Notes to the Consolidated Financial Statements
For the Years Ended
December 31, 2017
,
2016
and
2015
(Expressed in U.S. Dollars, unless otherwise indicated)
1. Description of Business
Gran Tierra Energy Inc., a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on oil and natural gas exploration and production in Colombia. The Company also had business activities in Brazil until
June 30, 2017
, and in Peru until
December 18, 2017
.
2. Significant Accounting Policies
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).
Significant accounting policies are:
Basis of consolidation
These consolidated financial statements include the accounts of the Company and its controlled subsidiaries. All intercompany accounts and transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows; depreciation, depletion, amortization and impairment (“DD&A”); impairment assessments of goodwill; timing of transfers from oil and gas properties not subject to depletion to the depletable base; asset retirement obligations; determining the value of the consideration transferred and the net identifiable assets acquired and liabilities assumed in connection with business combinations and determining goodwill; assessments of the likely outcome of legal and other contingencies; income taxes; stock-based compensation; and determining the fair value of derivatives and investment. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates.
Cash and cash equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted cash and cash equivalents
Restricted cash and cash equivalents comprises cash and cash equivalents pledged to secure letters of credit and to settle asset retirement obligations. Letters of credit currently secured by cash relate to work commitment guarantees contained in exploration contracts. Restrictions will lapse when work obligations are satisfied pursuant to the exploration contract or an asset retirement obligation is settled. Cash and claims to cash that are restricted as to withdrawal or use for other than current operations or are designated for expenditure in the acquisition or construction of long-term assets are excluded from the current asset classification. The long term portion of restricted cash and cash equivalents is included in other long-term assets on the Company's balance sheet.
Allowance for doubtful accounts
The Company estimates losses on receivables based on known uncollectible accounts, if any, and historical experience of losses incurred and accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. The allowance for doubtful receivables was
nil
at
December 31, 2017
and
2016
.
Equity method investment
During December 2017, the Company acquired an investment in common shares of Sterling in connection with the sale of its Peru business unit (Note 5). At December 31, 2017, this investment represented approximately
46%
of Sterling's issued and outstanding common shares. The Company determined that it did not have a controlling financial interest in Sterling, but could exert significant influence over Sterling's operating and financial policies as a result of its ownership interest in Sterling and the right to nominate
two
directors to Sterling's board of directors. Accordingly, Gran Tierra accounted for its investment in the common shares of Sterling as an equity method investment, but elected the fair value option for this investment to reflect the value that market participants would use to value the investment. The fair value of the investment in Sterling's common shares is recorded in 'Investments' in the consolidated balance sheet, and the change in fair value is recorded in the consolidated statement of operations as financial instruments gains or losses.
Derivatives
The Company records derivative instruments on its balance sheet at fair value as either an asset or liability with changes in fair value recognized in the consolidated statements of operations as financial instruments gains or losses. While the Company utilizes derivative instruments to manage the price risk attributable to its expected oil production and foreign exchange risk, it has elected not to designate its derivative instruments as accounting hedges under the accounting guidance.
Inventory
Inventory consists of oil in tanks and third party pipelines and supplies and is valued at the lower of cost and net realizable value. The cost of inventory is determined using the weighted average method. Oil inventories include expenditures incurred to produce, upgrade and transport the product to the storage facilities and include operating, depletion and depreciation expenses and cash royalties.
Income taxes
Income taxes are recognized using the liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax base, and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. Valuation allowances are provided if, after considering available evidence, it is not more likely than not that some or all of the deferred tax assets will be realized.
The tax benefit from an uncertain tax position is recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit recognized is the largest amount of benefit that has a greater than
50%
likelihood of being realized upon ultimate settlement. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The Company recognizes potential penalties and interest related to unrecognized tax benefits as a component of income tax expense.
Oil and gas properties
The Company uses the full cost method of accounting for its investment in oil and natural gas properties as defined by the Securities and Exchange Commission (“SEC”). Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. Costs associated with production and general corporate activities; however, are expensed as incurred. Separate cost centers are maintained for each country in which the Company incurs costs.
The Company computes depletion of oil and natural gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Future development costs related to properties with proved reserves are also included in the amortization base for computation of depletion. The costs of unproved properties are excluded from the amortization base until the properties are evaluated. The cost of exploratory dry wells is transferred to proved properties, and thus is subject to amortization, immediately upon determination that a well is dry in those countries where proved reserves exist.
The Company performs a ceiling test calculation each quarter in accordance with SEC Regulation S-X Rule 4-10. In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and
natural gas properties, net of accumulated depletion and deferred income taxes, to the estimated future net cash flows from proved oil and natural gas reserves discounted at
10%
, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to net income or loss. Any such write-down will reduce earnings in the period of occurrence and results in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
The Company calculates future net cash flows by applying the unweighted average of prices in effect on the first day of the month for the preceding 12-month period, adjusted for location and quality differentials. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts.
Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the depletable base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. This evaluation considers, among other factors, seismic data, requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to depletion. For countries where a reserve base has not yet been established, the impairment is charged to earnings.
In exploration areas, related seismic costs are capitalized in unproved property and evaluated as part of the total capitalized costs associated with a property. Seismic costs related to development projects are recorded in proved properties and therefore subject to depletion as incurred.
Gains and losses on the sale or other disposition of oil and natural gas properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.
Asset retirement obligation
The Company records an estimated liability for future costs associated with the abandonment of its oil and gas properties including the costs of reclamation of drilling sites. The Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with an offsetting increase to the related oil and gas properties. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets. The accretion of the asset retirement obligation and amortization of the asset retirement cost are included in DD&A. If estimated future costs of an asset retirement obligation change, an adjustment is recorded to both the asset retirement obligation and oil and gas properties. Revisions to the estimated asset retirement obligation can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Other capital assets
Other capital assets, including additions and replacements, are recorded at cost upon acquisition and include furniture, fixtures and leasehold improvement, computer equipment and automobiles. Depreciation is provided using the declining-balance method at a
30%
annual rate for furniture and fixtures, computer equipment and automobiles. Leasehold improvements are depreciated on a straight-line basis over the shorter of the estimated useful life and the term of the related lease. The cost of repairs and maintenance is charged to expense as incurred.
Goodwill
Goodwill represents the excess of the aggregate of the consideration transferred over the net identifiable assets acquired and liabilities assumed. The Company assesses qualitative factors annually, or more frequently if necessary, to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether it is necessary to perform the goodwill impairment test. The impairment test requires allocating goodwill and certain other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared with its net book value. An impairment loss is recognized if the estimated fair value of the reporting unit is less than its carrying amount, not exceeding the carrying amount of goodwill allocated to that reporting unit. Because quoted market prices are not available for the Company’s
reporting unit, the fair value of the reporting unit is estimated based upon estimated future cash flows of the reporting unit. The goodwill relates entirely to the Colombia reportable segment. The Company performed a qualitative assessment of goodwill at
December 31, 2017
, and based on this assessment,
no
impairment of goodwill was identified.
Convertible Notes
The Company accounts for its
5.00%
Convertible Senior Notes due 2021 (the "Convertible Notes") as a liability in their entirety. The embedded features of the Convertible Notes were assessed for bifurcation from the Convertible Notes under the applicable provisions, including the basic conversion feature, the fundamental change make-whole provision and the put and call options. Based on an assessment, the Company concluded that these embedded features did not meet the criteria to be accounted for separately.
The Company incurred debt issuance costs in connection with the issuance of the Convertible Notes which have been presented as a direct deduction against the carrying amount of the Convertible Notes and are being amortized to interest expense using the effective interest method over the contractual term of the Convertible Notes.
Revenue recognition
Revenue from the production of oil and natural gas is recognized when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable, the sale is evidenced by a contract and collection of the revenue is reasonably assured.
Revenue represents the Company’s share and is recorded net of royalty payments to governments and other mineral interest owners.
Stock-based compensation
The Company records stock-based compensation expense in its consolidated financial statements measured at the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes-Merton or Monte Carlo simulation stock option-pricing models and/or observable share prices. For equity-settled stock-based compensation awards, fair values are determined at the grant date and the expense, net of estimated forfeitures, is recognized using the accelerated method over the requisite service period. An adjustment is made to compensation expense for any difference between the estimated forfeitures and the actual forfeitures. For cash-settled stock-based compensation awards, fair values are determined at each reporting date and periodic changes are recognized as compensation costs, with a corresponding change to liabilities.
The Company uses historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of the Company’s shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.
Stock-based compensation expense is capitalized as part of oil and natural gas properties or expensed as part of general and administrative (“G&A”) or operating expenses, as appropriate.
Foreign currency translation
The functional currency of the Company, including its subsidiaries, is the United States dollar. Monetary items are translated into the reporting currency at the exchange rate in effect at the balance sheet date and non-monetary items are translated at historical exchange rates. Revenue and expense items are translated in a manner that produces substantially the same reporting currency amounts that would have resulted had the underlying transactions been translated on the dates they occurred.
DD&A expense on assets is translated at the historical exchange rates similar to the assets to which they relate. Gains and losses resulting from foreign currency transactions, which are transactions denominated in a currency other than the entity’s functional currency, are recognized in net income or loss.
Loss per share
Basic loss per share is calculated by dividing loss attributable to common shareholders by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income or loss per
share is calculated by adjusting the weighted average number of shares of Common Stock and exchangeable shares outstanding for the dilutive effect, if any, of share equivalents. The Company uses the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume weighted average trading price of shares of Common Stock during the period.
Recently Adopted Accounting Pronouncements
Simplifying the Measurement of Inventory
In July 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-11, “Simplifying the Measurement of Inventory". The ASU provides guidance for the subsequent measurement of inventory and requires that inventory that is measured using average cost be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The implementation of this update did not have an impact on the Company’s consolidated financial position, results of operations or cash flows or disclosure.
Employee Share-Based Payment Accounting
In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting
".
This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company elected to continue to estimate the total number of awards for which the requisite service period will not be rendered. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.
Income Taxes - Intra-Entity Transfers of Assets Other than Inventory
At December 31, 2016, GAAP prohibited the recognition of current and deferred income taxes for intra-entity transfers until an asset leaves the consolidated group, therefore, the current income tax effect of tax reorganizations completed in 2016 was deferred and recognized as prepaid income taxes. At December 31, 2016, the Company's balance sheet included
$54.1 million
of prepaid income taxes,
$12.3 million
in current prepaid taxes and
$41.8 million
in long-term prepaid taxes, and
$37.5 million
of current income taxes payable relating to tax reorganizations completed in 2016.
In October 2016, the FASB issued ASU 2016-16, "Intra-Entity Transfers of Assets Other than Inventory." This ASU requires companies to recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the income statement as income tax expense or benefit in the period the sale or transfer occurs. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption was permitted as of the beginning of an annual reporting period. The ASU is required to be applied on a modified retrospective basis with a cumulative-effect adjustment directly to retained earnings in the period of adoption. The Company early adopted this ASU on January 1, 2017, and in the three months ending March 31, 2017, wrote off the income tax effects that had been deferred from past intercompany transactions to opening deficit. A total of
$124.5 million
, representing deferred tax assets of
$178.6 million
, net of
$54.1 million
of prepaid tax, was recorded directly to opening deficit at January 1, 2017. Deferred tax assets recorded upon adoption were assessed for realizability under Accounting Standards Codification ("ASC") 740 "Income Taxes", and, valuation allowances were recognized on those deferred tax assets as necessary on the date of adoption. The adoption of ASU 2016-16 did not have any effect on the Company’s cash flows.
Restricted Cash and Cash Equivalents
In November 2016, the FASB issued ASU 2016-18, "Restricted Cash". ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted. The Company early adopted this ASU on January 1, 2017, on a retrospective basis to each period presented. The implementation of this ASU did not impact the Company's consolidated financial position or results of operations. For the
year ended
December 31, 2016
, the net decrease in cash, cash equivalents and restricted cash and cash equivalents currently disclosed was
$105.5 million
, compared with the net decrease in cash and cash equivalents of
$120.2 million
as previously disclosed in the consolidated statement of cash flows
prior to the adoption of ASU 2016-18. For the
year ended
December 31, 2015
, the net decrease in cash, cash equivalents and restricted cash and cash equivalents currently disclosed was
$187.0 million
, compared with the net decrease in cash and cash equivalents of
$186.5 million
as previously disclosed in the consolidated statement of cash flows prior to the adoption of ASU 2016-18.
Clarifying the Definition of a Business
In January 2017, the FASB issued ASU 2017-01, "Clarifying the Definition of a Business". ASU 2017-01 narrows the definition of a business and provides a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. ASU 2017-01 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted and the Company adopted this ASU on January 1, 2017. The Company now applies an initial screen for determining whether a transaction involves an asset or a business. When substantially all of the fair value of the gross assets acquired is concentrated in a single identified asset, or group of similar identifiable assets, the set will not be a business and no goodwill or gain on acquisition will be recognized. If the screen is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create an output. The Company’s acquisition of the Santana and Nancy Burdine-Maxine oil and gas properties during the
year ended December 31, 2017
was not considered a business under this ASU and therefore not allocated goodwill or gain on acquisition (Note 5).
Simplifying the Test for Goodwill Impairment
In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment". ASU 2017-04 eliminates step 2 of the goodwill impairment test. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2019. Early adoption is permitted. At December 31, 2017, the Company performed a qualitative assessment of goodwill and, based on this assessment, no impairment of goodwill was identified.
Recently Issued Accounting Pronouncements
Revenue from Contracts with Customers
In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers - Deferral of the Effective Date”. The ASU deferred the effective date of the new revenue recognition model by one year. As a result, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance on principal versus agent considerations. In April, May and December 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients” and ASU 2016-20 “Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers”, respectively, which addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings.
The Company has completed its evaluation of the impact of the ASU and has reviewed its various revenue streams and underlying contracts. The Company adopted the new standard using the modified retrospective method at the date of adoption, January 1, 2018. Adoption of the ASU did not have a material impact on the Company’s consolidated financial statements, other than enhanced disclosure related to revenues from contracts with customers as prescribed by ASU.
Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities". ASU 2016-01 addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. ASU 2016-01 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. This ASU is not expected to have a material impact on the Company's consolidated financial position, results of operations or cash flows or disclosure.
Leases
In February 2016, the FASB issued ASU 2016-02, “Leases". This ASU will require most lease assets and lease liabilities to be
recognized on the balance sheet and the disclosure of key information about lease arrangements. The ASU will be effective for
fiscal years, and interim periods within those years, beginning after December 15, 2018. The Company is currently assessing
the impact the new lease standard will have on its consolidated financial position, results of operations, cash flows, and disclosure.
Financial Instruments - Credit Losses
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses". This ASU replaces the current incurred
loss impairment methodology with a methodology that reflects expected credit losses and requires a broader range of
reasonable and supportable information to support credit loss estimates. The ASU will be effective for fiscal years, and interim
periods within those years, beginning after December 15, 2019. The Company is currently assessing the impact this update will
have on its consolidated financial position, results of operations, cash flows, and disclosure.
3. Segment and Geographic Reporting
The Company is primarily engaged in the exploration and production of oil and natural gas. The Company has one reportable segment based on geographic organization, Colombia. Prior to the sale of the Company's Brazil business unit effective
June 30, 2017
and its Peru business unit effective
December 18, 2017
, Brazil and Peru were reportable segments. The "All Other" category represents the Company’s corporate, Brazil and Peru activities until the date of sale. The Company evaluates reportable segment performance based on income or loss before income taxes.
The following tables present information on the Company’s reportable segment and other activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2017
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
|
All Other
|
|
|
Total
|
|
Oil and natural gas sales
|
$
|
413,316
|
|
|
$
|
8,418
|
|
|
$
|
421,734
|
|
DD&A expenses
|
126,453
|
|
|
4,882
|
|
|
131,335
|
|
Asset impairment
|
—
|
|
|
1,514
|
|
|
1,514
|
|
General and administrative expenses
|
23,500
|
|
|
15,514
|
|
|
39,014
|
|
Interest expense
|
486
|
|
|
13,396
|
|
|
13,882
|
|
Loss on sale
|
—
|
|
|
(44,385
|
)
|
|
(44,385
|
)
|
Income (loss) before income taxes
|
111,829
|
|
|
(74,499
|
)
|
|
37,330
|
|
Segment capital expenditures
|
242,636
|
|
|
8,405
|
|
|
251,041
|
|
|
Year Ended December 31, 2016
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
|
All Other
|
|
|
Total
|
|
Oil and natural gas sales
|
$
|
280,872
|
|
|
$
|
8,397
|
|
|
$
|
289,269
|
|
DD&A expenses
|
132,569
|
|
|
6,966
|
|
|
139,535
|
|
Asset impairment
|
514,314
|
|
|
102,335
|
|
|
616,649
|
|
General and administrative expenses
|
17,187
|
|
|
16,031
|
|
|
33,218
|
|
Interest expense
|
—
|
|
|
14,145
|
|
|
14,145
|
|
Gain on acquisition
|
—
|
|
|
929
|
|
|
929
|
|
Loss before income taxes
|
(505,447
|
)
|
|
(144,787
|
)
|
|
(650,234
|
)
|
Segment capital expenditures
|
105,963
|
|
|
21,826
|
|
|
127,789
|
|
|
Year Ended December 31, 2015
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
|
All Other
|
|
|
Total
|
|
Oil and natural gas sales
|
$
|
269,035
|
|
|
$
|
6,976
|
|
|
$
|
276,011
|
|
DD&A expenses
|
167,701
|
|
|
8,685
|
|
|
176,386
|
|
Asset impairment
|
235,069
|
|
|
88,849
|
|
|
323,918
|
|
General and administrative expenses
|
9,805
|
|
|
22,548
|
|
|
32,353
|
|
Loss before income taxes
|
(238,463
|
)
|
|
(129,625
|
)
|
|
(368,088
|
)
|
Segment capital expenditures
|
85,326
|
|
|
71,313
|
|
|
156,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2017
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
|
All Other
|
|
|
Total
|
|
Property, plant and equipment
|
$
|
1,096,833
|
|
|
$
|
2,391
|
|
|
$
|
1,099,224
|
|
Goodwill
|
102,581
|
|
|
—
|
|
|
$
|
102,581
|
|
All other assets
|
176,980
|
|
|
50,834
|
|
|
$
|
227,814
|
|
Total Assets
|
$
|
1,376,394
|
|
|
$
|
53,225
|
|
|
$
|
1,429,619
|
|
|
|
|
|
|
|
|
As at December 31, 2016
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
|
All Other
|
|
|
Total
|
|
Property, plant and equipment
|
$
|
939,947
|
|
|
$
|
126,662
|
|
|
$
|
1,066,609
|
|
Goodwill
|
102,581
|
|
|
—
|
|
|
$
|
102,581
|
|
All other assets
|
177,393
|
|
|
21,313
|
|
|
$
|
198,706
|
|
Total Assets
|
$
|
1,219,921
|
|
|
$
|
147,975
|
|
|
$
|
1,367,896
|
|
The following table presents the number of customers from whom the Company derived 10% or more of its consolidated oil and gas sales and sales as a percentage of the Company's consolidated oil and gas sales to each customer. All of these customers were in the Company's Colombian reportable segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Number of significant customers
|
3
|
|
3
|
|
4
|
Sales to each significant customer as % of oil and gas sales
|
44
|
%
|
31
|
%
|
17
|
%
|
|
40
|
%
|
34
|
%
|
13
|
%
|
|
43
|
%
|
15
|
%
|
13
|
%
|
12
|
%
|
4. Accounts Receivable
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Trade
|
$
|
37,794
|
|
|
$
|
39,203
|
|
Other
|
7,559
|
|
|
6,495
|
|
|
$
|
45,353
|
|
|
$
|
45,698
|
|
5. Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Oil and natural gas properties
|
|
|
|
|
Proved
|
$
|
2,810,796
|
|
|
$
|
2,652,171
|
|
Unproved
|
464,948
|
|
|
647,774
|
|
|
3,275,744
|
|
|
3,299,945
|
|
Other
|
26,401
|
|
|
29,445
|
|
|
3,302,145
|
|
|
3,329,390
|
|
Accumulated depletion, depreciation and impairment
|
(2,202,921
|
)
|
|
(2,262,781
|
)
|
|
$
|
1,099,224
|
|
|
$
|
1,066,609
|
|
Depletion and depreciation expense on property, plant and equipment for the
year ended
December 31, 2017
, was
$126.8 million
(
year ended
December 31, 2016
-
$130.2 million
;
year ended
December 31, 2015
-
$177.9 million
). A portion of depletion and depreciation expense was recorded as inventory in each year and adjusted for inventory changes.
Asset impairment for the three years ended December 31,
2017
, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Impairment of oil and gas properties
|
$
|
1,514
|
|
|
$
|
615,985
|
|
|
$
|
321,285
|
|
Impairment of inventory
|
—
|
|
|
664
|
|
|
2,633
|
|
|
$
|
1,514
|
|
|
$
|
616,649
|
|
|
$
|
323,918
|
|
In the year ended
December 31, 2016
, the Company recorded ceiling test impairment losses of
$513.7 million
in its Colombia cost center, and
$71.1 million
in its Brazil cost center. The Colombia ceiling test impairment loss related to lower oil prices and the fact that the acquisitions of PetroLatina and PetroAmerica were initially added into the cost base at estimated fair value. However, these acquired assets were subjected to a prescribed U.S. GAAP ceiling test, which is not a fair value test, and which, as noted below, uses constant commodity pricing that averages prices during the preceding 12 months. The Brazil ceiling test impairment loss related to continued low oil prices and increased costs in the depletable base as a result of a
$45.0 million
impairment of unproved properties.
In the year ended
December 31, 2015
, the Company recorded ceiling test impairment losses of
$232.4 million
in its Colombia cost center, and
$46.9 million
in its Brazil cost center as a result of lower realized prices.
The Company follows the full cost method of accounting for its oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at
10%
per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at
10%
per year and it should not be assumed that estimates of future net revenues represent the fair market value of the Company's reserves. In accordance with GAAP, Gran Tierra used an average Brent price of
$54.19
per bbl for the purposes of the December 31,
2017
ceiling test calculations (September 30, 2017 -
52.70
, June 30, 2017 -
$51.35
, March 31, 2017 -
$49.33
; December 31,
2016
-
$42.92
; September 30, 2016 -
$42.23
; June 30, 2016 -
$44.48
, March 31, 2016 -
$48.79
; December 31, 2015 -
$54.08
).
In the years ended December 31,
2016
and
2015
, the Company recorded impairment losses of
$31.2 million
and
$41.9 million
, respectively, related to costs incurred on Block 95 and other blocks in Peru. On February 19, 2015, the Company made the decision to cease all further development expenditures on the Bretaña Field on Block 95 other than what is necessary to maintain tangible asset integrity and security.
Acquisition of Santana and Nancy Burdine-Maxine Blocks
On
April 27, 2017
, the Company acquired the Santana and Nancy-Burdine-Maxine Blocks in the Putumayo Basin for cash consideration of
$30.4 million
. The acquisition was accounted for as an asset acquisition with the consideration paid allocated on a relative fair value basis to the net assets acquired.
The following table shows the allocation of the cost of the acquisition based on the relative fair values of the assets and
liabilities acquired:
|
|
|
|
|
(Thousands of U.S. Dollars)
|
|
Cost of asset acquisition:
|
|
Cash
|
$
|
30,410
|
|
|
|
Allocation of Consideration Paid:
|
|
Oil and gas properties
|
|
Proved
|
$
|
24,405
|
|
Unproved
|
8,649
|
|
|
33,054
|
|
Inventory
|
869
|
|
Asset retirement obligation - long-term
|
(3,513
|
)
|
|
$
|
30,410
|
|
Acquisition of PGC
On January 25, 2016, the Company acquired all of the issued and outstanding common shares of PGC, pursuant to the terms and conditions of an acquisition agreement dated January 14, 2016. Upon completion of the transaction, PGC became an indirect wholly-owned subsidiary of Gran Tierra. The net purchase price of PGC was
$19.4 million
, after giving consideration to net working capital of
$18.3 million
. The acquisition was accounted for as an asset acquisition with the excess consideration paid over the fair value of the net assets acquired allocated on a relative fair value basis to the net assets acquired.
|
|
|
|
|
(Thousands of U.S. Dollars)
|
|
Cost of asset acquisition:
|
|
Cash
|
$
|
37,727
|
|
|
|
Allocation of Consideration Paid:
|
|
Oil and gas properties
|
|
Proved
|
$
|
12,228
|
|
Unproved
|
15,563
|
|
|
27,791
|
|
Net working capital (including cash acquired of $0.2 million and restricted cash of $18.6 million)
|
18,339
|
|
Asset retirement obligation - long-term
|
(8,403
|
)
|
|
$
|
37,727
|
|
Property acquisitions in the year ended
December 31, 2017
included
$4.0 million
of contingent consideration related to the 2016 acquisition of PGC. The contingent consideration was subject to Gran Tierra reaching a certain level of production plus gross proved plus probable reserves in the Putumayo-7 Block and was payable at December 31, 2017. The Company recognized contingent consideration in accounts payable and accrued liabilities on its balance sheet as at
December 31, 2017
.
Disposition of Peru Business Unit
On December 18, 2017, Gran Tierra completed the sale of its Peru business unit. Pursuant to the divestiture, Sterling acquired all of the issued and outstanding shares in Gran Tierra's indirect, wholly owned subsidiary that indirectly held all of its Peruvian assets for aggregate consideration of
$33.5 million
, comprised of approximately
187.3 million
common shares of Sterling and an estimated cash-settled working capital adjustment of
$0.4 million
. Escrow conditions are applicable to
90%
of the share consideration, which will be released from escrow at
15%
every
6
months for
36
months following December 18, 2017. Additionally, in connection with the divestiture, Gran Tierra purchased
$11.0 million
of subscription receipts which were exchangeable for common shares of PetroTal Ltd. and subsequently exchanged them for approximately
58.9 million
common shares of Sterling. After giving effect to the divestiture, Gran Tierra directly and indirectly holds approximately
246.2 million
common shares representing approximately
46%
of Sterling's issued and outstanding common shares. Sterling is a junior oil and gas company focused on development of oil and gas assets in Peru.
In connection with the divestiture, Gran Tierra, through two of its indirect, wholly owned subsidiaries, entered into an investor rights agreement with Sterling, pursuant to which, Gran Tierra has the right to nominate two directors to the board of Sterling, as well as certain demand and piggy-back registration rights and certain pre-emptive rights, subject to the terms and conditions set forth in the investor rights agreement. Gran Tierra is prohibited from exercising voting rights over more than
30%
of the issued and outstanding Sterling Common Shares. In addition, Gran Tierra, through its indirect, wholly-owned subsidiary, entered into a carried interest and option agreement with Sterling and a Peruvian subsidiary, pursuant to which Gran Tierra has a
20%
carried working interest in Block 107, located in the Ucayali basin in Peru, which interest may, at the option of Gran Tierra, either be converted to a non-carried working interest or be forfeited following the drilling of an exploration well in Block 107.
At December 18, 2017, the net book value of the Peru business unit was greater than proceeds received resulting in a
$34.1 million
loss on sale.
At December 31, 2016, assets and liabilities of the Peru business unit were as follows:
|
|
|
|
|
(Thousands of U.S. Dollars)
|
As at December 31, 2016
|
Current assets
|
$
|
1,051
|
|
Property, plant and equipment
|
68,428
|
|
Other long-term assets
|
9,799
|
|
|
$
|
79,278
|
|
|
|
Current liabilities
|
$
|
(940
|
)
|
Long-term liabilities
|
(13,370
|
)
|
|
$
|
(14,310
|
)
|
Disposition of Brazil Business Unit
On June 30, 2017, the Company, through
two
of its indirect subsidiaries (the “Selling Subsidiaries”), completed the previously announced disposition of its assets in Brazil. Gran Tierra completed the disposition of its Brazil business unit for a purchase price of
$35.0 million
, which, after certain final closing adjustments, resulted in cash consideration paid to the Selling Subsidiaries of approximately
$36.8 million
.
At June 30, 2017, the net book value of the Brazil business unit was greater than proceeds received resulting in a
$10.2 million
loss on sale.
At December 31, 2016, assets and liabilities of the Brazil business unit were as follows:
|
|
|
|
|
(Thousands of U.S. Dollars)
|
As at December 31, 2016
|
Current assets
|
$
|
1,634
|
|
Property, plant and equipment
|
55,376
|
|
|
$
|
57,010
|
|
|
|
Current liabilities
|
$
|
(11,590
|
)
|
Long-term liabilities
|
(2,297
|
)
|
|
$
|
(13,887
|
)
|
Other
During the
year ended
December 31, 2016
, Gran Tierra sold non-operated and non-core assets in Colombia to a third party for cash consideration of
$6.0 million
.
Unproved oil and natural gas properties
At December 31, 2017, unproved oil and natural gas properties consist of exploration lands held in Colombia. Unproved oil and natural gas properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration warrants whether or not future areas will be developed. The Company expects that approximately
76%
of costs not subject to depletion at
December 31, 2017
, will be transferred to the depletable base within the next
five
years and the remainder in the next
five
to
10
years.
The following is a summary of Gran Tierra’s oil and natural gas properties not subject to depletion as at
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred in
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
|
2015
|
|
Prior to 2015
|
|
Total
|
Acquisition costs - Colombia
|
$
|
8,076
|
|
|
$
|
319,025
|
|
|
$
|
—
|
|
|
$
|
33,080
|
|
|
$
|
360,181
|
|
Exploration costs - Colombia
|
52,769
|
|
|
10,124
|
|
|
8,795
|
|
|
33,079
|
|
|
104,767
|
|
|
$
|
60,845
|
|
|
$
|
329,149
|
|
|
$
|
8,795
|
|
|
$
|
66,159
|
|
|
$
|
464,948
|
|
6. Debt and Debt Issuance Costs
The Company's debt at December 31,
2017
and
2016
, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
|
2017
|
|
2016
|
Convertible Notes (a)
|
|
$
|
115,000
|
|
|
$
|
115,000
|
|
Revolving credit facility (b)
|
|
148,000
|
|
|
90,000
|
|
Unamortized debt issuance costs
|
|
(6,458
|
)
|
|
(7,917
|
)
|
Long-term debt
|
|
$
|
256,542
|
|
|
$
|
197,083
|
|
a) Convertible Notes
At
December 31, 2017
, the Company had
$115 million
of Convertible Notes outstanding. The Convertible Notes bear interest at a rate of
5.00%
per year, payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2016. The Convertible Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted. The Convertible Notes are unsecured and are subordinated to secured debt to the extent of the value of the assets securing such indebtedness.
The Convertible Notes are convertible at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date. The conversion rate is initially
311.4295
shares of Common Stock per
$1,000
principal amount of Convertible Notes (equivalent to an initial conversion price of approximately
$3.21
per share of Common Stock). The conversion rate is subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase the conversion rate for a holder who elects to convert its Convertible Notes in connection with such a corporate event in certain circumstances.
The Company may not redeem the Convertible Notes prior to April 5, 2019, except in certain circumstances following a fundamental change (as defined in the indenture governing the Convertible Notes). The Company may redeem for all cash or any portion of the Convertible Notes, at its option, on or after April 5, 2019, if (terms below are as defined in the indenture governing the Convertible Notes):
(i) the last reported sale price of the Company's Common Stock has been at least
150%
of the conversion price then in effect for at least
20
trading days (whether or not consecutive) during any
30
consecutive trading day period (including the last trading day of such period) ending on, and including, the trading day immediately preceding the date on which the Company provides notice of redemption; and
(ii) the Company has filed all reports that it is required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, as applicable (other than current reports on Form 8-K), during the twelve months preceding the date on which the Company provides such notice.
The redemption price will be equal to
100%
of the principal amount of the Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. No sinking fund is provided for the Convertible Notes.
If the Company undergoes a fundamental change, holders may require the Company to repurchase for cash all or any portion of their Convertible Notes at a fundamental change repurchase price equal to
100%
of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.
Net proceeds from the sale of the Convertible Notes were
$109.1 million
, after deducting the initial purchasers' discount and the offering expenses payable by the Company.
b) Credit Facility
At
December 31, 2017
, the Company had a revolving credit facility with a syndicate of lenders with a borrowing base of
$300 million
. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. On November 10, 2017, as a result of the Ninth Amendment to the credit agreement, the borrowing base of
$300 million
was reaffirmed and, among other things, the maturity date of the borrowing under the revolving credit facility was extended from October 1, 2018 to November 10, 2020.
T
he next re-determination of the borrowing base is due to occur no later than May 2018.
Amounts drawn down under the revolving credit facility bear interest, at the Company's option, at the USD LIBOR rate plus a margin ranging from
2.15%
to
3.65%
(
December 31, 2016
-
2.00%
to
3.00%
), or an alternate base rate plus a margin ranging from
1.15%
to
2.65%
, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. At
December 31, 2017
the weighted-average interest rate on the balance outstanding on the Company's revolving credit facility was approximately
3.64%
. Undrawn amounts under the revolving credit facility bear interest from
0.54%
to
0.91%
(
December 31, 2016
-
0.75%
) per annum, based on the average daily amount of unused commitments. A letter of credit participation fee of
0.25%
per annum will accrue on the average daily amount of letter of credit exposure.
The Company’s revolving credit facility is guaranteed by and secured against the assets of certain of the Company’s subsidiaries (the "Credit Facility Group"). Under the terms of the credit facility, the Company is subject on certain restrictions on its ability to distribute funds to entities outside of the Credit Facility Group, including restrictions on the ability to pay dividends to shareholders of the Company.
c) Interest expense
The following table presents total interest expense recognized in the accompanying consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
|
2015
|
Contractual interest and other financing expenses
|
$
|
11,467
|
|
|
$
|
8,454
|
|
|
$
|
—
|
|
Amortization of debt issuance costs
|
2,415
|
|
|
5,691
|
|
|
—
|
|
|
$
|
13,882
|
|
|
$
|
14,145
|
|
|
$
|
—
|
|
The Company incurred debt issuance costs in connection with the issuance of the Convertible Notes and its revolving credit facility. As at December 31,
2017
, the balance of unamortized debt issuance costs has been presented as a direct deduction against the carrying amount of debt and is being amortized to interest expense using the effective interest method over the term of the debt.
7. Share Capital
The Company’s authorized share capital consists of
595,000,002
shares of capital stock, of which
570 million
are designated as Common Stock, par value
$0.001
per share,
25 million
are designated as Preferred Stock, par value
$0.001
per share, and
two
shares are designated as special voting stock, par value
$0.001
per share.
As at
December 31, 2017
, outstanding share capital consists of
385,191,042
shares of Common Stock of the Company,
4,422,776
exchangeable shares of Gran Tierra Exchangeco Inc., (the "Exchangeco exchangeable shares") and
1,688,889
exchangeable shares of Gran Tierra Goldstrike Inc. (the "Goldstrike exchangeable shares"). The Exchangeco exchangeable shares were issued upon the acquisition of Solana. The Goldstrike exchangeable shares were issued upon the business combination between Gran Tierra Energy Inc., an Alberta corporation, and Goldstrike, Inc., which is now the Company. The redemption date for the Exchangeco exchangeable shares and the Goldstrike exchangeable shares is a date to be established by the applicable Board of Directors.
The holders of shares of Common Stock are entitled to
one
vote for each share on all matters submitted to a stockholder vote and are entitled to share in all dividends that the Company’s Board of Directors, in its discretion, declares from legally available funds. The holders of Common Stock have no pre-emptive rights, no conversion rights, and there are no redemption provisions applicable to the shares. Holders of exchangeable shares have substantially the same rights as holders of shares of Common Stock. Each exchangeable share is exchangeable into
one
share of Common Stock of the Company.
|
|
|
|
|
|
|
|
|
|
|
Shares of Common Stock
|
|
Exchangeable Shares of Gran Tierra Exchangeco Inc.
|
|
Exchangeable Shares of Gran Tierra Goldstrike Inc.
|
Balance, December 31, 2016
|
390,807,194
|
|
|
4,812,592
|
|
|
3,387,302
|
|
Exchange of exchangeable shares
|
2,088,229
|
|
|
(389,816
|
)
|
|
(1,698,413
|
)
|
Shares repurchased and canceled
|
(7,704,381
|
)
|
|
—
|
|
|
—
|
|
Balance, December 31, 2017
|
385,191,042
|
|
|
4,422,776
|
|
|
1,688,889
|
|
Share Repurchase Program
On February 6, 2017, the Company announced that it had implemented a share repurchase program (the “2017 Program”) through the facilities of the Toronto Stock Exchange (“TSX”), the NYSE American and eligible alternative trading platforms in Canada and the United States. Under the 2017 Program, the Company is able to purchase at prevailing market prices up to
19,540,359
shares of Common Stock, representing
5.0%
of the issued and outstanding shares of Common Stock as of January 27, 2017. Shares purchased pursuant to the 2017 Program will be canceled. The 2017 Program expired on February 7, 2018.
Equity Compensation Awards
The Company has an equity compensation program in place for its executives and employees. Equity compensation grants vest either based solely on recipient's continued employment or achievement of certain key measures of performance. Equity awards consist
80%
of Performance Stock Units (“PSUs”) and
20%
of stock options. The Company’s equity compensation awards outstanding as at
December 31, 2017
, include PSUs, deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock options.
In accordance with the 2007 Equity Incentive Plan, the Company’s Board of Directors is authorized to issue options or other rights to acquire shares of the Company’s Common Stock. On June 27, 2012, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from
23,306,100
shares to
39,806,100
shares.
The following table provides information about PSU, DSU, RSU and stock option activity for the
year ended
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSUs
|
DSUs
|
RSUs
|
|
Stock Options
|
|
Number of Outstanding Share Units
|
Number of Outstanding Share Units
|
Number of Outstanding Share Units
|
|
Number of Outstanding Stock Options
|
|
Weighted Average Exercise Price /Stock Option ($)
|
Balance, December 31, 2016
|
3,362,717
|
|
208,698
|
|
359,145
|
|
|
9,239,478
|
|
|
$
|
4.16
|
|
Granted
|
3,422,170
|
|
247,070
|
|
—
|
|
|
2,029,035
|
|
|
2.54
|
|
Exercised
|
—
|
|
—
|
|
(224,548
|
)
|
|
—
|
|
|
—
|
|
Forfeited
|
(652,936
|
)
|
—
|
|
(12,507
|
)
|
|
(911,154
|
)
|
|
(4.79
|
)
|
Expired
|
—
|
|
—
|
|
—
|
|
|
(1,396,667
|
)
|
|
(4.65
|
)
|
Balance, December 31, 2017
|
6,131,951
|
|
455,768
|
|
122,090
|
|
|
8,960,692
|
|
|
$
|
3.65
|
|
Exercisable, at December 31, 2017
|
|
|
|
|
5,044,267
|
|
|
$
|
4.33
|
|
Vested, or expected to vest, at December 31, 2017, through the life of the options
|
|
|
|
|
8,792,816
|
|
|
$
|
3.67
|
|
Stock-based compensation expense for the year ended
December 31, 2017
, was
$9.8 million
(
December 31, 2016
-
$6.3 million
;
December 31, 2015
-
$2.7 million
) and was primarily recorded in G&A expenses.
At
December 31, 2017
, there was
$13.7 million
(
December 31, 2016
-
$10.0 million
) of unrecognized compensation cost related to unvested PSUs, RSUs and stock options which is expected to be recognized over a weighted average period of
1.6
years. The weighted-average remaining contractual term of options vested, or expected to vest, at
December 31, 2017
was
2.9
years.
PSUs
PSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company's
Common Stock upon vesting of such units or a cash payment equal to the value of the underlying shares. PSUs will cliff vest
after
three
years, subject to the continued employment of the grantee. The number of PSUs that vest may range from
zero
to
200%
of the target number granted based on the Company’s performance with respect to the applicable performance targets. The performance targets for the PSUs outstanding as at
December 31, 2017
, were as follows:
(i)
50%
of the award is subject to targets relating to the total shareholder return (“TSR”) of the Company against a group of
peer companies
(ii)
25%
of the award is subject to targets relating to net asset value ("NAV") of the Company per share and NAV is based on
before tax net present value discounted at
10%
of proved plus probable reserves; and
(iii)
25%
of the award is subject to targets relating to the execution of corporate strategy.
The compensation cost of PSUs is subject to adjustment based upon the attainability of these performance targets. No
settlement will occur with respect to the portion of the PSU award subject to each performance target for results below the
applicable minimum threshold for that target. PSUs in excess of the target number granted will vest and be settled if
performance exceeds the targeted performance goals. The Company currently intends to settle the PSUs in cash.
DSUs and RSUs
DSUs and RSUs entitle the holder to receive, either the underlying number of shares of the Company's Common Stock upon
vesting of such units or, at the option of the Company, a cash payment equal to the value of the underlying shares. The
Company's historic practice has been to settle RSUs in cash and the Company currently intends to settle the RSUs and DSUs
outstanding as at
December 31, 2017
in cash, and, therefore, DSUs and RSUs are accounted for as liability instruments. Once a DSU or RSU is vested, it is immediately settled. During the year ended
December 31, 2017
, DSUs were granted to directors and will vest
100%
at such time the grantee ceases to be a member of the Board of Directors. For the year ended
December 31, 2017
, the Company paid
$0.6 million
to cash settle RSUs (
2016
-
$1.2 million
and
2015
- $
1.4 million
).
Stock Options
Each stock option permits the holder to purchase
one
share of Common Stock at the stated exercise price. The exercise price equals the market price of a share of Common Stock at the time of grant. Stock options generally vest over
three
years. The term of stock options granted starting in May of 2013 is
five
years or
three
months after the grantee’s end of service to the Company, whichever occurs first. Stock options granted prior to May of 2013 continue to have a term of
ten
years or
three
months after the end of the grantee’s service to the Company, whichever occurs first.
For the year ended
December 31, 2017
,
no
stock options were exercised and
no
cash proceeds were received (
2016
–
2,165,370
options exercised and shares issued;
2015
–
390,000
options exercised and shares issued).
At
December 31, 2017
, the weighted average remaining contractual term of outstanding stock options was
2.9
years and of
exercisable stock options was
2.5
years.
The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Dividend yield (per share)
|
Nil
|
|
|
Nil
|
|
|
Nil
|
|
Volatility
|
51% to 53%
|
|
|
50% to 54%
|
|
|
46% to 50%
|
|
Weighted average volatility
|
52
|
%
|
|
52
|
%
|
|
48
|
%
|
Risk-free interest rate
|
1.75% to 2.10%
|
|
|
0.94% to 1.78%
|
|
|
1.20% to 1.68%
|
|
Expected term
|
4-5 years
|
|
|
4-5 years
|
|
|
4-5 years
|
|
The weighted average grant date fair value for options granted in the
year ended
December 31, 2017
, was
$1.11
(
2016
-
$1.14
;
2015
-
$1.24
). The weighted average grant date fair value for options vested in the
year ended
December 31, 2017
, was
$1.31
(
2016
-
$1.52
;
2015
-
$2.38
). The total fair value of stock options vested during
year ended
December 31, 2017
, was
$2.5 million
(
2016
-
$2.8 million
;
2015
-
$6.8 million
).
Weighted Average Shares Outstanding
For the
year ended
December 31, 2017
,
9,681,304
options, on a weighted average basis, (
2016
-
10,662,034
options;
2015
-
13,432,287
options) were excluded from the diluted loss per share calculation as the options were anti-dilutive.
8. Asset Retirement Obligation
Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Balance, beginning of year
|
$
|
43,357
|
|
|
$
|
33,224
|
|
Liability incurred
|
3,403
|
|
|
2,606
|
|
Settlements
|
(1,507
|
)
|
|
(872
|
)
|
Accretion
|
3,825
|
|
|
2,789
|
|
Revisions in estimated liability
|
(4,095
|
)
|
|
(6,856
|
)
|
Liabilities associated with assets sold
|
(16,932
|
)
|
|
(3,257
|
)
|
Liabilities assumed in acquisitions
|
3,513
|
|
|
15,723
|
|
Balance, end of year
|
$
|
31,564
|
|
|
$
|
43,357
|
|
|
|
|
|
Asset retirement obligation - current
|
$
|
323
|
|
|
$
|
5,215
|
|
Asset retirement obligation - long-term
|
31,241
|
|
|
38,142
|
|
Balance, end of year
|
$
|
31,564
|
|
|
$
|
43,357
|
|
For the
year ended December 31, 2017
, settlements included cash payments of
$1.3 million
with the balance in accounts payable and accrued liabilities at
December 31, 2017
(
December 31, 2016
-
$0.6 million
). Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling asset retirement obligations. At
December 31, 2017
, the fair value of assets that were legally restricted for purposes of settling asset retirement obligations was
$12.7 million
(
December 31, 2016
-
$12.0 million
). These assets were accounted for as restricted cash and cash equivalents on the Company's balance sheet.
9. Taxes
The income tax expense reported differs from the amount computed by applying the U.S. statutory rate to loss before income taxes for the following reasons:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
|
2015
|
Income (Loss) before income taxes
|
|
|
|
|
|
United States
|
$
|
(51,215
|
)
|
|
$
|
(23,986
|
)
|
|
$
|
(14,061
|
)
|
Foreign
|
88,545
|
|
|
(626,248
|
)
|
|
(354,027
|
)
|
|
37,330
|
|
|
(650,234
|
)
|
|
(368,088
|
)
|
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
Income tax expense (recovery) expected
|
13,066
|
|
|
(227,582
|
)
|
|
(128,831
|
)
|
Impact of foreign taxes
(1)
|
12,310
|
|
|
(9,799
|
)
|
|
(13,087
|
)
|
Other local taxes
|
1,056
|
|
|
1,998
|
|
|
2,354
|
|
Stock-based compensation
|
2,001
|
|
|
1,955
|
|
|
919
|
|
Increase in valuation allowance
|
52,269
|
|
|
47,675
|
|
|
37,691
|
|
Sale of Peru and Brazil business units
|
(12,527
|
)
|
|
—
|
|
|
—
|
|
Non-deductible third party royalty in Colombia
|
3,194
|
|
|
2,550
|
|
|
3,416
|
|
Other permanent differences
|
(2,331
|
)
|
|
(1,466
|
)
|
|
(2,521
|
)
|
Total income tax expense (recovery)
|
$
|
69,038
|
|
|
$
|
(184,669
|
)
|
|
$
|
(100,059
|
)
|
|
|
|
|
|
|
Current income tax expense
|
|
|
|
|
|
United States
|
$
|
3,457
|
|
|
$
|
1,818
|
|
|
$
|
1,070
|
|
Foreign
|
20,865
|
|
|
18,304
|
|
|
14,313
|
|
|
24,322
|
|
|
20,122
|
|
|
15,383
|
|
Deferred income tax expense (recovery)
|
|
|
|
|
|
Foreign
(2)
|
44,716
|
|
|
(204,791
|
)
|
|
(115,442
|
)
|
Total income tax expense (recovery)
|
$
|
69,038
|
|
|
$
|
(184,669
|
)
|
|
$
|
(100,059
|
)
|
(1)
Impact of foreign taxes in the rate reconciliation are tax effected at the
35%
statutory rate and were primarily due to higher income tax rates in Colombia. Impact of foreign taxes for the years ended
December 31, 2017
,
2016
and
2015
, included
$8.0 million
(expense),
$23.3 million
(recovery) and
$11.8 million
(recovery), respectively, in Colombia.
(2)
The deferred tax recovery for the year ended
December 31, 2016
, included
$201.3 million
associated with the ceiling test impairment loss in Colombia.
Undistributed earnings of foreign subsidiaries as of
December 31, 2017
, were considered to be permanently reinvested. A determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.
In the fourth quarter of 2016, the Colombian government approved tax legislation consolidating the corporate Income and CREE taxes into a single income tax at 40% for 2017 (including a surtax of 6%), 37% for 2018 (including a surtax of 4%) and 33% for 2019 and onwards. The tax rates applied to the calculation of deferred income taxes, before valuation allowances, have been adjusted to reflect these changes. In the same legislation, the Colombian government also instituted a 5% dividend tax on distributions of previously taxed earnings from 2017 and onwards. The Law also increased the corporate minimum presumptive income tax from 3% to 3.5%. The tax is imposed on a taxpayer’s net equity at the prior year-end when the presumptive income exceeds actual taxable profits.
The US government enacted the Tax Cuts and Jobs Act of 2017 (“TCJA”) on December 22, 2017. As of December 31, 2017, the Company is still evaluating the complete tax effects of the enactment of the TCJA. However, the Company has determined a reasonable estimate of the impact of the TCJA on its existing deferred tax balances and the one-time transition tax. Based on this estimate, the Company has determined that the there is no current tax expense impact to its financial statements as a result of the TCJA. The Company has also calculated an estimated deferred tax asset impact of
$59 million
, which is subject to a full valuation allowance because its recognition does not meet the “more-likely-than-not” threshold. Of the estimated amount,
$1.1 million
relates to the remeasurement of certain deferred tax assets and liabilities based on the rate at which they are expected to reverse in the future.
As noted above, the Company is still evaluating the complete tax effects of the enactment of the TCJA and there are a number of uncertainties and ambiguities as to the interpretation and application of many of the provisions in the TCJA. In the absence
of guidance on these matters and until the 2017 tax returns are finalized, which the Company expects to occur in October 2018, the Company expects to use what it believes are reasonable interpretations and assumptions in applying the TCJA for purposes of determining its cash tax liabilities and results of operations, which may change as it receives additional clarification and implementation guidance. Despite the fact that the Company has not prepared its tax returns for 2017, and therefore cannot provide a final estimate of 2017 foreign earning and profits, but considering the consistency of the Company’s 2017 foreign operations with prior years, the Company’s overall analysis of the one-time transition tax has not identified, nor does it expect to identify, any overall material adverse effect on its tax liability and financial condition.
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Deferred Tax Assets
|
|
|
|
|
|
Tax benefit of operating loss carryforwards
|
$
|
60,460
|
|
|
$
|
74,604
|
|
Tax basis in excess of book basis
|
62,768
|
|
|
187,651
|
|
Foreign tax credits and other accruals
|
70,157
|
|
|
48,341
|
|
Tax benefit of capital loss carryforwards
|
52,575
|
|
|
32,278
|
|
Deferred tax assets before valuation allowance
|
245,960
|
|
|
342,874
|
|
Valuation allowance
|
(188,650
|
)
|
|
(341,263
|
)
|
|
57,310
|
|
|
1,611
|
|
Deferred Tax Liabilities
|
28,417
|
|
|
107,230
|
|
Net Deferred Tax Assets (Liabilities)
(1)
|
$
|
28,893
|
|
|
$
|
(105,619
|
)
|
(1)
Effective November 1, 2016, several of Gran Tierra's subsidiaries executed intercompany sale agreements whereby certain depreciable assets were transferred within the consolidated Gran Tierra group. The purpose of the transaction was to improve the efficiency of Gran Tierra's operating and tax structures. The restructuring resulted in a consolidation of certain assets into a single entity in Colombia, an increase in the depreciable tax basis of the assets transferred, and current income taxes payable as at December 31, 2016, as a result of the capital gains taxes incurred. GAAP prohibited the recognition of current and deferred income taxes for intra-entity transfers until an asset leaves the consolidated group, therefore, the current and deferred income tax effect of the restructuring was deferred and recognized as prepaid income taxes at December 31, 2016. At January 1, 2017, the impact of the November 1, 2016, intercompany asset transfers was recognized pursuant to adoption of ASU 2016-16 (Note 2), which resulted in a material increase in the tax basis of certain Colombian assets. Accordingly, for 2017, this resulted in the Company realizing a change in its net deferred balance from a deferred tax liability at
December 31, 2016
, to a deferred tax asset at
December 31, 2017
.
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Operating loss carryforwards
|
$
|
199,138
|
|
|
$
|
257,023
|
|
Capital loss carryforwards
|
$
|
288,322
|
|
|
$
|
239,095
|
|
Of the operating loss and capital loss carryforwards, losses generated by the foreign subsidiaries of the Company.
|
$
|
392,053
|
|
|
$
|
496,118
|
|
In certain jurisdictions, operating loss carryforwards expire between
2018
and 2037, while certain other jurisdictions allow operating losses to be carried forward indefinitely. Capital losses can be carried forward indefinitely.
The valuation allowance decreased by
$152.6 million
during the year ended
December 31, 2017
. The change in the valuation allowance was primarily due to
$212.1 million
decrease as a result of the sale of Peru and Brazil business units.This is partially offset by
$86.7 million
increase in capital losses generated in Luxembourg as a result of the sale of Brazil,
$20.9 million
increase in foreign tax credits in the U.S. arising from the U.S. legislated one-time deemed repatriation of foreign earning,
$7.1 million
increase in tax basis as a result of the 2016 intercompany asset transfers recognized on January 1, 2017, pursuant to adoption of ASU 2016-16 and
$10.2 million
of losses incurred in the U.S., Colombia and Canada as well as other credits. These future tax benefits are fully off-set by valuation allowances, as their recognition does not meet the “more-likely-than-not” threshold.
The Company and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and certain other foreign jurisdictions. The Company is potentially subject to income tax examinations for open tax years 2009 through 2016 in certain
jurisdictions. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the consolidated statement of operations.
On December 23, 2014, the Colombian Congress passed legislation which imposed an equity tax levied on Colombian operations for 2015, 2016 and 2017. The equity tax was calculated based on a legislated measure, which was based on the Company’s Colombian legal entities' balance sheet equity for tax purposes at January 1, 2015. This measure was subject to adjustment for inflation in future years. The equity tax rates for January 1, 2015, 2016 and 2017, were
1.15%
,
1%
and
0.4%
, respectively. The legal obligation for each year's equity tax liability arose on January 1 of each year; therefore, the Company recognized the annual amount of
$1.2 million
,
$3.1 million
and
$3.8 million
for the equity tax expense in the consolidated statement of operations for the years ended
December 31, 2017
,
2016
and
2015
. These amounts were paid in May and September of each year and at
December 31, 2017
, accounts payable included
nil
(
December 31, 2016
-
nil
).
10. Accounts Payable and Accrued Liabilities
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Trade
|
$
|
99,146
|
|
|
$
|
80,072
|
|
Royalties
|
6,867
|
|
|
4,542
|
|
Employee compensation
|
8,767
|
|
|
8,152
|
|
Other
|
11,391
|
|
|
14,285
|
|
|
$
|
126,171
|
|
|
$
|
107,051
|
|
11. Commitments and Contingencies
Purchase Obligations, Firm Agreements and Leases
As at
December 31, 2017
, future minimum payments under non-cancelable agreements with remaining terms in excess of one year were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ending December 31
|
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
(Thousands of U.S. Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil transportation services
|
$
|
10,895
|
|
|
$
|
3,842
|
|
|
$
|
3,842
|
|
|
$
|
3,211
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Facility construction
|
27,006
|
|
|
5,446
|
|
|
5,446
|
|
|
5,461
|
|
|
5,446
|
|
|
5,207
|
|
|
—
|
|
Operating leases
|
4,554
|
|
|
1,840
|
|
|
1,267
|
|
|
1,240
|
|
|
207
|
|
|
—
|
|
|
—
|
|
Software and telecommunication
|
961
|
|
|
339
|
|
|
320
|
|
|
302
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
43,416
|
|
|
$
|
11,467
|
|
|
$
|
10,875
|
|
|
$
|
10,214
|
|
|
$
|
5,653
|
|
|
$
|
5,207
|
|
|
$
|
—
|
|
Gran Tierra leases certain office space, compressors, vehicles, equipment and housing. Total rent expense for the
year ended
December 31, 2017
, was
$3.2 million
(
year ended
December 31, 2016
–
$3.2 million
;
year ended
December 31, 2015
-
$4.0 million
).
Indemnities
Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated. The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid.
Letters of credit
At
December 31, 2017
, the Company had provided promissory notes totaling
$76.0 million
(
December 31, 2016
-
$96.8 million
) as security for letters of credit relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.
Contingencies
The ANH and Gran Tierra are engaged in ongoing discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Based on the Company's understanding of the ANH's position, the estimated compensation, which would be payable if the ANH’s interpretation is correct, could be up to
$50.8 million
as at
December 31, 2017
. At this time,
no
amount has been accrued in the consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.
In addition to the above, Gran Tierra has a number of lawsuits and claims pending. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, Gran Tierra believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Gran Tierra records costs as they are incurred or become probable and determinable.
12. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk
Financial Instruments
At
December 31, 2017
, the Company’s financial instruments recognized in the balance sheet consist of; cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; investments; derivatives; accounts payable and accrued liabilities; long-term debt; PSU liability included in other long-term liabilities; and RSU liability included in accounts payable and accrued liabilities and other long-term liabilities.
Fair Value Measurement
The fair value of investment, derivatives and RSU and PSU liabilities are being remeasured at the estimated fair value at the end of each reporting period.
The fair value of the short-term portion of the investment which was received as consideration on the sale of the Company's Peru business unit was estimated using quoted prices at December 31, 2017 and the market exchange rate at that time. The fair value of the long-term portion of the investment restricted by escrow conditions was estimated using observable and unobservable inputs; factors that were evaluated included quoted market prices, precedent comparable transactions, risk free rate, measures of market risk volatility, estimates of the Company's and Sterling’s cost of capital and quotes from third parties.
The fair value of commodity price and foreign currency derivatives is estimated based on various factors, including quoted
market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the
reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of
whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally,
the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its
potential repayment obligations associated with the derivative transactions.
The fair value of the RSU liability was estimated based on quoted market prices in an active market. The fair value of the PSU
liability was estimated based on option pricing model using the inputs, such as quoted market prices in an active market, and PSU performance factor.
The fair value of investments, derivatives, RSU, PSU and DSU liabilities at
December 31, 2017
, and
December 31, 2016
were as follows:
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Investment - current and long-term assets
|
$
|
44,202
|
|
|
$
|
—
|
|
Foreign currency derivative asset
|
302
|
|
|
578
|
|
|
$
|
44,504
|
|
|
$
|
578
|
|
|
|
|
|
Commodity price derivative liability
|
$
|
21,151
|
|
|
$
|
3,824
|
|
RSU, PSU and DSU liability
|
11,430
|
|
|
3,907
|
|
|
$
|
32,581
|
|
|
$
|
7,731
|
|
The following table presents losses or gains on financial instruments recognized in the accompanying consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Commodity price derivative loss
|
$
|
17,327
|
|
|
$
|
7,370
|
|
|
$
|
—
|
|
Foreign currency derivative (gain) loss
|
(1,287
|
)
|
|
(1,016
|
)
|
|
692
|
|
Investment gain
|
(111
|
)
|
|
—
|
|
|
—
|
|
Trading securities loss
|
—
|
|
|
3,925
|
|
|
1,335
|
|
|
$
|
15,929
|
|
|
$
|
10,279
|
|
|
$
|
2,027
|
|
These gains or losses are presented as financial instruments loss in the consolidated statements of operations and cash flows.
Investment gain related to fair value gains on the Sterling shares Gran Tierra received in connection with the sale of its Peru business unit in December 2017 (Note 5). For the year ended
December 31, 2017
these investment gains were unrealized.
All trading securities were sold during the year ended December 31, 2016, and the trading securities loss represented a realized loss. The cash proceeds were included in cash flows from investing activities in the Company's consolidated statements of cash flows because these securities were received in connection with the sale of the Company's Argentina business unit in 2014. For the year ended December 31, 2015, the trading securities loss represented an unrealized loss.
Financial instruments not recorded at fair value include the Convertible Notes (Note 6). At
December 31, 2017
, the carrying amount of the Convertible Notes was
$111.0 million
, which represents the aggregate principal amount less unamortized debt issuance costs, and the fair value was
$129.1 million
. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.
At
December 31, 2017
, the fair value of current portion of the investment, RSU and DSU liability was determined using Level 1 inputs, the fair value of derivatives and PSUs was determined using Level 2 inputs and the fair value of the long-term portion of the investment restricted by escrow conditions was determined using Level 3 inputs. The table below presents a roll-forward of the long-term portion of the investment:
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
Opening balance
|
$
|
—
|
|
|
$
|
—
|
|
Acquisition
|
19,091
|
|
|
—
|
|
Unrealized gain on valuation
|
56
|
|
|
—
|
|
Closing balance
|
$
|
19,147
|
|
|
$
|
—
|
|
The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt
is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the
difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk.
The credit spread (premium or discount) is determined by comparing the Company’s Convertible Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure in the paragraph above regarding the fair value of the Company’s revolving credit facility was determined using an income approach using Level 3 inputs. The disclosure in the paragraph above regarding the fair value of the Convertible Notes was determined using Level 2 inputs based on the indicative pricing published by certain investment banks or trading levels of the Convertible Notes, which are not listed on any securities exchange or quoted on an inter-dealer automated quotation system. The disclosure in the paragraph above regarding the fair value of cash and cash equivalents and restricted cash and cash equivalents was based on Level 1 inputs.
The Company’s non-recurring fair value measurements include asset retirement obligations. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. The significant level 3 inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free interest rate, inflation rates and estimated dates of abandonment. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets.
Commodity Price Derivatives
The Company utilizes commodity price derivatives to manage the variability in cash flows associated with the forecasted sale of its oil production, reduce commodity price risk and provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.
At
December 31, 2017
, the Company had outstanding commodity price derivative positions as follows:
|
|
|
|
|
|
|
|
|
|
|
Period and type of instrument
|
Volume,
bopd
|
Reference
|
Sold Swap ($/bbl, Weighted Average)
|
Purchased Call ($/bbl, Weighted Average)
|
Swaps: January 1, to December 31, 2018
|
5,000
|
|
ICE Brent
|
$
|
55.90
|
|
n/a
|
|
Participating Swaps: January 1, to December 31, 2018
|
5,000
|
|
ICE Brent
|
$
|
52.50
|
|
$
|
56.11
|
|
Foreign Exchange Risk and Foreign Currency Derivatives
The Company utilizes foreign currency derivatives to manage the variability in cash flows associated with the Company's forecasted Colombian peso ("COP") denominated expenses, predominantly operating costs, general and administrative costs and transportation costs.
At
December 31, 2017
, the Company had outstanding foreign currency derivative positions as follows:
|
|
|
|
|
|
|
|
|
|
|
Period and type of instrument
|
Amount Hedged
(Millions COP)
|
U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)
|
Reference
|
Purchased Call
(COP)
|
Sold Put (COP, Weighted Average)
|
Collars: January 1, 2018 to December 31, 2018
|
174,000
|
|
58,311
|
|
COP
|
3,000
|
|
3,107
|
|
The Company's cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company's derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. These cash settlements were included in cash flows from operating activities in the Company's consolidated statements of cash flows.
While the use of these derivative instruments may limit or partially reduce the downside risk of adverse commodity price and foreign exchange movements, their use also may limit future income and gains from favorable commodity price and foreign exchange movements.
Unrealized foreign exchange gains and losses primarily result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, which are monetary liabilities mainly denominated in the local currency of the Colombian operations. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at
$10,000
for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar
.
This effect was calculated based on the Company's
December 31, 2017
, deferred tax balances.
For the
year ended
December 31, 2017
,
98%
(
year ended
December 31, 2016
-
97%
,
year ended
December 31, 2015
-
97%
) of the Company's oil and natural gas sales were generated in Colombia. In Colombia, the Company receives
100%
of its revenues in U.S. dollars and the majority of its capital expenditures are in U.S. dollars or are based on U.S. dollar prices.
Credit Risk
Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, restricted cash and accounts receivable. The carrying value of cash and cash equivalents, restricted cash and accounts receivable reflects management’s assessment of credit risk
.
At
December 31, 2017
, cash and cash equivalents and restricted cash included balances in bank accounts, term deposits and certificates of deposit, placed with financial institutions with investment grade credit ratings.
Most of the Company’s accounts receivable relate to uncollateralized sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. For the
year ended
December 31, 2017
, the Company had
three
customers which were significant to the Colombian segment.
To reduce the concentration of exposure to any individual counterparty, the Company utilizes a group of investment-grade rated financial institutions, for its derivative transactions. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments.
13. Supplemental Cash Flow Information
The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company's consolidated balance sheet that sum to the total of the same such amounts shown in the consolidated statements of cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
As at December 31,
|
|
2017
|
|
2016
|
|
2015
|
Cash and cash equivalents
|
$
|
12,326
|
|
|
$
|
25,175
|
|
|
$
|
145,342
|
|
Restricted cash and cash equivalents - current
|
11,787
|
|
|
8,322
|
|
|
92
|
|
Restricted cash and cash equivalents - long-term
(1)
|
2,565
|
|
|
9,770
|
|
|
3,317
|
|
|
$
|
26,678
|
|
|
$
|
43,267
|
|
|
$
|
148,751
|
|
(1)
The long-term portion of restricted cash is included in other long-term assets on the Company's balance sheet.
Net changes in assets and liabilities from operating activities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Accounts receivable and other long-term assets
|
$
|
(2,494
|
)
|
|
$
|
(29
|
)
|
|
$
|
44,365
|
|
Derivatives
|
—
|
|
|
(3,546
|
)
|
|
—
|
|
Inventory
|
(78
|
)
|
|
5,510
|
|
|
(1,571
|
)
|
Other prepaids
|
2,674
|
|
|
(615
|
)
|
|
152
|
|
Accounts payable and accrued and other long-term liabilities
|
15,617
|
|
|
(9,691
|
)
|
|
(33,743
|
)
|
Prepaid tax and taxes receivable and payable
|
(44,936
|
)
|
|
(2,966
|
)
|
|
(48,251
|
)
|
Net changes in assets and liabilities from operating activities
|
$
|
(29,217
|
)
|
|
$
|
(11,337
|
)
|
|
$
|
(39,048
|
)
|
The following table provides additional supplemental cash flow disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
Cash paid for income taxes
|
$
|
54,505
|
|
|
$
|
64,067
|
|
|
$
|
39,422
|
|
Cash paid for interest
|
$
|
9,684
|
|
|
$
|
5,624
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Non-cash investing activities:
|
|
|
|
|
|
|
|
Net liabilities related to property, plant and equipment, end of year
|
$
|
76,352
|
|
|
$
|
55,181
|
|
|
$
|
33,923
|
|
See Note 5 in these consolidated financial statements for disclosure regarding non-cash share consideration received in connection with the Company's disposition of its Peru Business unit. In the year ended December 31, 2016, the purchase price paid for acquisition of Petroamerica Oil Corp. included
$25.8 million
of Gran Tierra's Common Stock.
14. Subsequent Event
On
February 15
, 2018, Gran Tierra Energy International Holdings Ltd., an indirect, wholly owned subsidiary of the Company, issued
$300 million
aggregate principal amount of its
6.25%
Senior Notes due 2025 (the "2025 Notes") in a private placement transaction. The 2025 Notes bear interest at a rate of
6.25%
per year, payable semi-annually in arrears on
February 15
and
August 15
of each year, beginning on
August 15, 2018
. The 2025 Notes will mature on
February 15, 2025
, unless earlier redeemed or repurchased.
Supplementary Data (Unaudited)
1) Oil and Gas Producing Activities
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the U.S. Securities and Exchange Commission (SEC), the Company is making certain supplemental disclosures about its oil and gas exploration and production operations.
A. Estimated Proved NAR Reserves
The following table sets forth Gran Tierra's estimated proved NAR reserves and total net proved developed and undeveloped reserves as of
December 31, 2014
,
2015
,
2016
and
2017
, and the changes in total net proved reserves during the three-year period ended
December 31, 2017
.
The net proved reserves represent management’s best estimate of proved oil and natural gas reserves after royalties. Reserve estimates for each property are prepared internally each year and 100% of the reserves at
December 31, 2017
, have been evaluated by independent qualified reserves consultants,
McDaniel & Associates Consultants Ltd.
The reserve estimation process requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property, and demonstrate reasonable certainty that they are recoverable from known reservoirs under economic and operating conditions that existed at year end. The determination of oil and natural gas reserves is complex and requires significant judgment. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. The process of estimating oil and gas reserves is complex and requires significant judgment, as discussed in Item 1A. “Risk Factors”. See “Critical Accounting Estimates” in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for a description of Gran Tierra’s reserves estimation process.
|
|
|
|
|
|
|
|
|
|
Colombia
|
|
|
Liquids
(1)
|
|
Gas
|
|
|
(Mbbl)
|
|
(MMcf)
|
Proved NAR Reserves, December 31, 2014
|
|
34,044
|
|
|
983
|
|
Extensions and discoveries
|
|
410
|
|
|
526
|
|
Production
|
|
(6,872
|
)
|
|
(318
|
)
|
Revisions of previous estimates
|
|
5,804
|
|
|
632
|
|
Proved NAR Reserves, December 31, 2015
|
|
33,386
|
|
|
1,823
|
|
Purchases of reserves in place
|
|
20,568
|
|
|
—
|
|
Extensions and discoveries
|
|
1,142
|
|
|
435
|
|
Production
|
|
(8,125
|
)
|
|
(592
|
)
|
Revisions of previous estimates
|
|
(1,093
|
)
|
|
(71
|
)
|
Proved NAR Reserves, December 31, 2016
|
|
45,878
|
|
|
1,595
|
|
Purchases of reserves in place
|
|
2,041
|
|
|
—
|
|
Extensions and discoveries
|
|
9,543
|
|
|
—
|
|
Improved recoveries
|
|
2,461
|
|
|
—
|
|
Technical revisions
|
|
7,627
|
|
|
1,077
|
|
Discoveries
|
|
873
|
|
|
—
|
|
Production
|
|
(9,469
|
)
|
|
(588
|
)
|
Proved NAR Reserves, December 31, 2017
|
|
58,954
|
|
|
2,084
|
|
|
|
|
|
|
Proved Developed Reserves NAR, December 31, 2015
|
|
28,513
|
|
|
1,346
|
|
Proved Developed Reserves NAR, December 31, 2016
|
|
35,529
|
|
|
1,468
|
|
Proved Developed Reserves NAR, December 31, 2017
|
|
39,487
|
|
|
1,431
|
|
|
|
|
|
|
Proved Undeveloped Reserves NAR, December 31, 2015
|
|
4,873
|
|
|
477
|
|
Proved Undeveloped Reserves NAR, December 31, 2016
|
|
10,349
|
|
|
127
|
|
Proved Undeveloped Reserves NAR, December 31, 2017
|
|
19,467
|
|
|
653
|
|
(1)
At
December 31, 2017
,
2016
,
2015
and
2014
, liquids reserves are 100% oil.
B. Capitalized Costs
Capitalized costs for Gran Tierra's oil and gas producing activities consisted of the following at the end of each of the years in the two-year period ended
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Proved Properties
|
|
Unproved Properties
|
|
Accumulated
Depletion,
Depreciation
and
Impairment
|
|
Net Capitalized Costs
|
Colombia
|
$
|
2,810,796
|
|
|
$
|
464,948
|
|
|
$
|
(2,181,715
|
)
|
|
$
|
1,094,029
|
|
Balance, December 31, 2017
|
$
|
2,810,796
|
|
|
$
|
464,948
|
|
|
$
|
(2,181,715
|
)
|
|
$
|
1,094,029
|
|
|
|
|
|
|
|
|
|
Colombia
|
$
|
2,435,124
|
|
|
$
|
561,463
|
|
|
$
|
(2,059,073
|
)
|
|
$
|
937,514
|
|
Brazil
|
217,047
|
|
|
18,445
|
|
|
(180,779
|
)
|
|
54,713
|
|
Peru
|
—
|
|
|
67,866
|
|
|
—
|
|
|
67,866
|
|
Balance, December 31, 2016
|
$
|
2,652,171
|
|
|
$
|
647,774
|
|
|
$
|
(2,239,852
|
)
|
|
$
|
1,060,093
|
|
C. Costs Incurred
The following tables present costs incurred for Gran Tierra's oil and gas property acquisitions, exploration and development for the respective years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
|
Colombia
|
|
Brazil
|
|
Peru
|
|
Total
|
Balance, December 31, 2014
|
|
$
|
1,795,532
|
|
|
$
|
200,406
|
|
|
$
|
394,531
|
|
|
$
|
2,390,469
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
Proved
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Unproved
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration costs
|
|
17,512
|
|
|
12,466
|
|
|
50,347
|
|
|
80,325
|
|
Development costs
|
|
69,910
|
|
|
7,472
|
|
|
—
|
|
|
77,382
|
|
Balance, December 31, 2015
|
|
1,882,954
|
|
|
220,344
|
|
|
444,878
|
|
|
2,548,176
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
Proved
|
|
408,793
|
|
|
—
|
|
|
—
|
|
|
408,793
|
|
Unproved
|
|
500,081
|
|
|
—
|
|
|
—
|
|
|
500,081
|
|
Exploration costs
|
|
33,362
|
|
|
6,086
|
|
|
4,985
|
|
|
44,433
|
|
Development costs
|
|
72,601
|
|
|
9,060
|
|
|
—
|
|
|
81,661
|
|
Balance, December 31, 2016
|
|
2,897,791
|
|
|
235,490
|
|
|
449,863
|
|
|
3,583,144
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
Proved
|
|
28,405
|
|
|
1,565
|
|
|
—
|
|
|
29,970
|
|
Unproved
|
|
8,649
|
|
|
—
|
|
|
4,314
|
|
|
12,963
|
|
Exploration costs
|
|
64,003
|
|
|
—
|
|
|
—
|
|
|
64,003
|
|
Development costs
|
|
171,498
|
|
|
—
|
|
|
|
|
171,498
|
|
Balance, December 31, 2017
|
|
$
|
3,170,346
|
|
|
$
|
237,055
|
|
|
$
|
454,177
|
|
|
$
|
3,861,578
|
|
D. Results of Operations for Oil and Gas Producing Activities
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Colombia
|
Year Ended December 31, 2017
|
|
Oil and natural gas sales
|
$
|
413,316
|
|
Production costs
|
(132,829
|
)
|
Exploration expenses
|
—
|
|
DD&A expenses
|
(126,453
|
)
|
Asset Impairment
|
—
|
|
Income tax expense
|
(64,000
|
)
|
Results of Operations
|
$
|
90,034
|
|
|
|
Year Ended December 31, 2016
|
|
Oil and natural gas sales
|
$
|
280,872
|
|
Production costs
|
(116,141
|
)
|
Exploration expenses
|
—
|
|
DD&A expenses
|
(132,569
|
)
|
Asset Impairment
|
(514,314
|
)
|
Income tax expense
|
187,168
|
|
Results of Operations
|
$
|
(294,984
|
)
|
|
|
Year Ended December 31, 2015
|
|
Oil and natural gas sales
|
$
|
269,035
|
|
Production costs
|
(109,406
|
)
|
Exploration expenses
|
—
|
|
DD&A expenses
|
(167,701
|
)
|
Asset Impairment
|
(235,069
|
)
|
Income tax expense
|
102,014
|
|
Results of Operations
|
$
|
(141,127
|
)
|
E. Standardized Measure of Discounted Future Net Cash Flows and Changes
The following disclosure is based on estimates of net proved reserves and the period during which they are expected to be produced. Future cash inflows are computed by applying the twelve month period unweighted arithmetic average of the price as of the first day of each month within that twelve month period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions to Gran Tierra’s after royalty share of estimated annual future production from proved oil and gas reserves.
|
|
|
|
|
|
|
|
|
Colombia
|
Brazil
|
Twelve month period unweighted arithmetic average of the wellhead price as of the first day of each month within the twelve month period
|
|
|
2017
|
$
|
43.00
|
|
$
|
—
|
|
2016
|
$
|
31.67
|
|
$
|
31.42
|
|
2015
|
$
|
43.51
|
|
$
|
37.72
|
|
Weighted average production costs
|
|
|
2017
|
$
|
15.73
|
|
$
|
—
|
|
2016
|
$
|
15.42
|
|
$
|
12.19
|
|
2015
|
$
|
12.11
|
|
$
|
8.30
|
|
Future development and production costs to be incurred in producing and further developing the proved reserves are based on year end cost indicators. Future income taxes are computed by applying year end statutory tax rates. These rates reflect allowable deductions and tax credits, and are applied to the estimated pre-tax future net cash flows. Discounted future net cash flows are calculated using 10% mid-year discount factors. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proved to be the case in the past. Other assumptions could give rise to substantially different results.
The Company believes this information does not in any way reflect the current economic value of its oil and gas producing properties or the present value of their estimated future cash flows as:
|
|
•
|
no economic value is attributed to probable and possible reserves;
|
|
|
•
|
use of a 10% discount rate is arbitrary; and
|
|
|
•
|
prices change constantly from the twelve month period unweighted arithmetic average of the price as of the first day of each month within that twelve month period.
|
The standardized measure of discounted future net cash flows from Gran Tierra's estimated proved oil and gas reserves is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
Brazil
|
|
Total
|
December 31, 2017
|
|
|
|
|
|
Future cash inflows
|
$
|
2,570,551
|
|
|
$
|
—
|
|
|
$
|
2,570,551
|
|
Future production costs
|
(1,082,651
|
)
|
|
—
|
|
|
(1,082,651
|
)
|
Future development costs
|
(212,712
|
)
|
|
—
|
|
|
(212,712
|
)
|
Future asset retirement obligations
|
(33,796
|
)
|
|
—
|
|
|
(33,796
|
)
|
Future income tax expense
|
(146,652
|
)
|
|
—
|
|
|
(146,652
|
)
|
Future net cash flows
|
1,094,740
|
|
|
—
|
|
|
1,094,740
|
|
10% discount
|
(246,692
|
)
|
|
—
|
|
|
(246,692
|
)
|
Standardized Measure of Discounted Future Net Cash Flows
|
$
|
848,048
|
|
|
$
|
—
|
|
|
$
|
848,048
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
|
|
Future cash inflows
|
$
|
1,487,553
|
|
|
$
|
195,476
|
|
|
$
|
1,683,029
|
|
Future production costs
|
(803,208
|
)
|
|
(85,262
|
)
|
|
(888,470
|
)
|
Future development costs
|
(94,131
|
)
|
|
(23,975
|
)
|
|
(118,106
|
)
|
Future asset retirement obligations
|
(24,647
|
)
|
|
(1,200
|
)
|
|
(25,847
|
)
|
Future income tax expense
|
(28,446
|
)
|
|
(8,957
|
)
|
|
(37,403
|
)
|
Future net cash flows
|
537,121
|
|
|
76,082
|
|
|
613,203
|
|
10% discount
|
(117,263
|
)
|
|
(43,235
|
)
|
|
(160,498
|
)
|
Standardized Measure of Discounted Future Net Cash Flows
|
$
|
419,858
|
|
|
$
|
32,847
|
|
|
$
|
452,705
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
Future cash inflows
|
$
|
1,486,828
|
|
|
$
|
195,726
|
|
|
$
|
1,682,554
|
|
Future production costs
|
(697,071
|
)
|
|
(58,058
|
)
|
|
(755,129
|
)
|
Future development costs
|
(51,671
|
)
|
|
(15,660
|
)
|
|
(67,331
|
)
|
Future asset retirement obligations
|
(15,096
|
)
|
|
(1,200
|
)
|
|
(16,296
|
)
|
Future income tax expense
|
(196,981
|
)
|
|
(17,361
|
)
|
|
(214,342
|
)
|
Future net cash flows
|
526,009
|
|
|
103,447
|
|
|
629,456
|
|
10% discount
|
(119,100
|
)
|
|
(45,599
|
)
|
|
(164,699
|
)
|
Standardized Measure of Discounted Future Net Cash Flows
|
$
|
406,909
|
|
|
$
|
57,848
|
|
|
$
|
464,757
|
|
Changes in the Standardized Measure of Discounted Future Net Cash Flows
The following table summarizes changes in the standardized measure of discounted future net cash flows for Gran Tierra's proved oil and gas reserves during three years ended
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
2017
|
|
2016
|
|
2015
|
Balance, beginning of year
|
$
|
452,705
|
|
|
$
|
464,757
|
|
|
$
|
1,021,133
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(193,197
|
)
|
|
(207,776
|
)
|
|
(160,242
|
)
|
Net changes in prices and production costs related to future production
|
(372,138
|
)
|
|
13,425
|
|
|
(918,746
|
)
|
Extensions, discoveries and improved recovery, less related costs
|
193,672
|
|
|
111
|
|
|
22,754
|
|
Previously estimated development costs incurred during the year
|
71,816
|
|
|
34,917
|
|
|
54,904
|
|
Revisions of previous quantity estimates
|
1,128,440
|
|
|
(263,713
|
)
|
|
144,603
|
|
Accretion of discount
|
(120,231
|
)
|
|
73,076
|
|
|
137,853
|
|
Purchases of reserves in place
|
7,416
|
|
|
186,393
|
|
|
—
|
|
Sales of reserves in place
|
(32,847
|
)
|
|
—
|
|
|
—
|
|
Net change in income taxes
|
(112,838
|
)
|
|
178,273
|
|
|
100,587
|
|
Changes in future development costs
|
(174,750
|
)
|
|
(26,758
|
)
|
|
61,911
|
|
Net increase (decrease)
|
395,343
|
|
|
(12,052
|
)
|
|
(556,376
|
)
|
Balance, end of year
|
$
|
848,048
|
|
|
$
|
452,705
|
|
|
$
|
464,757
|
|
2) Summarized Quarterly Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Year Ended
|
(Thousands of U.S. Dollars, Except Per Share Amounts)
|
March 31, 2017
|
June 30, 2017
|
September 30, 2017
|
December 31, 2017
|
|
December 31, 2017
|
Oil and natural gas sales
|
$
|
94,659
|
|
$
|
96,128
|
|
$
|
103,768
|
|
$
|
127,179
|
|
|
$
|
421,734
|
|
|
|
|
|
|
|
|
Asset impairment
|
$
|
283
|
|
$
|
169
|
|
$
|
787
|
|
$
|
275
|
|
|
$
|
1,514
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
12,771
|
|
$
|
(6,807
|
)
|
$
|
3,130
|
|
$
|
(40,802
|
)
|
|
$
|
(31,708
|
)
|
|
|
|
|
|
|
|
Net income (Loss) per share - Basic and Diluted
|
$
|
0.03
|
|
$
|
(0.02
|
)
|
$
|
0.01
|
|
$
|
(0.10
|
)
|
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Year Ended
|
(Thousands of U.S. Dollars, Except Per Share Amounts)
|
March 31, 2016
|
June 30,
2016
|
September 30, 2016
|
December 31, 2016
|
|
December 31, 2016
|
Oil and natural gas sales
|
$
|
57,403
|
|
$
|
71,713
|
|
$
|
68,539
|
|
$
|
91,614
|
|
|
$
|
289,269
|
|
|
|
|
|
|
|
|
Asset impairment
|
$
|
56,898
|
|
$
|
92,843
|
|
$
|
319,974
|
|
$
|
146,934
|
|
|
$
|
616,649
|
|
|
|
|
|
|
|
|
Net loss
|
$
|
(45,032
|
)
|
$
|
(63,559
|
)
|
$
|
(229,619
|
)
|
$
|
(127,355
|
)
|
|
$
|
(465,565
|
)
|
|
|
|
|
|
|
|
Loss per share - Basic and Diluted
|
$
|
(0.15
|
)
|
$
|
(0.21
|
)
|
$
|
(0.71
|
)
|
$
|
(0.38
|
)
|
|
$
|
(1.45
|
)
|