Notes to the Consolidated Financial Statements
For the Years Ended
December 31, 2016
,
2015
and
2014
(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 has business activities in Peru and Brazil, and until June 25, 2014, had business activities in Argentina.
On February, 6, 2017, the Company announced that a purchase and sale agreement (the "Agreement") had been executed by a third party ("Purchaser") to purchase Gran Tierra's Brazil business unit through the acquisition of all of the equity interests in one of Gran Tierra's indirect subsidiaries, and the assignment of certain debt owed by the corporate entities comprising Gran Tierra's Brazil business unit to the Gran Tierra group of companies (Note 17).
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”). The Company believes that the information and disclosures presented are adequate to ensure the information presented is not misleading.
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.
Discontinued operations
On June 25, 2014, the Company completed the sale of its Argentina business unit and the discontinued operations criteria of Accounting Standards Codification ("ASC") 205-20, “
Discontinued Operations
”, were met. Therefore, the results of the Company’s Argentina business unit are reflected separately as loss from discontinued operations, net of income taxes, in the consolidated statement of operations for the year ended December 31, 2014, on a line immediately after “Loss or income from continuing operations.” Additionally, cash flows of the Company’s Argentina business unit are reflected separately in the consolidated statement of cash flows for the year ended December 31, 2014, as cash provided by or used in operating and investing activities of discontinued operations. See Note 4, “Discontinued Operations,” for additional disclosure.
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. 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 is included in other current assets and other long-term assets on the Company's balance sheet. 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.
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, 2016
, and
2015
.
Marketable securities
The Company acquired investments in marketable securities in connection with the sale of its Argentina business unit in 2014. Marketable securities are classified as trading securities, in accordance with ASC 320, “
Investments – Debt and Equity Securities
”, and are recorded in the consolidated balance sheet at fair value. The Company classifies trading securities as current or non-current based on the intent of management, the nature of the trading securities and whether they are readily available for use in current operations. Gains or losses on trading securities are 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. 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 or market 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 two-step 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 the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for the Company’s reporting units, the fair values of the reporting units are estimated based upon estimated future cash flows of the reporting unit.
The Company recorded
$87.6 million
of goodwill in relation to the acquisition of Solana Resources Limited (“Solana”) in 2008 and
$15.0 million
of goodwill in relation to the Argosy Energy International L.P. acquisition in 2006. The goodwill relates entirely to the Colombia reportable segment. The Company performed a qualitative assessment of goodwill at
December 31, 2016
, and based on this assessment, no impairment of goodwill was identified.
Convertible Senior Notes
The Company accounts for its
5.00%
Convertible Senior Notes due 2021 (the "Notes") as a liability in their entirety. The
embedded features of the Notes were assessed for bifurcation from the 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 Notes which have been presented as a direct
deduction against the carrying amount of the Notes and are being amortized to interest expense using the effective interest
method over the contractual term of the 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. In Colombia, the sales point for the Company's sales varies depending on the delivery point but includes the Port of Tumaco on the Pacific coast of Colombia, the purchaser's facilities and when oil is loaded into a truck at Gran Tierra's loading facility or an export tanker. In Brazil, the sales point is either the Petróleo Brasileiro S.A station or the purchaser's facility.
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 Accounting for Measurement - Period Adjustments
In September 2015, the Financial Accounting Standards Board (the "FASB") issued Accounting Standards Update (“ASU")
2015-16, "Simplifying the Accounting for Measurement - Period Adjustments". The amendments require that an acquirer
recognize adjustments to provisional amounts identified during the measurement period in the reporting period in which the
adjustments are determined and eliminates the requirement to retrospectively revise prior periods. Additionally, an acquirer
should record in the same period the effects on earnings of any changes in the provisional accounts, calculated as if the
accounting had been completed at the acquisition date. The ASU was effective for fiscal years, and interim periods within those
years, beginning after December 15, 2015. The implementation of this update did not materially impact the Company’s
consolidated financial position at December 31, 2016 or results of operations or cash flows for the year ended December 31, 2016. See Note 3, “Business Combinations,” for additional disclosure.
Classification of Certain Cash Receipts and Cash Payments
In August 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments"
.
This ASU
addresses specific cash flow issues with the objective of reducing the existing diversity in practice in how certain cash receipts
and cash payments are presented and classified in the statement of cash flows. The ASU will be effective for fiscal years, and
interim periods within those years, beginning after December 15, 2017. The Company implemented this update retrospectively
in its consolidated financial statements for the interim period ended September 30, 2016. The implementation of this update did
not materially impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.
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 will be 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 is currently assessing the impact the new revenue recognition model will have on its consolidated financial
position, results of operations, cash flows, and disclosure.
Simplifying the Measurement of Inventory
In July 2015, the 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 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The implementation of this update is not expected to materially impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.
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.
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 will be effective for fiscal years, and interim
periods within those years, beginning after December 15, 2016. The Company is currently assessing the impact this update 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.
Income Taxes - Intra-Entity Transfers of Assets Other than Inventory
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. Current GAAP prohibits the recognition of income tax expense or benefit for an intra-entity transfer until the asset leaves the consolidated group.
This ASU will be effective for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted as of the beginning of an annual reporting period. The ASU must be applied on a modified retrospective basis with a cumulative-effect adjustment directly to retained earnings in the period of adoption. In the period of adoption, the Company will write off any income tax effects that had been deferred from past intercompany transactions to opening retained earnings.
The Company expects to early adopt this ASU in its year ended December 31, 2017, and expects prepaid tax of
$54.1 million
and deferred tax assets will be recorded directly to opening retained earnings at January 1, 2017. The Company is currently assessing the deferred tax effect of adoption of this ASU. Deferred tax assets recorded upon adoption will be assessed for realizability under ASC 740, and, if a valuation allowance on those deferred tax assets is necessary on the date of adoption, that allowance will be recorded with an offset to opening retained earnings. ASU 2016-16 will not have any effect on the Company’s cash flows.
Restricted Cash
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. This ASU will not impact the Company's consolidated financial position or results of operations and for the year ended December 31, 2016, would not have had a material impact on net cash used in investing activities. For the year ended December 31, 2016, the net
decrease
in cash, cash equivalents and restricted cash and cash equivalents would have been
$119.9 million
, compared with the net
decrease
in cash and cash equivalents of
-$120.2 million
as currently disclosed in the consolidated statement of cash flows.
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 is permitted.
The Company expects to early adopt this ASU in its year ended December 31, 2017. The Company will apply 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, the set will not be a business and no goodwill or gain on acquisition will be recognized.
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. A 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, 2016, the Company performed a qualitative assessment of goodwill and, based on this assessment, no impairment of goodwill was identified. The Company did not have to perform step 2 of the goodwill impairment test.
3. Business Combinations
a) PetroLatina Energy Ltd.
On August 23, 2016 (the “PetroLatina Acquisition Date”), the Company acquired all of the issued and outstanding common shares of PetroLatina Energy Ltd. ("PetroLatina") for
$525 million
, consisting of cash consideration of
$465.7 million
, which included a deferred cash payment of
$25.0 million
that was paid on December 31, 2016, assumption of a reserve-backed credit
facility with an outstanding balance of
$80.0 million
(Note 8), net working capital of
$17.3 million
and other closing adjustments. Upon completion of the transaction on the PetroLatina Acquisition Date, Gran Tierra repaid and canceled the reserve-based credit facility and PetroLatina became an indirect wholly-owned subsidiary of Gran Tierra.
PetroLatina is an exploration and production company, incorporated in England and Wales, with assets primarily in the Middle Magdalena Basin of Colombia. The acquisition added a new core area for Gran Tierra in the prolific Middle Magdalena Basin and was accounted for as a business combination using the acquisition method, with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the PetroLatina Acquisition Date, and the results of PetroLatina were included with those of Gran Tierra from that date. Fair value estimates were made based on significant unobservable (Level 3) inputs and based on the best information available at the time.
The following table shows the allocation of the consideration based on the fair values of the assets and liabilities acquired:
|
|
|
|
|
(Thousands of U.S. Dollars)
|
|
Consideration Paid:
|
|
Purchase price
|
$
|
525,000
|
|
Purchase price adjustments:
|
|
PetroLatina's long-term debt assumed
|
(80,000
|
)
|
Working capital and other
|
20,683
|
|
Total cash consideration
|
465,683
|
|
Estimated post-closing adjustments
|
1,908
|
|
Cash consideration paid
|
$
|
467,591
|
|
|
|
Allocation of Total Consideration
(2)
:
|
|
Oil and gas properties
|
|
Proved
(1)
|
$
|
360,483
|
|
Unproved
(1)
|
432,286
|
|
Net working capital (including cash acquired of $15.9 million, restricted cash of $0.7 million and accounts receivable of $4.0 million)
|
17,302
|
|
Long-term restricted cash
|
3,017
|
|
Long-term debt
|
(80,000
|
)
|
Long-term deferred tax liability
(1)
|
(262,566
|
)
|
Long-term portion of asset retirement obligation
|
(3,870
|
)
|
Other long-term liabilities
|
(969
|
)
|
|
$
|
465,683
|
|
(1)
During the three months ended December 31, 2016, post-closing adjustments were finalized and this resulted in a
$4.3 million
increase to total cash consideration. Additionally, management obtained further information about the acquisition date fair value of PetroLatina's proved and unproved properties and working capital and determined that the fair values were
$3.9 million
lower,
$9.6 million
higher and
$1.8 million
higher, respectively, than previously estimated. This resulted in a
$3.2 million
increase in the acquisition date deferred tax liability. In accordance with GAAP, these changes were accounted for in the three months ended December 31, 2016 without retrospective revision of prior periods. The reduction in the acquisition date fair value of proved properties would have resulted in a
$1.0 million
net of income tax expense, reduction in the net loss for the three months ended September 30, 2016, as a result of lower Colombian ceiling test impairment losses.
(2)
The allocation of the consideration is incomplete and is subject to change. Management is continuing to review and assess information to accurately determine the acquisition date fair value of the assets and liabilities acquired. During the measurement period, Gran Tierra will continue to obtain information to assist in finalizing the fair value of net assets acquired, which may differ materially from the above preliminary estimates.
The Company's consolidated statement of operations for the year ended December 31, 2016, included oil and gas sales of
$11.4 million
and net
loss
after tax of
$42.3 million
from PetroLatina for the period subsequent to the PetroLatina Acquisition Date.
Pro Forma Results (unaudited)
Pro forma results for the years ended December 31, 2016 and 2015, are shown below, as if the acquisition had occurred on January 1, 2015. Pro forma results are not indicative of actual results or future performance.
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(Unaudited, thousands of U.S. Dollars, except per share amounts)
|
2016
|
2015
|
Oil and gas sales
|
$
|
323,266
|
|
$
|
357,693
|
|
Net loss
|
$
|
(309,972
|
)
|
$
|
(288,389
|
)
|
Net loss per share - basic and diluted
|
$
|
(0.97
|
)
|
$
|
(1.01
|
)
|
The supplemental pro forma net loss of Gran Tierra for the year ended December 31, 2016, was adjusted to exclude
$6.2 million
of transaction expenses because they were not expected to have a continuing impact on Gran Tierra’s results of operations.
b) Petroamerica Oil Corp.
On January 13, 2016 (the “Petroamerica Acquisition Date”), the Company acquired all of the issued and outstanding common shares of Petroamerica Oil Corp. ("Petroamerica"), a Canadian corporation, pursuant to the terms and conditions of an arrangement agreement dated November 12, 2015 (the “Arrangement”). The transaction contemplated by the Arrangement was effected through a court approved plan of arrangement in Canada. The Arrangement was approved at a special meeting of Petroamerica shareholders and by the Court of Queen's Bench of Alberta on January 11, 2016. Under the Arrangement, each Petroamerica shareholder was entitled to receive, for each Petroamerica share held, either
$0.40
of a Gran Tierra common share or
$1.33
Canadian dollars in cash, or a combination of shares and cash, subject to a maximum of
70%
of the consideration payable in cash.
As consideration for the acquisition of all the issued and outstanding Petroamerica shares, the Company issued approximately
13.7 million
shares of Gran Tierra Common Stock, par value
$0.001
, and paid cash consideration of approximately
$70.6 million
. The fair value of Gran Tierra’s Common Stock issued was determined to be
$25.8 million
based on the closing price of shares of Common Stock of Gran Tierra as at the Petroamerica Acquisition Date. Total net purchase price of Petroamerica was
$72.2 million
, after giving effect to net working capital of
$24.2 million
. Upon completion of the transaction on the Petroamerica Acquisition Date, Petroamerica became an indirect wholly-owned subsidiary of Gran Tierra.
The acquisition was accounted for as a business combination using the acquisition method, with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the Petroamerica Acquisition Date, and the results of Petroamerica were included with those of Gran Tierra from that date. Fair value estimates were made based on significant unobservable (Level 3) inputs and based on the best information available at the time.
The following table shows the allocation of the consideration paid based on the fair values of the assets and liabilities acquired:
|
|
|
|
|
(Thousands of U.S. Dollars)
|
|
Consideration Paid:
|
|
Cash
|
$
|
70,625
|
|
Issuance of Common Shares, net of share issuance costs
|
25,811
|
|
|
$
|
96,436
|
|
|
|
Allocation of Consideration Paid:
|
|
Oil and gas properties
|
|
Proved
(1)
|
$
|
36,082
|
|
Unproved
(1)
|
52,232
|
|
Net working capital (including cash acquired of $19.7 million, restricted cash of $2.5 million and accounts receivable of $5.0 million)
|
24,202
|
|
Long-term restricted cash
|
8,167
|
|
Other long-term assets
|
1,570
|
|
Long-term deferred tax liability
(1)
|
(10,553
|
)
|
Long-term portion of asset retirement obligation
|
(11,556
|
)
|
Other long-term liabilities
|
(2,779
|
)
|
Gain on acquisition
(1)
|
(929
|
)
|
|
$
|
96,436
|
|
(1)
During the three months ended December 31, 2016, management obtained further information about the acquisition date fair value of Petroamerica's proved and unproved properties and determined that the fair values were
$12.5 million
lower and
$2.2 million
higher, respectively, than previously estimated. This resulted in a
$10.8 million
decrease in the gain on acquisition, and a
$0.5 million
increase in the acquisition date deferred tax liability. In accordance with GAAP, these changes were accounted for in the three months ended December 31, 2016 without retrospective revision of prior periods. The reduction in the acquisition date fair value of proved properties would have resulted in a
$11.4 million
, net of income tax expense, reduction in the net loss for the three months ended March 31, 2016, as a result of lower Colombian ceiling test impairment losses.
As indicated in the allocation of the consideration paid, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration paid. Consequently, Gran Tierra reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, Gran Tierra recognized an “Other gain” of
$0.9 million
in the consolidated statement of operations for the year ended December 31, 2016. The gain reflects the impact on Petroamerica’s pre-acquisition market value resulting from the company's lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects.
The Company's consolidated statement of operations for the year ended December 31, 2016, included oil and gas sales of
$17.1 million
and net
loss
after tax of
$24.7 million
from Petroamerica for the period subsequent to the Petroamerica Acquisition Date.
Pro Forma Results (unaudited)
Pro forma results for the years ended December 31, 2016 and 2015, are shown below, as if the acquisition had occurred on January 1, 2015. Pro forma results are not indicative of actual results or future performance.
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
(Unaudited, thousands of U.S. Dollars, except per share amounts)
|
2016
|
2015
|
Oil and gas sales
|
$
|
289,739
|
|
$
|
332,867
|
|
Net loss
|
$
|
(466,506
|
)
|
$
|
(276,852
|
)
|
Net loss per share - basic and diluted
|
$
|
(1.45
|
)
|
$
|
(0.97
|
)
|
The supplemental pro forma net loss of Gran Tierra for the year ended December 31, 2016, was adjusted to exclude the
$0.9 million
gain on acquisition and
$1.2 million
of transaction expenses because they were not expected to have a continuing impact on Gran Tierra’s results of operations.
4. Discontinued Operations
On June 25, 2014, the Company sold its Argentina business unit to Madalena Energy Inc. ("Madalena") for aggregate consideration of
$69.3 million
, comprising
$55.4 million
in cash and
$13.9 million
in Madalena shares. Revenue and other income and loss from discontinued operations, net of income taxes, for the year ended December 31, 2014, were as follows:
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(Thousands of U.S. Dollars)
|
|
2014
|
Revenue and other income
|
|
$
|
31,985
|
|
|
|
|
Loss from operations of discontinued operations before income taxes
|
|
$
|
(6,252
|
)
|
Income tax expense
|
|
(1,458
|
)
|
Loss from operations of discontinued operations
|
|
(7,710
|
)
|
|
|
|
Loss on sale before income taxes
|
|
(18,235
|
)
|
Income tax expense
|
|
(1,045
|
)
|
Loss on sale
|
|
(19,280
|
)
|
Loss from discontinued operations, net of income taxes
|
|
$
|
(26,990
|
)
|
5. Segment and Geographic Reporting
The Company is primarily engaged in the exploration and production of oil and natural gas. The Company’s reportable segments are Colombia, Peru and Brazil based on geographic organization. The All Other category represents the Company’s corporate activities. The Company evaluates reportable segment performance based on income or loss from continuing operations before income taxes.
On February, 6, 2017, the Company announced that a purchase and sale agreement had been executed by the Purchaser to purchase Gran Tierra's Brazil business unit through the acquisition of all of the equity interests in one of Gran Tierra's indirect subsidiaries, and the assignment of certain debt owed by the corporate entities comprising Gran Tierra's Brazil business unit to the Gran Tierra group of companies (Note 17). The completion of the sale is subject to the Purchaser obtaining financing, as well as customary closing conditions, including the receipt of required regulatory approval from the ANP.
The following tables present information on the Company’s reportable segments and other activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
Peru
|
|
Brazil
|
|
All Other
|
|
Total
|
Oil and natural gas sales
|
$
|
280,872
|
|
|
$
|
—
|
|
|
$
|
8,397
|
|
|
$
|
—
|
|
|
$
|
289,269
|
|
DD&A expenses
|
132,569
|
|
|
544
|
|
|
3,819
|
|
|
2,603
|
|
|
139,535
|
|
Asset impairment
|
514,314
|
|
|
31,192
|
|
|
71,143
|
|
|
—
|
|
|
616,649
|
|
General and administrative expenses
|
17,187
|
|
|
1,643
|
|
|
968
|
|
|
13,420
|
|
|
33,218
|
|
Interest income
|
1,281
|
|
|
8
|
|
|
274
|
|
|
805
|
|
|
2,368
|
|
Interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
14,145
|
|
|
14,145
|
|
Loss from continuing operations before income taxes
|
(505,447
|
)
|
|
(33,181
|
)
|
|
(70,591
|
)
|
|
(41,015
|
)
|
|
(650,234
|
)
|
Segment capital expenditures
(1)
|
105,963
|
|
|
5,059
|
|
|
15,146
|
|
|
1,621
|
|
|
127,789
|
|
|
Year Ended December 31, 2015
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
Peru
|
|
Brazil
|
|
All Other
|
|
Total
|
Oil and natural gas sales
|
$
|
269,035
|
|
|
$
|
—
|
|
|
$
|
6,976
|
|
|
$
|
—
|
|
|
$
|
276,011
|
|
DD&A expenses
|
167,701
|
|
|
789
|
|
|
6,183
|
|
|
1,713
|
|
|
176,386
|
|
Asset impairment
|
235,069
|
|
|
41,916
|
|
|
46,933
|
|
|
—
|
|
|
323,918
|
|
General and administrative expenses
|
9,805
|
|
|
3,800
|
|
|
2,708
|
|
|
16,040
|
|
|
32,353
|
|
Interest income
|
294
|
|
|
2
|
|
|
218
|
|
|
855
|
|
|
1,369
|
|
Interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Loss from continuing operations before income taxes
|
(238,463
|
)
|
|
(51,675
|
)
|
|
(54,968
|
)
|
|
(22,982
|
)
|
|
(368,088
|
)
|
Segment capital expenditures
|
85,326
|
|
|
50,203
|
|
|
20,014
|
|
|
1,096
|
|
|
156,639
|
|
|
Year Ended December 31, 2014
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
Peru
|
|
Brazil
|
|
All Other
|
|
Total
|
Oil and natural gas sales
|
$
|
532,196
|
|
|
$
|
—
|
|
|
$
|
27,202
|
|
|
$
|
—
|
|
|
$
|
559,398
|
|
DD&A expenses
|
174,063
|
|
|
690
|
|
|
9,932
|
|
|
1,192
|
|
|
185,877
|
|
Asset impairment
|
—
|
|
|
265,126
|
|
|
—
|
|
|
|
|
|
265,126
|
|
General and administrative expenses
|
19,431
|
|
|
6,448
|
|
|
3,698
|
|
|
21,672
|
|
|
51,249
|
|
Interest income
|
569
|
|
|
1
|
|
|
1,604
|
|
|
682
|
|
|
2,856
|
|
Interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Income (loss) from continuing operations before income taxes
|
279,924
|
|
|
(274,207
|
)
|
|
5,921
|
|
|
(28,772
|
)
|
|
(17,134
|
)
|
Segment capital expenditures
|
206,520
|
|
|
158,266
|
|
|
23,873
|
|
|
2,867
|
|
|
391,526
|
|
(1)
On January 13, 2016 and August 23, 2016, respectively, the Company acquired all of the issued and outstanding common
shares of Petroamerica and PetroLatina, which acquisitions were accounted for as business combinations (Note 3) and,
therefore, property, plant and equipment acquired are not reflected in the table above. Additionally, on January 25, 2016, the
Company acquired all of the issued and outstanding common shares of PetroGranada Colombia Limited ("PGC"), which
acquisition was accounted for as an asset acquisition (Note 7) and property, plant and equipment acquired in this acquisition are
not reflected in the table above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2016
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
Peru
|
|
Brazil
|
|
All Other
|
|
Total
|
Property, plant and equipment
|
$
|
939,947
|
|
|
$
|
68,428
|
|
|
$
|
55,196
|
|
|
$
|
3,038
|
|
|
$
|
1,066,609
|
|
Goodwill
|
102,581
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
102,581
|
|
All other assets
|
177,393
|
|
|
10,848
|
|
|
1,619
|
|
|
8,846
|
|
|
$
|
198,706
|
|
Total Assets
|
$
|
1,219,921
|
|
|
$
|
79,276
|
|
|
$
|
56,815
|
|
|
$
|
11,884
|
|
|
$
|
1,367,896
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2015
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
Peru
|
|
Brazil
|
|
All Other
|
|
Total
|
Property, plant and equipment
|
$
|
574,351
|
|
|
$
|
95,069
|
|
|
$
|
115,552
|
|
|
$
|
4,021
|
|
|
$
|
788,993
|
|
Goodwill
|
102,581
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
102,581
|
|
All other assets
|
93,479
|
|
|
21,111
|
|
|
2,236
|
|
|
137,718
|
|
|
$
|
254,544
|
|
Total Assets
|
$
|
770,411
|
|
|
$
|
116,180
|
|
|
$
|
117,788
|
|
|
$
|
141,739
|
|
|
$
|
1,146,118
|
|
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,
|
|
2016
|
|
2015
|
|
2014
|
Number of significant customers
|
3
|
|
4
|
|
2
|
Sales to each significant customer as % of oil and gas sales
|
40
|
%
|
34
|
%
|
13
|
%
|
|
43
|
%
|
15
|
%
|
13
|
%
|
12
|
%
|
|
52
|
%
|
32
|
%
|
6. Accounts Receivable and Inventory
Accounts Receivable
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
Trade
|
$
|
39,203
|
|
|
$
|
26,924
|
|
Other
|
6,495
|
|
|
2,293
|
|
|
$
|
45,698
|
|
|
$
|
29,217
|
|
Inventory
At
December 31, 2016
, oil and supplies inventories were
$6.0 million
and
$1.8 million
, respectively (
December 31, 2015
-
$17.8 million
and
$1.3 million
, respectively). At
December 31, 2016
, the Company had
208
Mbbl of oil inventory
(December 31, 2015 -
616
Mbbl) NAR. In the
year ended December 31, 2016
, the Company recorded oil inventory impairment of
$0.7 million
(
year ended December 31, 2015
-
$2.6 million
,
year ended December 31, 2014
- $
nil
) related to lower oil prices (Note 7).
7. Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
Oil and natural gas properties
|
|
|
|
|
Proved
|
$
|
2,652,171
|
|
|
$
|
1,998,330
|
|
Unproved
|
647,774
|
|
|
310,771
|
|
|
3,299,945
|
|
|
2,309,101
|
|
Other
|
29,445
|
|
|
28,342
|
|
|
3,329,390
|
|
|
2,337,443
|
|
Accumulated depletion, depreciation and impairment
|
(2,262,781
|
)
|
|
(1,548,450
|
)
|
|
$
|
1,066,609
|
|
|
$
|
788,993
|
|
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 (Note 3). 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
$42.92
per bbl for the purposes of the December 31, 2016, ceiling test calculations (December 31, 2015 -
$54.08
).
In the year ended December 31,
2016
, the Company recorded impairment losses in its Peru cost center of
$31.2 million
related to costs incurred on Block 95, and other blocks. In the years ended December 31, 2015 and 2014, the Company recorded impairment losses of
$41.9 million
and
$265.1 million
, respectively, related to costs incurred on Block 95. 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. In the three months ended September 30, 2016, the Company ceased the impairment of costs incurred on Block 95 as a result of the effect of a revised field development plan for the Block.
Asset impairment for the three years ended December 31,
2016
, was follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Impairment of oil and gas properties
|
$
|
615,985
|
|
|
$
|
321,285
|
|
|
$
|
265,126
|
|
Impairment of inventory (Note 6)
|
664
|
|
|
2,633
|
|
|
—
|
|
|
$
|
616,649
|
|
|
$
|
323,918
|
|
|
$
|
265,126
|
|
Depletion and depreciation expense on property, plant and equipment for the
year ended
December 31, 2016
, was
$130.2 million
(
year ended
December 31, 2015
-
$177.9 million
;
year ended December 31, 2014
-
$187.9 million
). A portion of depletion and depreciation expense was recorded as inventory in each year and adjusted for inventory changes.
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. PGC is an oil and gas exploration, development and
production company active in Colombia. 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.
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
|
$
|
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
|
|
Long-term deferred tax liability
|
(8,403
|
)
|
|
$
|
37,727
|
|
Contingent consideration of
$4.0 million
will be payable if cumulative production from the Putumayo-7 Block plus gross proved plus probable reserves under the Putumayo-7 Block meet or exceed
8
MMbbl. Contingent consideration will be
recognized when the contingency is resolved and the consideration is paid or becomes payable.
On November 25, 2016, Gran Tierra submitted winning bids totaling a combined
$30.4 million
for
two
blocks which Ecopetrol offered as part of an asset disposition process. Gran Tierra's winning bids were on the Santana and Nancy-Burdine-Maxine Blocks, which are located in the Putumayo Basin. At December 31, 2016, the assignments of working interests in these blocks was not complete. Ecopetrol will transfer ownership of the blocks' assets, contracts, permits and licenses, as well as
100%
ownership of Ecopetrol's rights and obligations in respect of the oil and gas assets, to Gran Tierra once the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) grants approval and the conditions of the assignment agreement are met. The purchase price of
$30.4 million
will be paid from the Company's credit facility. Additionally, 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 consist of exploration lands held in Colombia, Brazil and Peru. The following table provides a summary of Gran Tierra’s unproved properties as at
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
Colombia
|
$
|
561,463
|
|
|
$
|
147,500
|
|
Brazil
|
67,866
|
|
|
69,089
|
|
Peru
|
18,445
|
|
|
94,182
|
|
|
$
|
647,774
|
|
|
$
|
310,771
|
|
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
74%
of costs not subject to depletion at
December 31, 2016
, 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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred in
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
|
2014
|
|
Prior to 2014
|
|
Total
|
Acquisition costs - Colombia
|
$
|
429,626
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
48,810
|
|
|
$
|
478,436
|
|
Acquisition costs - Peru
|
—
|
|
|
—
|
|
|
—
|
|
|
11,500
|
|
|
11,500
|
|
Acquisition costs - Brazil
|
—
|
|
|
—
|
|
|
—
|
|
|
5,949
|
|
|
5,949
|
|
Exploration costs - Colombia
|
10,823
|
|
|
16,840
|
|
|
29,969
|
|
|
25,394
|
|
|
83,026
|
|
Exploration costs - Peru
|
3,213
|
|
|
7,471
|
|
|
29,424
|
|
|
16,258
|
|
|
56,366
|
|
Exploration costs - Brazil
|
79
|
|
|
4,714
|
|
|
2,024
|
|
|
5,680
|
|
|
12,497
|
|
Total oil and natural gas properties not subject to depletion
|
$
|
443,741
|
|
|
$
|
29,025
|
|
|
$
|
61,417
|
|
|
$
|
113,591
|
|
|
$
|
647,774
|
|
8. Debt and Debt Issuance Costs
The Company's debt at December 31, 2016 and 2015, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
|
2016
|
|
2015
|
Convertible senior notes (a)
|
|
$
|
115,000
|
|
|
$
|
—
|
|
Revolving credit facility (b)
|
|
90,000
|
|
|
—
|
|
Unamortized debt issuance costs
|
|
(7,917
|
)
|
|
—
|
|
Long-term debt
|
|
$
|
197,083
|
|
|
$
|
—
|
|
a) Convertible Senior Notes
On April 6, 2016, the Company issued
$100 million
aggregate principal amount of Notes in a private placement to qualified institutional buyers. On April 22, 2016, the Company issued an additional
$15 million
aggregate principal amount of the Notes pursuant to the underwriters’ exercise of their option to acquire additional Notes. The 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 Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted. The Notes are unsecured and are subordinated to secured debt to the extent of the value of the assets securing such indebtedness.
The 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 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 Notes in connection with such a corporate event in certain circumstances.
The Company may not redeem the Notes prior to April 5, 2019, except in certain circumstances following a fundamental change (as defined in the indenture governing the Notes). The Company may redeem for all cash or any portion of the Notes, at its option, on or after April 5, 2019, if (terms below are as defined in the indenture governing the 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 Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. No sinking fund is provided for the Notes.
If the Company undergoes a fundamental change, holders may require the Company to repurchase for cash all or any portion of their Notes at a fundamental change repurchase price equal to
100%
of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.
Net proceeds from the sale of the 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, 2016, the Company had a revolving credit facility with a syndicate of lenders. On November 16, 2016, the Company entered into a Fourth Amendment (the "Fourth Amendment") to its credit agreement dated September 18, 2015 (the "Credit Agreement"). The Fourth Amendment, among other things, increased the borrowing base from
$185.0 million
, with
$160.0 million
readily available and
$25.0 million
subject to the consent of all lenders, to
$250 million
readily available. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders.
T
he borrowing base will be re-determined semi-annually and will be re-determined no later than May 2017. The Company’s revolving credit facility is secured against the assets of the Company’s subsidiaries in Colombia, Canada and the United States of America (the "Credit Facility Group"). The credit agreement includes a letter of credit sub-limit of up to
$100 million
. None of the letter of credit sub-limit had been used at December 31, 2016. Borrowings under the revolving credit facility will mature on September 18, 2018. Under the terms of the credit facility, the Company cannot pay any dividends to its shareholders if it is in default under the facility and, if the Company is not in default, it is required to obtain bank approval for dividend payments to shareholders outside of the Credit Facility Group.
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
2.00%
and
3.00%
per annum, or an alternate base rate plus a margin ranging from
1.00%
per annum to
2.00%
per annum, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. At December 31 2016, the weighted-average interest rate on the balance outstanding on the Company's revolving credit facility was approximately
2.96%
. Undrawn amounts under the revolving credit facility bear interest at
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.
On August 23, 2016, the Company entered into a Third Amendment (the "Third Amendment") to the Credit Agreement to add a bridge term loan facility (the “Bridge Loan Facility”), pursuant to which the lenders provided
$130.0 million
in secured bridge loan financing to fund a portion of the purchase price of the PetroLatina acquisition. The Bridge Loan Facility had a term of
364
days, bore interest at USD LIBOR plus
6%
, and had customary bridge facility repayment terms, providing for the prepayment of the Bridge Loan Facility upon the occurrence of certain events, including certain debt issuances. It was otherwise on substantially the same terms as the existing secured revolving credit facility.
On August 23, 2016, in connection with the PetroLatina acquisition, the Company drew
$95.0 million
on its revolving credit facility and
$130.0 million
on its Bridge Loan Facility. During the three months ending September 30, 2016, the Company repaid
$30.0 million
of the balance outstanding on its revolving credit facility.
During the three months ending December 31, 2016, upon the sale of non-core assets (Note 7), the Company repaid
$5.0 million
of the balance outstanding on the Bridge Loan Facility and, concurrent with the effectiveness of the Fourth Amendment, repaid the remaining balance on the Bridge Loan Facility using available borrowing capacity under its Credit Agreement. This resulted in a balance outstanding on its revolving credit facility of $
190 million
. The Company subsequently drew an additional
$37.0 million
on its revolving credit facility and repaid
$137.0 million
of the balance outstanding on this facility primarily using proceeds from its November 2016 equity offering (Note 9).
As part of the PetroLatina acquisition, Gran Tierra assumed PetroLatina's reserve-backed credit facility with an outstanding balance as at the PetroLatina Acquisition Date of
$80.0 million
. This credit facility plus accrued interest was repaid by Gran Tierra upon closing of the PetroLatina Acquisition on August 23, 2016.
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)
|
2016
|
|
2015
|
|
2014
|
Contractual interest and other financing expenses
|
$
|
8,454
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Amortization of debt issuance costs
|
5,691
|
|
|
—
|
|
|
—
|
|
|
$
|
14,145
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The Company incurred debt issuance costs in connection with the issuance of the Notes, the Bridge Loan Facility and its revolving credit facility. As at December 31, 2016, 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.
9. 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, 2016
, outstanding share capital consists of
390,807,194
shares of Common Stock of the Company,
4,812,592
exchangeable shares of Gran Tierra Exchangeco Inc., (the "Exchangeco exchangeable shares") and
3,387,302
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, 2015
|
273,442,799
|
|
4,933,177
|
|
3,638,889
|
|
Shares issued upon conversion of subscription receipts (a)
|
57,835,134
|
|
—
|
|
—
|
|
Shares issued upon public offering (b)
|
43,335,000
|
|
—
|
|
—
|
|
Shares issued for acquisition (Note 3)
|
13,656,719
|
|
—
|
|
—
|
|
Options exercised
|
2,165,370
|
|
—
|
|
—
|
|
Exchange of exchangeable shares
|
372,172
|
|
(120,585
|
)
|
(251,587
|
)
|
Balance, December 31, 2016
|
390,807,194
|
|
4,812,592
|
|
3,387,302
|
|
a) Subscription Receipts
On July 8, 2016, the Company issued approximately
57.8 million
subscription receipts (“Subscription Receipts”) in a private placement to eligible purchasers at a price of
$3.00
per Subscription Receipt for gross proceeds of
$173.5 million
, or net proceeds after share issuance costs of
$165.8 million
. The proceeds were used to partially fund the PetroLatina acquisition. Each Subscription Receipt entitled the holder to automatically receive
one
common share of the Company upon closing of the PetroLatina acquisition on the satisfaction of certain conditions. Upon the closing of the PetroLatina acquisition on August 23, 2016, each Subscription Receipt was converted to
one
common share.
b) Public Offering
On November 29, 2016, the Company issued approximately
43.3 million
shares of its common stock at a public offering price of
$3.00
per share for gross proceeds of
$130.0 million
, or net proceeds after share issuance costs of
$123.0 million
(the "Offering"). The proceeds were used to repay borrowings outstanding under the Company's revolving credit facility.
2015 Share Repurchase Program
During 2015, the Company repurchased and canceled
4.6 million
shares at an average price of
$2.19
for total proceeds of
$10.0 million
, pursuant to the terms of a share repurchase program (the “2015 Program”) through the facilities of the Toronto Stock Exchange, the NYSE MKT and eligible alternative trading platforms in Canada and the United States. The 2015 Program expired on July 29, 2016.
Equity Compensation Awards
In December 2015, the Company's Board of Directors approved a new equity compensation program for 2016 to realign the
Company's compensation programs with its renewed short and long-term strategy. The 2016 equity compensation program
reflects the Company's emphasis on pay-for-performance.
In prior years, all equity awards were subject to vesting conditions based solely on the recipient’s continued employment over a
specified period of time. In contrast,
80%
of the equity awards granted in early 2016 consisted of Performance Stock Units
(“PSUs”) and
20%
consisted of stock options. Gran Tierra's Compensation Committee and Board of Directors believed it was
important to revise the Company's long-term incentive program to incorporate a new form of equity award that vests based on
the achievement of certain key measures of performance. The purpose of this change was to align the Company's executives
and employees to achieve the operational goals established by the Board of Directors, total shareholder return and increase the
net asset value per share for stockholders. The Company’s equity compensation awards outstanding as at
December 31, 2016
,
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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSUs
|
DSUs
|
RSUs
|
|
Stock Options
|
|
Number of Outstanding Share Units
|
Number of Outstanding Share Units
|
Number of Outstanding Share Units
|
|
Number of Outstanding Options
|
|
Weighted Average Exercise Price $/Option
|
Balance, December 31, 2015
|
—
|
|
—
|
|
1,015,457
|
|
|
12,851,557
|
|
|
$
|
4.60
|
|
Granted
|
3,362,717
|
|
208,698
|
|
—
|
|
|
1,744,165
|
|
|
2.69
|
|
Exercised
|
—
|
|
—
|
|
(476,972
|
)
|
|
(2,165,370
|
)
|
|
2.47
|
|
Forfeited
|
—
|
|
—
|
|
(179,340
|
)
|
|
(386,320
|
)
|
|
(4.71
|
)
|
Expired
|
—
|
|
—
|
|
—
|
|
|
(2,804,554
|
)
|
|
(6.49
|
)
|
Balance, December 31, 2016
|
3,362,717
|
|
208,698
|
|
359,145
|
|
|
9,239,478
|
|
|
$
|
4.16
|
|
Exercisable, at December 31, 2016
|
|
|
|
|
5,068,834
|
|
|
$
|
5.03
|
|
Vested, or expected to vest, at December 31, 2016, through the life of the options
|
|
|
|
|
9,000,561
|
|
|
$
|
4.19
|
|
Stock-based compensation expense for the year ended
December 31, 2016
, was
$6.3 million
(December 31, 2015 -
$2.7 million
; December 31, 2014 -
$7.7 million
) and was primarily recorded in G&A expenses.
At
December 31, 2016
, there was
$10.0 million
(
December 31, 2015
-
$3.9 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
1.8
years. The weighted-average remaining contractual term of options vested, or expected to vest, at
December 31, 2016
was
3.5
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, 2016
, are 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 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, 2016
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, 2016
, 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, 2016
, the Company paid
$1.2 million
to cash settle RSUs (
2015
-
$1.4 million
and
2014
- $
3.4 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, 2016
,
2,165,370
shares of Common Stock were issued for cash proceeds of
$5.3 million
upon the exercise of
2,165,370
stock options (
2015
–
390,000
;
2014
–
3,029,853
).
At
December 31, 2016
, the weighted average remaining contractual term of outstanding stock options was
3.5
years and of
exercisable stock options was
3.3
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,
|
|
2016
|
2015
|
2014
|
Dividend yield (per share)
|
Nil
|
|
Nil
|
|
Nil
|
|
Volatility
|
50% to 54%
|
|
46% to 50%
|
|
39% to 42%
|
|
Weighted average volatility
|
52
|
%
|
48
|
%
|
41
|
%
|
Risk-free interest rate
|
0.94% to 1.78%
|
|
1.20% to 1.68%
|
|
0.78% to 1.45%
|
|
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, 2016
, was
$1.14
(
2015
-
$1.24
;
2014
-
$2.47
). The weighted average grant date fair value for options vested in the
year ended
December 31, 2016
, was
$1.52
(
2015
-
$2.38
;
2014
-
$3.63
). The total fair value of stock options vested during
year ended
December 31, 2016
, was
$2.8 million
(
2015
-
$6.8 million
;
2014
-
$12.4 million
).
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Weighted average number of common and exchangeable shares outstanding
|
|
320,851,538
|
|
|
285,333,869
|
|
|
284,715,785
|
|
Shares issuable pursuant to stock options
|
|
—
|
|
|
—
|
|
|
—
|
|
Shares assumed to be purchased from proceeds of stock options
|
|
—
|
|
|
—
|
|
|
—
|
|
Weighted average number of diluted common and exchangeable shares outstanding
|
|
320,851,538
|
|
|
285,333,869
|
|
|
284,715,785
|
|
For the
year ended
December 31, 2016
,
10,662,034
options, on a weighted average basis, (
2015
-
13,432,287
options;
2014
-
15,621,890
options) were excluded from the diluted loss per share calculation as the options were anti-dilutive.
10. 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)
|
2016
|
|
2015
|
Balance, beginning of year
|
$
|
33,224
|
|
|
$
|
35,812
|
|
Settlements
|
(872
|
)
|
|
(6,317
|
)
|
Liabilities associated with assets sold
|
(3,257
|
)
|
|
—
|
|
Liability incurred
|
2,606
|
|
|
1,556
|
|
Liabilities assumed in acquisitions (Note 3)
|
15,723
|
|
|
—
|
|
Accretion
|
2,789
|
|
|
1,313
|
|
Revisions in estimated liability
|
(6,856
|
)
|
|
860
|
|
Balance, end of year
|
$
|
43,357
|
|
|
$
|
33,224
|
|
|
|
|
|
Asset retirement obligation - current
|
$
|
5,215
|
|
|
$
|
2,146
|
|
Asset retirement obligation - long-term
|
38,142
|
|
|
31,078
|
|
Balance, end of year
|
$
|
43,357
|
|
|
$
|
33,224
|
|
For the
year ended December 31, 2016
, settlements included cash payments of
$0.6 million
with the balance in accounts payable and accrued liabilities at
December 31, 2016
. 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 the asset retirement obligation. At
December 31, 2016
, the fair value of assets that are legally restricted for purposes of settling asset retirement obligations was
$12.0 million
(
December 31, 2015
-
$2.9 million
). These assets are accounted for as restricted cash on the Company's balance sheet.
11. Taxes
The income tax expense reported differs from the amount computed by applying the U.S. statutory rate to income or loss from continuing operations before income taxes for the following reasons:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
|
2014
|
Loss from continuing operations before income taxes
|
|
|
|
|
|
United States
|
$
|
(23,986
|
)
|
|
$
|
(14,061
|
)
|
|
$
|
(19,744
|
)
|
Foreign
|
(626,248
|
)
|
|
(354,027
|
)
|
|
2,610
|
|
|
(650,234
|
)
|
|
(368,088
|
)
|
|
(17,134
|
)
|
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
Income tax recovery expense from continuing operations expected
|
(227,582
|
)
|
|
(128,831
|
)
|
|
(5,997
|
)
|
Foreign currency translation adjustments
|
218
|
|
|
(187
|
)
|
|
(6,520
|
)
|
Impact of foreign taxes
(1)
|
(9,799
|
)
|
|
(13,087
|
)
|
|
27,910
|
|
Other local taxes
|
1,998
|
|
|
2,354
|
|
|
4,433
|
|
Stock-based compensation
|
1,955
|
|
|
919
|
|
|
2,232
|
|
Increase in valuation allowance
|
47,675
|
|
|
37,691
|
|
|
94,922
|
|
Non-deductible third party royalty in Colombia
|
2,550
|
|
|
3,416
|
|
|
9,116
|
|
Other permanent differences
|
(1,684
|
)
|
|
(2,334
|
)
|
|
1,119
|
|
Total income tax (recovery) expense from continuing operations
|
$
|
(184,669
|
)
|
|
$
|
(100,059
|
)
|
|
$
|
127,215
|
|
|
|
|
|
|
|
Current income tax expense from continuing operations
|
|
|
|
|
|
United States
|
$
|
1,818
|
|
|
$
|
1,070
|
|
|
$
|
1,260
|
|
Foreign
|
18,304
|
|
|
14,313
|
|
|
91,605
|
|
|
20,122
|
|
|
15,383
|
|
|
92,865
|
|
Deferred income tax (recovery) expense from continuing operations
|
|
|
|
|
|
Foreign
(2)
|
(204,791
|
)
|
|
(115,442
|
)
|
|
34,350
|
|
Total income tax (recovery) expense from continuing operations
|
$
|
(184,669
|
)
|
|
$
|
(100,059
|
)
|
|
$
|
127,215
|
|
(1)
Impact of foreign taxes in the rate reconciliation are tax effected at the
35%
statutory rate and for the years ended
December 31, 2016
,
2015
and 2014, included
$23.3 million
,
$11.8 million
and
$28.1 million
, 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.
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
Deferred Tax Assets
|
|
|
|
|
|
Tax benefit of operating loss carryforwards
|
$
|
74,604
|
|
|
$
|
56,015
|
|
Tax basis in excess of book basis
|
187,651
|
|
|
139,012
|
|
Foreign tax credits and other accruals
|
48,341
|
|
|
22,674
|
|
Tax benefit of capital loss carryforwards
|
32,278
|
|
|
30,799
|
|
Deferred tax assets before valuation allowance
|
342,874
|
|
|
248,500
|
|
Valuation allowance
|
(341,263
|
)
|
|
(245,259
|
)
|
|
1,611
|
|
|
3,241
|
|
Deferred Tax Liabilities
|
107,230
|
|
|
34,592
|
|
Net Deferred Tax Liabilities
|
$
|
(105,619
|
)
|
|
$
|
(31,351
|
)
|
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
Operating loss carryforwards
|
$
|
257,023
|
|
|
$
|
178,677
|
|
Capital loss carryforwards
|
$
|
239,095
|
|
|
$
|
228,144
|
|
Of the operating loss and capital loss carryforwards, losses generated by the foreign subsidiaries of the Company.
|
$
|
496,118
|
|
|
$
|
355,875
|
|
In certain jurisdictions, the operating loss carryforwards expire between 2017 and 2036, while certain other jurisdictions allow operating losses to be carried forward indefinitely. The capital losses can be carried forward indefinitely.
The valuation allowance increased by
$96.0 million
during the year ended
December 31, 2016
, which included
$48.3 million
of acquisition date valuation allowances for Petroamerica and PetroLatina. The change in the valuation allowance was primarily due to impairment losses recorded in Peru and Brazil and an increase in the corporate tax rate in Canada, partially offset by foreign currency translation adjustments. Also, the Company continues to incur losses in the U.S., Peru, Brazil and Canada. These losses are fully offset by a valuation allowance as their recognition does not meet the “more likely than not” threshold.
In the fourth quarter of 2016, Congressional authorities in Colombia enacted new legislation which consolidated the corporate income tax and CREE tax 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 have been adjusted to reflect these changes and resulted in a decrease of the future Colombian tax liability by approximately
$4.1 million
when tax effected at
40%
. This legislation also introduced a new
5%
dividend tax on distributions of previously taxed earnings from 2017 and onwards. Additionally, the legislation increased the corporate minimum presumptive income tax from
3%
to
3.5%
. This tax is imposed on a taxpayer’s net equity at the prior year-end when the presumptive CIT exceeds actual taxable profits.
Undistributed earnings of foreign subsidiaries as of
December 31, 2016
, were considered to be permanently reinvested. A determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.
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 prohibits 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. Since the date of the transfer, prepaid income taxes were amortized in accordance with accounting depreciation. Including the effect of tax reorganizations completed earlier in the year, 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.
Changes in the Company's unrecognized tax benefit relating to loss or income from continuing operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
(Thousands of U.S. Dollars)
|
|
|
|
|
|
Unrecognized tax benefit relating to loss or income from continuing operations, beginning of year
|
$
|
2,200
|
|
|
$
|
3,300
|
|
|
$
|
2,900
|
|
Increases for positions relating to prior year
|
—
|
|
|
—
|
|
|
500
|
|
Decreases for positions relating to prior year
|
|
|
|
(800
|
)
|
|
(100
|
)
|
Decreases due to lapse of statute of limitations
|
(2,200
|
)
|
|
(300
|
)
|
|
—
|
|
Unrecognized tax benefit relating to loss or income from continuing operations, end of year
|
$
|
—
|
|
|
$
|
2,200
|
|
|
$
|
3,300
|
|
Interest and penalties (recovery) expense on the unrecognized tax benefit included in income tax expense from continuing operations
|
$
|
—
|
|
|
$
|
(600
|
)
|
|
$
|
400
|
|
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. As at
December 31, 2016
, the amount of interest and penalties on the unrecognized tax benefit included in current income tax liabilities in the consolidated balance sheet was approximately $
nil
(
December 31, 2015
-
$1.4 million
).The Company had
no
other material interest or penalties included in the consolidated statement of operations for the three years ended
December 31, 2016
, respectively.
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 the tax years 2009 through 2016 in certain jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefit disclosed above within the next twelve months.
On December 23, 2014, the Colombian Congress passed legislation which imposes an equity tax levied on Colombian operations for 2015, 2016 and 2017. The equity tax is calculated based on a legislated measure, which is based on the Company’s Colombian legal entities' balance sheet equity for tax purposes at January 1, 2015. This measure is subject to adjustment for inflation in future years. The equity tax rates for January 1, 2015, 2016 and 2017, are
1.15%
,
1%
and
0.4%
, respectively. The legal obligation for each year's equity tax liability arises on January 1 of each year; therefore, the Company recognized the annual amount of
$3.1 million
and
$3.8 million
for the equity tax expense in the consolidated statement of operations for the years ended December 31, 2016 and 2015. These amounts were paid in May and September of each year and at
December 31, 2016
, accounts payable included $
nil
(
December 31, 2015
- $
nil
).
12. Accounts Payable and Accrued Liabilities
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
Trade
|
$
|
80,072
|
|
|
$
|
54,402
|
|
Royalties
|
4,542
|
|
|
2,066
|
|
Employee compensation and severance
|
8,152
|
|
|
8,414
|
|
Other
|
14,285
|
|
|
5,896
|
|
|
$
|
107,051
|
|
|
$
|
70,778
|
|
13. Commitments and Contingencies
Purchase Obligations, Firm Agreements and Leases
As at
December 31, 2016
, future minimum payments under non-cancelable agreements with remaining terms in excess of one year were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ending December 31
|
|
Total
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
(Thousands of U.S. Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil transportation services
|
$
|
13,958
|
|
|
$
|
3,639
|
|
|
$
|
3,639
|
|
|
$
|
3,639
|
|
|
$
|
3,041
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Drilling, completions and seismic
|
4,159
|
|
|
2,172
|
|
|
1,987
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Operating leases
|
4,111
|
|
|
1,971
|
|
|
1,259
|
|
|
412
|
|
|
402
|
|
|
67
|
|
|
—
|
|
Software and telecommunication
|
35
|
|
|
24
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
22,263
|
|
|
$
|
7,806
|
|
|
$
|
6,896
|
|
|
$
|
4,051
|
|
|
$
|
3,443
|
|
|
$
|
67
|
|
|
$
|
—
|
|
Gran Tierra leases certain office space, compressors, vehicles, equipment and housing. Total rent expense for the
year ended December 31, 2016
, was
$3.2 million
(
year ended December 31, 2015
–
$4.0 million
;
year ended December 31, 2014
-
$3.2 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.
The Company provided the purchaser of its Argentina business unit with certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations. The Company does not believe that these obligations are probable of having a material impact on its consolidated financial position, results of operations or cash flows.
Letters of credit
At
December 31, 2016
, the Company had provided promissory notes totaling
$96.8 million
(
December 31, 2015
-
$76.5 million
) as security for letters of credit relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.
Contingencies
On June 6, 2016, the Company received a positive decision from the Chamber of Commerce of Bogotá Center for Arbitration and Conciliation tribunal (the "Tribunal") relating to its dispute with the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) of Colombia ("ANH") with respect to whether all production from the Moqueta Exploitation Area of the Chaza Block exploration and production contract ("Chaza Contract") was subject to an additional royalty (the "HPR Royalty"). In its decision, the Tribunal found that the HPR Royalty under the Chaza Contract was only payable when the
accumulated oil production from the Moqueta Exploitation Area exceeded
5.0
MMbbl. That production threshold was reached on April 30, 2015, and since that time the Company has been paying the HPR Royalty on production from the Moqueta Exploitation Area.
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
$45.9 million
as at
December 31, 2016
. 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.
14. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk
Financial Instruments
At
December 31, 2016
, the Company’s financial instruments recognized in the balance sheet consist of; cash and cash equivalents; restricted cash; accounts receivable; derivative assets and liabilities; 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 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 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 quoted market prices in an active market and an option pricing model such as the Monte Carlo
simulation option-pricing models.
The fair value of trading securities which were received as consideration on the sale of the Company's Argentina business unit is estimated based on quoted market prices in an active market.
The fair value of trading securities, derivative assets, and RSU and PSU liabilities at
December 31, 2016
, and
December 31, 2015
were as follows:
|
|
|
|
|
|
|
|
|
|
As at December 31,
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
Foreign currency derivative asset
|
$
|
578
|
|
|
$
|
—
|
|
Trading securities
|
—
|
|
|
6,250
|
|
|
$
|
578
|
|
|
$
|
6,250
|
|
|
|
|
|
Commodity price derivative liability
|
$
|
3,824
|
|
|
$
|
—
|
|
RSU, PSU and DSU liability
|
3,907
|
|
|
1,189
|
|
|
$
|
7,731
|
|
|
$
|
1,189
|
|
During the year ended December 31, 2016, the Company sold the trading securities for cash proceeds of
$2.3 million
(year ended December 31, 2015 -
nil
). These 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.
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,
|
|
2016
|
|
2015
|
|
2014
|
Trading securities loss
|
$
|
3,925
|
|
|
$
|
1,335
|
|
|
$
|
6,326
|
|
Commodity price derivative loss
|
7,370
|
|
|
—
|
|
|
—
|
|
Foreign currency derivatives (gain) loss
|
(1,016
|
)
|
|
692
|
|
|
(1,604
|
)
|
|
$
|
10,279
|
|
|
$
|
2,027
|
|
|
$
|
4,722
|
|
These losses are presented as financial instruments loss in the consolidated statements of operations and cash flows. Trading securities losses related to losses on the Madalena shares Gran Tierra received in connection with the sale of its Argentina business unit in June 2014 (Note 4). All trading securities were sold during the year ended
December 31, 2016
and the trading securities loss represented a realized loss. For the years ended December 31, 2015 and 2014, the trading securities loss represented an unrealized loss.
Financial instruments not recorded at fair value include the Notes (Note 8). At
December 31, 2016
, the carrying amount of the
Notes was
$109.9 million
, which represents the aggregate principal amount less unamortized debt issuance costs, and the fair value was
$135.6 million
. The fair value of long-term restricted cash 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.
The fair value of the RSU liability was determined using Level 1 inputs. The fair value of the derivatives was determined using Level 2 inputs. The fair value of the PSU liability was determined using Level 3 inputs.
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 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 Notes was determined using Level 2 inputs based on the indicative pricing published by certain investment banks or trading levels of the 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 restricted cash 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, 2016
, the Company had outstanding commodity price derivative positions as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period and type of instrument
|
Volume,
bopd
|
Reference
|
Sold Put
($/bbl)
|
Purchased Put
($/bbl)
|
Sold Call
($/bbl)
|
Premiums received/(paid)
($/bbl)
|
Collar: June 1, 2016 to May 31, 2017
|
10,000
|
|
ICE Brent
|
$
|
35
|
|
$
|
45
|
|
$
|
65
|
|
$
|
(1.25
|
)
|
Collar: June 1, 2017 to December 31, 2017
|
10,000
|
|
ICE Brent
|
$
|
35
|
|
$
|
45
|
|
$
|
65
|
|
$
|
0.475
|
|
Collar: October 1, 2016 to December 31, 2017
|
5,000
|
|
ICE Brent
|
$
|
35
|
|
$
|
45
|
|
$
|
65
|
|
$
|
—
|
|
During the year ended December 31, 2016, the Company paid net premiums upon entering into commodity price derivatives of
$3.5 million
.
Collars are a combination of put options (floor) and sold call options (ceiling). For a collar position, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor strike price while the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling strike price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor strike price and equal to or less than the ceiling strike price. At December 31, 2015, we did not have any open commodity price derivative positions.
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 costs.
At
December 31, 2016
, the Company had outstanding foreign currency derivative positions as follows:
|
|
|
|
|
|
|
|
|
|
|
Period and type of instrument
|
Amount hedged
(Millions COP)
|
Reference
|
Purchased Call
(COP)
|
Sold Put
(1)
(COP)
|
Sold Put
(1)
(COP)
|
Collar: January 1, 2017 to March 31, 2017
|
31,597.6
|
|
COP
|
3,100
|
|
3,300
|
|
3,345
|
|
Collar: April 1, 2017 to May 31, 2017
|
22,697.2
|
|
COP
|
3,100
|
|
3,310
|
|
3,370
|
|
|
54,294.8
|
|
|
|
|
|
(1)
The put levels noted in the table above varied based on market conditions at the inception of each foreign currency derivative contract.
At December 31, 2015, the Company did not have any open foreign currency derivative positions. 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
$43,000
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, 2016, deferred tax balances, adjusted for the expected effect of the adoption of ASU 2016-16.
For the
year ended
December 31, 2016
,
97%
(
year ended
December 31, 2015
-
97%
,
year ended December 31, 2014
-
95%
) 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. In Brazil, prices for oil are in U.S. dollars, but revenues are received in local currency translated according to current exchange rates. The majority of the Company's capital expenditures within Brazil are based on U.S. dollar prices, but are paid in local currency translated according to current exchange rates. In Peru, capital expenditures are based on U.S. dollar prices and may be paid in local currency or U.S. dollars.
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, 2016
, cash and cash equivalents and restricted cash included balances in bank accounts, term deposits and certificates of deposit, placed with financial institutions with strong investment grade ratings or governments.
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, 2016
, the Company had
three
customers which were significant to the Colombian segment, and
one
customer which was significant to the Brazil 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.
15. Severance Expenses
During the years ended December 31, 2016 and 2015, the Company reduced the number of its employees and contractors. Severance expenses were recorded as incurred based on existing employee contracts, statutory requirements, completed negotiations and company policy. Severance expenses were
$1.3 million
,
$9.0 million
and $
nil
in the three years ended December 31, 2016. At December 31, 2015, $
nil
(December 31, 2014 -
$1.5 million
) severance expense was payable.
16. Supplemental Cash Flow Information
Net changes in assets and liabilities from operating activities of continuing operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Accounts receivable and other long-term assets
|
$
|
(29
|
)
|
|
$
|
44,365
|
|
|
$
|
(34,473
|
)
|
Derivatives
|
(3,546
|
)
|
|
—
|
|
|
—
|
|
Inventory
|
5,510
|
|
|
(1,571
|
)
|
|
(2,891
|
)
|
Other prepaids
|
(615
|
)
|
|
152
|
|
|
4
|
|
Accounts payable and accrued and other long-term liabilities
|
(9,691
|
)
|
|
(33,743
|
)
|
|
2,988
|
|
Prepaid tax and taxes receivable and payable
|
(2,966
|
)
|
|
(48,251
|
)
|
|
(61,064
|
)
|
Net changes in assets and liabilities from operating activities of continuing operations
|
$
|
(11,337
|
)
|
|
$
|
(39,048
|
)
|
|
$
|
(95,436
|
)
|
The following table provides additional supplemental cash flow disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2016
|
|
2015
|
|
2014
|
Cash paid for income taxes
|
$
|
64,067
|
|
|
$
|
39,422
|
|
|
$
|
101,179
|
|
Cash paid for interest
|
$
|
5,624
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Non-cash investing activities:
|
|
|
|
|
|
|
|
Net liabilities related to property, plant and equipment, end of year
|
$
|
55,181
|
|
|
$
|
33,923
|
|
|
$
|
113,874
|
|
Acquisition of marketable securities as proceeds from sale of Argentina business unit (Note 4)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
13,912
|
|
See Note 3 in these consolidated financial statements for disclosure regarding shares issued in connection with the Company's acquisition of Petroamerica.
17. Subsequent Event
On February, 6, 2017, Gran Tierra announced that a purchase and sale agreement (the "Agreement") had been executed by the Purchaser to purchase Gran Tierra's Brazil business unit through the acquisition of all of the equity interests in
one
of Gran Tierra's indirect subsidiaries, and the assignment of certain debt owed by the corporate entities comprising Gran Tierra's Brazil business unit to the Gran Tierra group of companies (the "Brazil Divestiture").
Upon completion of the Brazil Divestiture, the Purchaser will acquire all of Gran Tierra's assets and certain liabilities in Brazil, including its
100%
working interest in the Tiê Field and all of Gran Tierra's interest in exploration rights and obligations held pursuant to concession agreements granted by the Agência Nacional do Petróleo, Gás Natural e Biocombustíveis of Brazil ("ANP").
The completion of the Brazil Divestiture is subject to the Purchaser obtaining financing, as well as customary closing conditions, including the receipt of required regulatory approval from the ANP. The consideration to be received by Gran Tierra on the completion of the Brazil Divestiture is
$35 million
, subject to adjustments, plus the assumption by the Purchaser of certain existing and potential liabilities of Gran Tierra's Brazil business unit. Pursuant to the Agreement, the Purchaser paid a deposit of
$3.5 million
on
February 7, 2017
, which is not refundable in the event the Purchaser is not successful in obtaining financing to complete the Brazil Divestiture.
The economic effective date of the transaction will be on or before August 1, 2017, and Gran Tierra will continue to operate its Brazil business unit until the completion of the Brazil Divestiture.
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, 2013
,
2014
,
2015
and
2016
, and the changes in total net proved reserves during the three-year period ended
December 31, 2016
.
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, 2016
, 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 for a description of Gran Tierra’s reserves estimation process.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Colombia
|
|
Argentina
|
|
Brazil
|
Total
|
|
|
Liquids
(1)
|
|
Gas
|
|
Liquids
(1)
|
|
Gas
|
|
Liquids
(1)
|
|
Gas
|
|
Liquids
(1)
|
|
Gas
|
|
|
(Mbbl)
|
|
(MMcf)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(Mbbl)
|
|
(MMcf)
|
Proved NAR Reserves, December 31, 2013
|
|
34,559
|
|
|
8,776
|
|
|
3,604
|
|
|
4,677
|
|
|
1,683
|
|
|
—
|
|
|
39,846
|
|
|
13,453
|
|
Extensions and discoveries
|
|
4,099
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
572
|
|
|
—
|
|
|
4,671
|
|
|
—
|
|
Production
|
|
(6,654
|
)
|
|
(329
|
)
|
|
(385
|
)
|
|
(713
|
)
|
|
(330
|
)
|
|
—
|
|
|
(7,369
|
)
|
|
(1,042
|
)
|
Revisions of previous estimates
|
|
—
|
|
|
—
|
|
|
(3,219
|
)
|
|
(3,964
|
)
|
|
—
|
|
|
—
|
|
|
(3,219
|
)
|
|
(3,964
|
)
|
Revisions of Previous Estimates
|
|
2,040
|
|
|
(7,464
|
)
|
|
—
|
|
|
—
|
|
|
911
|
|
|
—
|
|
|
2,951
|
|
|
(7,464
|
)
|
Proved NAR Reserves, December 31, 2014
|
|
34,044
|
|
|
983
|
|
|
—
|
|
|
—
|
|
|
2,836
|
|
|
—
|
|
|
36,880
|
|
|
983
|
|
Extensions and discoveries
|
|
410
|
|
|
526
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,805
|
|
|
410
|
|
|
3,331
|
|
Improved recoveries
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,396
|
|
|
—
|
|
|
1,396
|
|
|
—
|
|
Production
|
|
(6,872
|
)
|
|
(318
|
)
|
|
—
|
|
|
—
|
|
|
(189
|
)
|
|
—
|
|
|
(7,061
|
)
|
|
(318
|
)
|
Revisions of previous estimates
|
|
5,804
|
|
|
632
|
|
|
—
|
|
|
—
|
|
|
680
|
|
|
—
|
|
|
6,484
|
|
|
632
|
|
Proved NAR Reserves, December 31, 2015
|
|
33,386
|
|
|
1,823
|
|
|
—
|
|
|
—
|
|
|
4,723
|
|
|
2,805
|
|
|
38,109
|
|
|
4,628
|
|
Purchases of reserves in place
|
|
20,568
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,568
|
|
|
—
|
|
Extensions and discoveries
|
|
1,142
|
|
|
435
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,142
|
|
|
435
|
|
Production
|
|
(8,125
|
)
|
|
(592
|
)
|
|
—
|
|
|
—
|
|
|
(262
|
)
|
|
(2
|
)
|
|
(8,387
|
)
|
|
(594
|
)
|
Revisions of previous estimates
|
|
(1,093
|
)
|
|
(71
|
)
|
|
—
|
|
|
—
|
|
|
1,591
|
|
|
783
|
|
|
498
|
|
|
712
|
|
Proved NAR Reserves, December 31, 2016
|
|
45,878
|
|
|
1,595
|
|
|
—
|
|
|
—
|
|
|
6,052
|
|
|
3,586
|
|
|
51,930
|
|
|
5,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves, December 31, 2014
|
|
27,866
|
|
|
983
|
|
|
—
|
|
|
—
|
|
|
1,333
|
|
|
—
|
|
|
29,199
|
|
|
983
|
|
Proved Developed Reserves NAR, December 31, 2015
|
|
28,513
|
|
|
1,346
|
|
|
—
|
|
|
—
|
|
|
2,303
|
|
|
1,368
|
|
|
30,816
|
|
|
2,714
|
|
Proved Developed Reserves NAR, December 31, 2016
|
|
35,529
|
|
|
1,468
|
|
|
—
|
|
|
—
|
|
|
1,912
|
|
|
1,382
|
|
|
37,441
|
|
|
2,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves NAR, December 31, 2014
|
|
6,178
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,503
|
|
|
—
|
|
|
7,681
|
|
|
—
|
|
Proved Undeveloped Reserves NAR, December 31, 2015
|
|
4,873
|
|
|
477
|
|
|
—
|
|
|
—
|
|
|
2,420
|
|
|
1,437
|
|
|
7,293
|
|
|
1,914
|
|
Proved Undeveloped Reserves NAR, December 31, 2016
|
|
10,349
|
|
|
127
|
|
|
—
|
|
|
—
|
|
|
4,140
|
|
|
2,203
|
|
|
14,489
|
|
|
2,330
|
|
(1)
At December 31, 2016, 2015 and 2014, liquids reserves are 100% oil. At December 31, 2013, the Company had NGL reserves in small amounts in Colombia and Argentina only.
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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Proved Properties
|
|
Unproved Properties
|
|
Accumulated
Depletion,
Depreciation
and
Impairment
|
|
Net Capitalized Costs
|
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
|
|
|
|
|
|
|
|
|
|
Colombia
|
$
|
1,846,522
|
|
|
$
|
147,500
|
|
|
$
|
(1,422,617
|
)
|
|
$
|
571,405
|
|
Brazil
|
151,808
|
|
|
69,089
|
|
|
(106,124
|
)
|
|
114,773
|
|
Peru
|
—
|
|
|
94,182
|
|
|
—
|
|
|
94,182
|
|
Balance, December 31, 2015
|
$
|
1,998,330
|
|
|
$
|
310,771
|
|
|
$
|
(1,528,741
|
)
|
|
$
|
780,360
|
|
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
|
|
Argentina
|
|
Brazil
|
|
Peru
|
|
Total
|
Balance, December 31, 2013
|
|
$
|
1,582,847
|
|
|
$
|
274,976
|
|
|
$
|
176,317
|
|
|
$
|
221,405
|
|
|
$
|
2,255,545
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Unproved
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration costs
|
|
88,378
|
|
|
82
|
|
|
11,106
|
|
|
173,126
|
|
|
272,692
|
|
Development costs
|
|
124,307
|
|
|
18,179
|
|
|
12,983
|
|
|
—
|
|
|
155,469
|
|
Balance, December 31, 2014
|
|
1,795,532
|
|
|
293,237
|
|
|
200,406
|
|
|
394,531
|
|
|
2,683,706
|
|
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
|
|
|
293,237
|
|
|
220,344
|
|
|
444,878
|
|
|
2,841,413
|
|
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
|
|
|
$
|
293,237
|
|
|
$
|
235,490
|
|
|
$
|
449,863
|
|
|
$
|
3,876,381
|
|
D. Results of Operations for Oil and Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
Colombia
|
|
Brazil
|
|
Peru
|
|
Total Continuing Operations
|
Argentina
|
Total
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
$
|
280,872
|
|
|
$
|
8,397
|
|
|
$
|
—
|
|
|
$
|
289,269
|
|
$
|
—
|
|
$
|
289,269
|
|
Production costs
|
(116,141
|
)
|
|
(2,560
|
)
|
|
—
|
|
|
(118,701
|
)
|
—
|
|
(118,701
|
)
|
Exploration expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
DD&A expenses
|
(132,569
|
)
|
|
(3,819
|
)
|
|
(544
|
)
|
|
(136,932
|
)
|
—
|
|
(136,932
|
)
|
Asset Impairment
|
(514,314
|
)
|
|
(71,143
|
)
|
|
(31,192
|
)
|
|
(616,649
|
)
|
|
(616,649
|
)
|
Income tax expense
|
187,168
|
|
|
(674
|
)
|
|
—
|
|
|
186,494
|
|
—
|
|
186,494
|
|
Results of Operations
|
$
|
(294,984
|
)
|
|
$
|
(69,799
|
)
|
|
$
|
(31,736
|
)
|
|
$
|
(396,519
|
)
|
$
|
—
|
|
$
|
(396,519
|
)
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
$
|
269,035
|
|
|
$
|
6,976
|
|
|
$
|
—
|
|
|
$
|
276,011
|
|
$
|
—
|
|
$
|
276,011
|
|
Production costs
|
(109,406
|
)
|
|
(6,363
|
)
|
|
—
|
|
|
(115,769
|
)
|
—
|
|
(115,769
|
)
|
Exploration expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
DD&A expenses
|
(167,701
|
)
|
|
(6,183
|
)
|
|
(789
|
)
|
|
(174,673
|
)
|
—
|
|
(174,673
|
)
|
Asset Impairment
|
(235,069
|
)
|
|
(46,933
|
)
|
|
(41,916
|
)
|
|
(323,918
|
)
|
—
|
|
(323,918
|
)
|
Income tax expense
|
102,014
|
|
|
(880
|
)
|
|
—
|
|
|
101,134
|
|
—
|
|
101,134
|
|
Results of Operations
|
$
|
(141,127
|
)
|
|
$
|
(53,383
|
)
|
|
$
|
(42,705
|
)
|
|
$
|
(237,215
|
)
|
$
|
—
|
|
$
|
(237,215
|
)
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
$
|
532,196
|
|
|
$
|
27,202
|
|
|
$
|
—
|
|
|
$
|
559,398
|
|
$
|
31,938
|
|
$
|
591,336
|
|
Production costs
|
(107,101
|
)
|
|
(6,848
|
)
|
|
—
|
|
|
(113,949
|
)
|
(14,612
|
)
|
(128,561
|
)
|
Exploration expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
DD&A expenses
|
(174,063
|
)
|
|
(9,932
|
)
|
|
(690
|
)
|
|
(184,685
|
)
|
(13,684
|
)
|
(198,369
|
)
|
Asset Impairment
|
—
|
|
|
—
|
|
|
(265,126
|
)
|
|
(265,126
|
)
|
—
|
|
(265,126
|
)
|
Income tax expense
|
(125,171
|
)
|
|
(844
|
)
|
|
68
|
|
|
(125,947
|
)
|
(1,458
|
)
|
(127,405
|
)
|
Results of Operations
|
$
|
125,861
|
|
|
$
|
9,578
|
|
|
$
|
(265,748
|
)
|
|
$
|
(130,309
|
)
|
$
|
2,184
|
|
$
|
(128,125
|
)
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
2016
|
$
|
31.67
|
|
$
|
31.42
|
|
2015
|
$
|
43.51
|
|
$
|
37.72
|
|
2014
|
$
|
87.55
|
|
$
|
84.63
|
|
Weighted average production costs
|
|
|
2016
|
$
|
15.42
|
|
$
|
12.19
|
|
2015
|
$
|
12.11
|
|
$
|
8.30
|
|
2014
|
$
|
14.74
|
|
$
|
11.24
|
|
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, 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
|
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
Future cash inflows
|
$
|
3,020,286
|
|
|
$
|
240,022
|
|
|
$
|
3,260,308
|
|
Future production costs
|
(998,809
|
)
|
|
(63,928
|
)
|
|
(1,062,737
|
)
|
Future development costs
|
(182,503
|
)
|
|
(14,150
|
)
|
|
(196,653
|
)
|
Future asset retirement obligations
|
(16,410
|
)
|
|
(3,500
|
)
|
|
(19,910
|
)
|
Future income tax expense
|
(558,048
|
)
|
|
(20,554
|
)
|
|
(578,602
|
)
|
Future net cash flows
|
1,264,516
|
|
|
137,890
|
|
|
1,402,406
|
|
10% discount
|
(337,969
|
)
|
|
(43,304
|
)
|
|
(381,273
|
)
|
Standardized Measure of Discounted Future Net Cash Flows
|
$
|
926,547
|
|
|
$
|
94,586
|
|
|
$
|
1,021,133
|
|
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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands of U.S. Dollars)
|
2016
|
|
2015
|
|
2014
|
Balance, beginning of year
|
$
|
464,757
|
|
|
$
|
1,021,133
|
|
|
$
|
1,344,953
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(207,776
|
)
|
|
(160,242
|
)
|
|
(444,358
|
)
|
Net changes in prices and production costs related to future production
|
13,425
|
|
|
(918,746
|
)
|
|
(40,162
|
)
|
Extensions, discoveries and improved recovery, less related costs
|
111
|
|
|
22,754
|
|
|
152,426
|
|
Previously estimated development costs incurred during the year
|
34,917
|
|
|
54,904
|
|
|
107,842
|
|
Revisions of previous quantity estimates
|
(263,713
|
)
|
|
144,603
|
|
|
103,359
|
|
Accretion of discount
|
73,076
|
|
|
137,853
|
|
|
180,787
|
|
Purchases of reserves in place
|
186,393
|
|
|
—
|
|
|
—
|
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
(72,089
|
)
|
Net change in income taxes
|
178,273
|
|
|
100,587
|
|
|
(256,033
|
)
|
Changes in future development costs
|
(26,758
|
)
|
|
61,911
|
|
|
(55,592
|
)
|
Net decrease
|
(12,052
|
)
|
|
(556,376
|
)
|
|
(323,820
|
)
|
Balance, end of year
|
$
|
452,705
|
|
|
$
|
464,757
|
|
|
$
|
1,021,133
|
|
2) Summarized Quarterly Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Year Ended
|
(Thousands of U.S. Dollars, Except Per Share Amounts)
|
March 31, 2015
|
June 30,
2015
|
September 30, 2015
|
December 31, 2015
|
|
December 31, 2015
|
Oil and natural gas sales
|
$
|
76,231
|
|
$
|
69,350
|
|
$
|
75,653
|
|
$
|
54,777
|
|
|
$
|
276,011
|
|
|
|
|
|
|
|
|
Asset impairment
|
$
|
37,014
|
|
$
|
30,285
|
|
$
|
149,979
|
|
$
|
106,640
|
|
|
$
|
323,918
|
|
|
|
|
|
|
|
|
Net loss
|
$
|
(44,866
|
)
|
$
|
(38,564
|
)
|
$
|
(101,877
|
)
|
$
|
(82,722
|
)
|
|
$
|
(268,029
|
)
|
|
|
|
|
|
|
|
Loss per share - Basic and Diluted
|
$
|
(0.16
|
)
|
$
|
(0.13
|
)
|
$
|
(0.36
|
)
|
$
|
(0.29
|
)
|
|
$
|
(0.94
|
)
|