capitalized costs:
|
|
(in thousands)
|
Properties not being amortized
|
|
$
|
15,668
|
|
$
|
15,980
|
Properties being amortized
(1)
|
|
|
389,935
|
|
|
389,231
|
Total capitalized costs
|
|
$
|
405,603
|
|
$
|
405,211
|
Less accumulated depletion, amortization and impairment
|
|
|
(384,014)
|
|
|
(379,473)
|
Net capitalized costs
|
|
$
|
21,589
|
|
$
|
25,738
|
(1)
Includes $
11.0 million
and $10.3 million asset retirement cost in
2017
and
2016
,
respectively
.
Results of Operations for Oil and Natural Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
United States
|
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
|
|
(in thousands)
|
Crude oil and natural gas sales
|
|
$
|
76,978
|
|
$
|
59,460
|
|
$
|
79,947
|
|
$
|
47
|
|
$
|
324
|
|
$
|
498
|
Production costs and other expense
(1)
|
|
|
(41,558)
|
|
|
(38,160)
|
|
|
(42,399)
|
|
|
(26)
|
|
|
(166)
|
|
|
(171)
|
Depreciation, depletion, amortization
|
|
|
(6,196)
|
|
|
(6,531)
|
|
|
(32,125)
|
|
|
(1)
|
|
|
(151)
|
|
|
(633)
|
Exploration expenses
|
|
|
(7)
|
|
|
(5)
|
|
|
(9,159)
|
|
|
—
|
|
|
—
|
|
|
(1,250)
|
Impairment of proved properties
|
|
|
—
|
|
|
—
|
|
|
(78,080)
|
|
|
—
|
|
|
(88)
|
|
|
(3,242)
|
Other operating expense
|
|
|
—
|
|
|
(8,853)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
Bad debt expense
|
|
|
(452)
|
|
|
(1,222)
|
|
|
(2,700)
|
|
|
—
|
|
|
—
|
|
|
—
|
Income tax
|
|
|
(11,638)
|
|
|
(9,248)
|
|
|
(13,238)
|
|
|
1,260
|
|
|
—
|
|
|
(1,349)
|
Results from oil and natural gas producing activities
|
|
$
|
17,127
|
|
$
|
(4,559)
|
|
$
|
(97,754)
|
|
$
|
1,280
|
|
$
|
(81)
|
|
$
|
(6,147)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Include
s
local general and administrative expenses, but excludes
corporate general and administrative expenses and allocated corporate overhead.
Estimated Quantities of
Proved Reserves
The estimation of net recoverable quantities of crude oil and natural gas is a highly technical process which is based upon several underlying assumptions that are subject to change. See “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Critical Accounting Estimates – Estimated Quantities of Net Reserves”. For a discussion of our reserve estimation process, including internal controls, see “Item 1. Business – Reserves”.
|
|
|
|
|
|
|
Oil
|
|
Natural
|
Proved reserves:
|
|
(MBbls)
|
|
Gas (MMCF)
|
Balance at January 1, 2015
|
|
8,260
|
|
1,406
|
Production
|
|
(1,659)
|
|
(181)
|
Revisions of previous estimates
|
|
(3,746)
|
|
(172)
|
Balance at December 31, 2015
|
|
2,855
|
|
1,053
|
Production
|
|
(1,518)
|
|
(124)
|
Purchases of minerals in place
|
|
308
|
|
—
|
Sales of minerals in place
|
|
(12)
|
|
(929)
|
Revisions of previous estimates
|
|
1,009
|
|
—
|
Balance at December 31, 2016
|
|
2,642
|
|
—
|
Production
|
|
(1,518)
|
|
—
|
Revisions of previous estimates
|
|
1,925
|
|
—
|
Balance at December 31, 2017
|
|
3,049
|
|
—
|
|
|
|
|
|
|
|
Oil
|
|
Natural
|
Proved developed reserves:
|
|
(MBbls)
|
|
Gas (MMCF)
|
Balance at January 1, 2015
|
|
3,224
|
|
1,406
|
Balance at December 31, 2015
|
|
2,855
|
|
1,053
|
Balance at December 31, 2016
|
|
2,642
|
|
—
|
Balance at December 31, 2017
|
|
3,049
|
|
—
|
Our proved developed reserves are
located offshore Gabon.
The upward revision of the previous estimates in 2017 was primarily a result of improved well performance and to a lesser degree the higher average crude oil prices
.
I
n 2016, reserves increased as a result of estimated proved reserve quantities related to our acquisition of the Sojitz working interest in Etame Marin block (308 MBbl) as well as upward revisions to our estimated proved reserve quantities as a result of cost cutting efforts that had the impact of driving down operating cost projections and extending economic limits, demonstration of the effectiveness of deploying lower cost hydraulic workover units to conduct workovers during 2016 and success in production optimization produced better-than-forecasted results from the prior year’s development program (1,575 MBbl). These positive developments were somewhat offset by the effects of an 18% reduction in the average price used to determine reserves in 2016 versus 2015 (566 MBbl).
The net negative revisions of previous estimates in 2015 were primarily a result of the loss of 3.5 years of production due to lower oil prices (2,705 MBOE) and the removal of sour reserves (1,440 MBbl), partially offset by positive revisions due to the performance of wells drilled in the 2014-2015 drilling campaign exceeding expectations (370 MBbl).
We maintain a policy of not booking proved reserves on discoveries until such time as a development plan has been prepared for the discovery
indicating that the development well will be drilled within five years from the date of its initial booking
. Additionally, the development plan is required to have the approval of our partners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves
The information that follows has been developed pursuant to procedures prescribed GAAP and uses reserve and production data estimated by independent petroleum consultants. The information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating us or our performance.
In accordance with the guidelines of the SEC, our estimates of future net cash flow from our properties and the present value thereof are made using oil and natural gas contract prices using a twelve month average of beginning of month prices and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The future cash flows are also based on costs in existence at the dates of the projections, excluding Gabon royalties, and the interests of other consortium members. Future production costs do not include overhead charges allowed under joint operating agreements or headquarters general and administrative overhead expenses.
However, a
ll future costs related to future
property
abandonment when the wells become uneconomic to produce
are included in future development costs for purposes of calculating the standardized measure of discounted net cash flows
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International
|
|
United States
|
|
Total
|
(In thousands)
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
Future cash inflows
|
|
$
|
165,341
|
|
$
|
106,583
|
|
$
|
140,190
|
|
$
|
—
|
|
$
|
—
|
|
$
|
3,086
|
|
$
|
165,341
|
|
$
|
106,583
|
|
$
|
143,276
|
Future production costs
|
|
|
(108,387)
|
|
|
(71,260)
|
|
|
(81,973)
|
|
|
—
|
|
|
—
|
|
|
(1,644)
|
|
|
(108,387)
|
|
|
(71,260)
|
|
|
(83,617)
|
Future development costs
(1)
|
|
|
(8,803)
|
|
|
(10,887)
|
|
|
(10,900)
|
|
|
—
|
|
|
—
|
|
|
(259)
|
|
|
(8,803)
|
|
|
(10,887)
|
|
|
(11,159)
|
Future income tax expense
|
|
|
(24,798)
|
|
|
(16,346)
|
|
|
(21,598)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(24,798)
|
|
|
(16,346)
|
|
|
(21,598)
|
Future net cash flows
|
|
|
23,353
|
|
|
8,090
|
|
|
25,719
|
|
|
—
|
|
|
—
|
|
|
1,183
|
|
|
23,353
|
|
|
8,090
|
|
|
26,902
|
Discount to present value at 10% annual rate
|
|
|
(863)
|
|
|
1,351
|
|
|
491
|
|
|
—
|
|
|
|
|
|
(252)
|
|
|
(863)
|
|
|
1,351
|
|
|
239
|
Standardized measure of discounted future net cash flows
|
|
$
|
22,490
|
|
$
|
9,441
|
|
$
|
26,210
|
|
$
|
—
|
|
$
|
—
|
|
$
|
931
|
|
$
|
22,490
|
|
$
|
9,441
|
|
$
|
27,141
|
(1)
Includes costs expected to be incurred to abandon the properties.
International income taxes represent amounts payable to the Government of Gabon on profit oil as final payment of corporate income taxes, and domestic income taxes (including other expenses treated as taxes), and domestic income taxes represent amounts payable for severance and ad-valorem taxes in Texas.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in standardized measure of discounted future net cash flows as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(in thousands)
|
Balance at beginning of period
|
|
$
|
9,441
|
|
$
|
27,141
|
|
$
|
149,387
|
Sales of oil and natural gas, net of production costs
|
|
|
(37,328)
|
|
|
(22,198)
|
|
|
(40,349)
|
Net changes in prices and production costs
|
|
|
35,257
|
|
|
(25,958)
|
|
|
(146,536)
|
Revisions of previous quantity estimates
|
|
|
18,743
|
|
|
19,558
|
|
|
(104,158)
|
Purchases
|
|
|
—
|
|
|
3,400
|
|
|
—
|
Divestitures of reserves
|
|
|
—
|
|
|
(835)
|
|
|
—
|
Changes in estimated future development costs
|
|
|
(692)
|
|
|
—
|
|
|
(15,604)
|
Development costs incurred during the period
|
|
|
2,298
|
|
|
—
|
|
|
60,004
|
Accretion of discount
|
|
|
2,482
|
|
|
4,657
|
|
|
27,312
|
Net change of income taxes
|
|
|
(7,432)
|
|
|
4,052
|
|
|
104,303
|
Change in production rates (timing) and other
|
|
|
(279)
|
|
|
(376)
|
|
|
(7,218)
|
Balance at end of period
|
|
$
|
22,490
|
|
$
|
9,441
|
|
$
|
27,141
|
There
are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown for Gabon are recoverable under a service contract and the reserves in place at the end of the contract period remain the property of the Gabon government.
In accordance with the current guidelines of the
U.S.
S
ecurities and Exchange Commission (“S
EC
”)
, estimates of future net cash flow from our properties and the present value thereof are made using an unweighted, arithmetic average of the first-day-of-the-month price for each of the 12 months
of
the year
adjusted for quality, transportation fees and market differentials
. Such prices are held constant throughout the life of the
properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. For 2017,
the average of
such prices reflected
a 33% increase
during the year and were $
53.49
per Bbl for crude oil from Gabon
when compared to the average of such prices for 2016 of $40.35 per Bbl for crude oil from Gabon.
Under the PSC in Gabon, the Gabonese government is the owner of all oil and natural gas mineral rights. The right to produce the oil and natural gas is stewarded by the Directorate Generale de Hydrocarbures and the
PSC
was awarded by a decree from the State. Pursuant to the contract, the Gabon government receives a fixed royalty rate of 13%. Originally, under the PSC, Gabonese government was not anticipated to take physical delivery of its allocated production. Instead, we were authorized to sell the Gabonese government’s share of production and remit the proceeds to the Gabonese
government. Beginning in February 2018, the Gabonese government elected to take physical delivery of its allocated production volumes for “profit oil” (see discussion below).
The consortium maintains a Cost Account, which entitles it to receive 70% of the production remaining after deducting the 13% royalty so long as there are amounts remaining in the Cost Account (“Cost Recovery”).
At December 31, 2017, there was $
9
7.6
million in the cost account net to our interest. As payment of corporate income taxes, the c
onsortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and Cost Recovery. The percentage of “profit oil” paid to the government as tax is a function of production rates. However, when the Cost Account becomes substantially recovered, we only recover ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. Also because of the nature of the Cost Account, decreases in oil prices result in a higher number of barrels required to recover costs, therefore at higher oil prices, our net reserves after taxes would decrease, but at lower prices our Cost Recovery barrels increase.
The Etame PSC allows for the carve-out of development areas which include all producing fields in the Etame Marin block. The Etame development area has a term of 20 years and will expire in 2021. The Avouma/South Tchibala field development area has a term of 20 years and will expire in 2025. The Ebouri field development area has a term of 20 years and will expire in 2026. The
balance of the Etame Marin block comprises the exploration area, which expired in July 2014. This compares to the economic end date of reserves under the current reserve report prepared by our independent reserve engineering
firm of November
20
20
.
The Mutamba Iroru PSC entitles us to receive 70% of any future production remaining after deducting the royalty so long as there are amounts remaining in the Cost Account. The Mutamba Iroru PSC provides for all commercial discoveries to be reclassified into a development area with a term of twenty years. At
December 31, 2017
, we have no proved reserves related to the Mutamba Iroru block.
The PSC for Block P in Equatorial Guinea entitles us to receive up to 70% of any future production after royalty deduction so long as there are amounts remaining in the Cost Account. Royalty rates are 10-16% depending on production rates. The consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 10% to 60% of the oil remaining after deducting the royalty and Cost Recovery. The percentage of “profit oil” paid to the government as tax is a function of cumulative production. In addition, Equatorial Guinea imposes a 25% income tax on net profits. The Block P PSC provides for a discovery to be reclassified into a development area with a term of 25 years. At
December 31, 2017
, we have no proved
reserves related to Block P in Equatorial Guinea.