10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

 For the quarterly period ended June 30, 2018

or

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

 For the transition period from __________ to __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)

Delaware	98-0479924
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
900, 520 - 3 Avenue SW Calgary, Alberta Canada T2P 0R3
(Address of principal executive offices, including zip code)

(403) 265-3221

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.          Yes ý  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   

Yes   ý  No o

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

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o
	Emerging growth company o

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

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

On July 30, 2018, the following number of shares of the registrant’s capital stock were outstanding: 391,175,023 shares of the registrant’s Common Stock, $0.001 par value.

1

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended June 30, 2018

Table of contents

		Page
PART I	Financial Information
Item 1.	Financial Statements	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	36
PART II	Other Information
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 6.	Exhibits	38
SIGNATURES		39

2

 CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “budget”, “objective”, “could”, “should”, or similar expressions or variations on these expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct or that, even if correct, intervening circumstances will not occur to cause actual results to be different than expected. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, sustained or future declines in commodity prices; potential future impairments and reductions in proved reserve quantities and value; our operations are located in South America, and unexpected problems can arise due to guerilla activity; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; geographic, political and weather conditions can impact the production, transport or sale of our products; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict; our ability to execute business plans; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; the risk that current global economic and credit market conditions may impact oil prices and oil consumption more than we currently predict, which could cause us to further modify our strategy and capital spending program; those factors set out in Part I, Item 1A “Risk Factors” in our 2017 Annual Report on Form 10-K and in our other filings with the Securities and Exchange Commission (“SEC”). The information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the SEC and, except as otherwise required by the federal securities laws, we disclaim any obligation or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

In this document, the abbreviations set forth below have the following meanings:

bbl	barrel	BOE	barrels of oil equivalent
bopd	barrels of oil per day	BOEPD	barrels of oil equivalent per day
Mcf	thousand cubic feet	NAR	net after royalty

Sales volumes represent production NAR adjusted for inventory changes. Our oil and gas reserves are reported NAR. Our production is also reported NAR, except as otherwise specifically noted as "working interest production before royalties." Natural gas liquids ("NGLs") volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

3

PART I - Financial Information

Item 1. Financial Statements

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations (Unaudited)

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
OIL AND NATURAL GAS SALES (Notes 3 and 7)	$	163,446		$	96,128		$	301,674		$	190,787
EXPENSES
Operating	35,059			27,208			61,324			51,145
Transportation	6,522			6,492			13,519			13,434
Depletion, depreciation and accretion (Note 3)	46,607			31,813			86,068			58,689
General and administrative (Note 3)	13,213			9,513			24,373			18,225
Equity tax	—			—			—			1,224
Foreign exchange loss	1,924			3,897			982			2,050
Financial instruments loss (gain) (Note 10)	4,768			(1,447		)	11,714			(6,886		)
Interest expense (Note 5)	7,375			3,331			12,870			6,426
	115,468			80,807			210,850			144,307
LOSS ON SALE	(292		)	(9,076		)	(292		)	(9,076		)
INTEREST INCOME	610			245			1,396			653
INCOME BEFORE INCOME TAXES (Note 3)	48,296			6,490			91,928			38,057
INCOME TAX EXPENSE
Current (Note 8)	4,827			1,772			17,116			9,189
Deferred (Note 8)	23,169			11,525			36,651			22,904
	27,996			13,297			53,767			32,093
NET AND COMPREHENSIVE INCOME (LOSS)	$	20,300		$	(6,807	)	$	38,161		$	5,964
NET INCOME (LOSS) PER SHARE
- BASIC AND DILUTED	$	0.05		$	(0.02	)	$	0.10		$	0.01
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	391,054,204			398,585,290			391,173,460			398,795,023
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	427,455,092			398,585,290			427,242,014			398,816,091

(See notes to the condensed consolidated financial statements)

4

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)

	As at June 30, 2018			As at December 31, 2017
ASSETS
Current Assets
Cash and cash equivalents (Note 11)	$	125,807		$	12,326
Restricted cash and cash equivalents (Note 11)	2,836			11,787
Accounts receivable	63,030			45,353
Investment (Note 10)	32,654			25,055
Derivatives (Note 10)	930			302
Taxes receivable	62,689			40,831
Other current assets	14,423			9,591
Total Current Assets	302,369			145,245
Oil and Gas Properties (using the full cost method of accounting)
Proved	750,948			629,081
Unproved	423,808			464,948
Total Oil and Gas Properties	1,174,756			1,094,029
Other capital assets	3,440			5,195
Total Property, Plant and Equipment (Notes 3 and 4)	1,178,196			1,099,224
Other Long-Term Assets
Deferred tax assets	18,248			57,310
Investment (Note 10)	15,302			19,147
Other long-term assets (Note 11)	5,389			6,112
Goodwill (Note 3)	102,581			102,581
Total Other Long-Term Assets	141,520			185,150
Total Assets (Note 3)	$	1,622,085		$	1,429,619
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	126,726		$	125,876
Derivatives (Note 10)	27,157			21,151
Taxes payable	3,848			9,324
Asset retirement obligation	110			323
Equity compensation award liability (Note 10)	11,597			295
Total Current Liabilities	169,438			156,969
Long-Term Liabilities
Long-term debt (Notes 5 and 10)	398,130			256,542
Deferred tax liabilities	24,528			28,417
Asset retirement obligation	35,839			31,241
Equity compensation award liability (Note 10)	9,480			11,135
Other long-term liabilities	9,381			8,980
Total Long-Term Liabilities	477,358			336,315
Contingencies (Note 9)
Shareholders’ Equity
Common Stock (Note 6) (390,017,518 and 385,191,042 shares of Common Stock and 1,135,239 and 6,111,665 exchangeable shares, par value $0.001 per share, issued and outstanding as at June 30, 2018, and December 31, 2017, respectively)	10,295			10,295
Additional paid in capital	1,328,037			1,327,244
Deficit	(363,043		)	(401,204		)
Total Shareholders’ Equity	975,289			936,335
Total Liabilities and Shareholders’ Equity	$	1,622,085		$	1,429,619

(See notes to the condensed consolidated financial statements)

5

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)

	Six Months Ended June 30,
	2018			2017
Operating Activities
Net income	$	38,161		$	5,964
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 3)	86,068			58,689
Deferred tax expense	36,651			22,904
Stock-based compensation (Note 6)	10,202			3,183
Amortization of debt issuance costs (Note 5)	1,513			1,225
Cash settlement of restricted share units	(360		)	(501		)
Unrealized foreign exchange loss	539			1,076
Financial instruments loss (gain) (Note 10)	11,714			(6,886		)
Cash settlement of financial instruments (Note 10)	(15,483		)	1,216
Cash settlement of asset retirement obligation	(369		)	(298		)
Loss on sale	292			9,076
Net change in assets and liabilities from operating activities (Note 11)	(37,994		)	(28,112		)
Net cash provided by operating activities	130,934			67,536
Investing Activities
Additions to property, plant and equipment (Note 3)	(157,088		)	(104,025		)
Property acquisitions	(3,100		)	(30,410		)
Net proceeds from sale of Brazil business unit	—			34,481
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit	—			4,700
Changes in non-cash investing working capital	(6,142		)	(627		)
Net cash used in investing activities	(166,330		)	(95,881		)
Financing Activities
Proceeds from bank debt, net of issuance costs (Note 5)	4,988			98,304
Repayment of bank debt (Note 5)	(153,000		)	(33,000		)
Proceeds from exercise of stock options (Note 6)	845			—
Repurchase of shares of Common Stock (Note 6)	(1,208		)	(10,000		)
Proceeds from issuance of Senior Notes, net of issuance costs (Note 5)	288,087			—
Net cash provided by financing activities	139,712			55,304
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(69		)	(1,175		)
Net increase in cash, cash equivalents and restricted cash and cash equivalents	104,247			25,784
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 11)	26,678			43,267
Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 11)	$	130,925		$	69,051
Supplemental cash flow disclosures (Note 11)

(See notes to the condensed consolidated financial statements)

6

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)

	Six Months Ended June 30,			Six Months Ended June 30,
	2018			2017
Share Capital
Balance, beginning of period	$	10,295		$	10,303
Repurchase of Common Stock (Note 6)	—			(4		)
Balance, end of period	10,295			10,299
Additional Paid in Capital
Balance, beginning of period	1,327,244			1,342,656
Exercise of stock options (Note 6)	845			—
Stock-based compensation (Note 6)	1,156			1,354
Repurchase of Common Stock (Note 6)	(1,208		)	(9,996		)
Balance, end of period	1,328,037			1,334,014
Deficit
Balance, beginning of period	(401,204		)	(493,972		)
Net income	38,161			5,964
Cumulative adjustment for accounting change related to tax reorganizations	—			124,476
Balance, end of period	(363,043		)	(363,532		)
Total Shareholders’ Equity	$	975,289		$	980,781

(See notes to the condensed consolidated financial statements)

7

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

(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.

2. Significant Accounting Policies

These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2017, included in the Company’s 2017 Annual Report on Form 10-K, filed with the SEC on February 27, 2018.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2017 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as noted below. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

Recently Adopted Accounting Pronouncements

Revenue from Contracts with Customers

The Company adopted Accounting Standard Codification ("ASC") 606 Revenue from Contracts with Customers with a date of initial application of January 1, 2018 in accordance with the modified retrospective approach without using the practical expedients. Except for providing enhanced disclosures about the Company's revenue transactions, the application of ASC 606 did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.

a) Significant Accounting Policy

The Company's revenue relates to oil and natural gas sales in Colombia. The Company recognizes revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents the Company's share and is recorded net of royalty payments to governments and other mineral interest owners.

The Company evaluates its arrangement with third parties and partners to determine if the Company acts as a principal or an agent. In making this evaluation, management considers if the Company obtains control of the product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by the Company from the transaction.

Tariffs, tolls and fees charged to other entities for use of pipelines owned by the Company are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements.

In the comparative period, revenue from the production of oil and natural gas was recognized when the customer took title and assumed the risks and rewards of ownership, prices were fixed or determinable, the sale was evidenced by a contract and collection of the revenue was reasonably assured.

8

b) Significant Judgments

When determining if the Company acted as a principal or as an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers detailed criteria for revenue recognition set out in ASC 606.

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 addressed certain aspects of recognition, measurement, presentation and disclosure of financial instruments. ASU 2016-01 was effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. The implementation of this update did not impact on the Company’s consolidated financial position, results of operations or cash flows or disclosure.

In February 2018, the FASB issued ASU 2018-03, "Recognition and Measurement of Financial Assets and Financial Liabilities". ASU 2018-03 clarified certain aspects of the guidance in ASU 2016-01. ASU 2018-03 is effective for annual reporting periods beginning after December 15, 2017 and interim reporting periods within those annual reporting periods beginning after June 15, 2018. Early adoption is permitted upon adoption of ASU 2016-01.The amendments should be applied retrospectively with a cumulative-effect adjustment to the effective date of ASU 2016-01. The Company early adopted this update on January 1, 2018. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Recently Issued but Not Yet Adopted Accounting Pronouncements

Leases

In January 2018, the FASB issued ASU 2018-01, "Land Easement Practical Expedient for Transition to Topic 842". ASU 2018-01 provides an optional transition practical expedient that, if elected, would not require an organization to reconsider their accounting for existing or expired land easements that were not previously accounted for as leases under Topic 840. The effective date and transition requirements for the amendment is the same as the effective date and transition requirements in Update 2016-02. The Company is planning to adopt ASU 2018-01 upon transition to ASU 2016-01 "Leases".

The Company is finalizing an assessment of its contract inventory using certain practical expedients to determine which contracts meet the definition of a lease. The next steps will include classifying leases as either financing or operating, establishing interest rates and determining the value of right-of-use lease assets and lease liabilities. The Company expects to apply the guidance of ASU 2016-02 using a modified retrospective transition approach.

3. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. Commencing 2018, the Company has one reportable segment based on geographic organization, Colombia. Prior to the sale of the Company's Brazil business unit effective June 30, 2017 and Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. The "All Other" category represents the Company’s corporate activities, Mexico activities and Brazil and Peru activities until the date of sale.

9

The following tables present information on the Company’s reportable segments and other activities:

	Three Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	163,446	$	—		$	163,446
Depletion, depreciation and accretion	46,065		542			46,607
General and administrative expenses	7,213		6,000			13,213
Income (loss) before income taxes	51,029		(2,733		)	48,296
Segment capital expenditures	83,757		637			84,394
	Three Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	91,905	$	4,223		$	96,128
Depletion, depreciation and accretion	30,130		1,683			31,813
General and administrative expenses	5,229		4,284			9,513
Income (loss) before income taxes	21,598		(15,108		)	6,490
Segment capital expenditures	55,436		2,429			57,865
	Six Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	301,674	$	—		$	301,674
Depletion, depreciation and accretion	84,564		1,504			86,068
General and administrative expenses	14,022		10,351			24,373
Income (loss) before income taxes	112,180		(20,252		)	91,928
Segment capital expenditures	156,318		770			157,088
	Six Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	182,369	$	8,418		$	190,787
Depletion, depreciation and accretion	55,065		3,624			58,689
General and administrative expenses	10,061		8,164			18,225
Income (loss) before income taxes	58,742		(20,685		)	38,057
Segment capital expenditures	98,276		5,749			104,025

	As at June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,176,540	$	1,656	$	1,178,196
Goodwill	102,581		—		102,581
All other assets	175,563		165,745		341,308
Total Assets	$	1,454,684	$	167,401	$	1,622,085
	As at December 31, 2017
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,096,833	$	2,391	$	1,099,224
Goodwill	102,581		—		102,581
All other assets	176,980		50,834		227,814
Total Assets	$	1,376,394	$	53,225	$	1,429,619

10

4. Property, Plant and Equipment

(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Oil and natural gas properties
Proved	$	3,014,725		$	2,810,796
Unproved	423,808			464,948
	3,438,533			3,275,744
Other	19,086			26,401
	3,457,619			3,302,145
Accumulated depletion, depreciation and impairment	(2,279,423		)	(2,202,921		)
	$	1,178,196		$	1,099,224

The Company used an average Brent price of $62.58 per bbl for the purposes of the June 30, 2018 ceiling test calculations (March 31, 2018 - $56.92, December 31, 2017 - $54.19).

5. Debt and Debt Issuance Costs

The Company's debt at June 30, 2018 and December 31, 2017 was as follows:

(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Senior notes	$	300,000		$	—
Convertible notes	115,000			115,000
Revolving credit facility	—			148,000
Unamortized debt issuance costs	(16,870		)	(6,458		)
Long-term debt	$	398,130		$	256,542

Senior Notes

On February 15, 2018, Gran Tierra Energy International Holdings Ltd. ("GTEIH"), an indirect, wholly owned subsidiary of the Company, issued $300 million of 6.25% Senior Notes due 2025 (the "Senior Notes"). The Senior Notes are fully and unconditionally guaranteed by the Company and certain subsidiaries of the Company that guarantee its revolving credit facility. Net proceeds from the sale of the Senior Notes were $288.1 million, after deducting the initial purchasers' discounts and commission and the offering expenses payable by the Company.

The Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Before February 15, 2022, GTEIH may, at its option, redeem all or a portion of the Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2022 - 103.125%; 2023 - 101.563%; 2024 and thereafter - 100%.

Interest Expense

The following table presents total interest expense recognized in the accompanying interim unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		2018		2017
Contractual interest and other financing expenses	$	6,532	$	2,711	$	11,357	$	5,201
Amortization of debt issuance costs	843		620		1,513		1,225
	$	7,375	$	3,331	$	12,870	$	6,426

11

6. Share Capital

On  May 1, 2018, Gran Tierra Exchangeco Inc., a subsidiary of the Company, announced that it had established a redemption date of July 5, 2018 in respect of all of its outstanding exchangeable shares. Effective July 5, 2018, all remaining outstanding exchangeable shares of record on July 4, 2018 were acquired for purchase consideration of one share of Gran Tierra common stock, and on July 9, 2018, the Company retired and canceled one share of Special A Voting Stock and one share of Special B Voting Stock, which held voting rights in connection with those exchangeable shares. As a result, no shares of Special A Voting Stock and Special B Voting Stock remain outstanding.

	Shares of Common Stock		Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2017	385,191,042		4,422,776		1,688,889
Options exercised	319,462		—		—
Shares repurchased and canceled	(469,412	)	—		—
Exchange of exchangeable shares	4,976,426		(3,287,537	)	(1,688,889	)
Balance, June 30, 2018	390,017,518		1,135,239		—

On March 7, 2018, the Company announced that it intended to implement a share repurchase program (the “2018 Program”) through the facilities of the Toronto Stock Exchange ("TSX") and eligible alternative trading platforms in Canada. Under the 2018 Program, the Company is able to purchase at prevailing market prices up to 19,269,732 shares of Common Stock, representing approximately 5.00% of the issued and outstanding shares of Common Stock as of March 8, 2018. Shares purchased pursuant to 2018 Program will be canceled. The 2018 Program will expire on March 11, 2019, or earlier if the 5.00% share maximum is reached.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock option activity for the six months ended June 30, 2018:

	PSUs		DSUs	RSUs		Stock Options
	Number of Outstanding Share Units		Number of Outstanding Share Units	Number of Outstanding Share Units		Number of Outstanding Stock Options		Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2017	6,131,951		455,768	122,090		8,960,692		3.65
Granted	3,544,001		131,888	—		1,996,526		2.51
Exercised	—		—	(120,268	)	(319,462	)	2.65
Forfeited	(213,160	)	—	(1,822	)	(491,475	)	5.42
Expired	—		—	—		(171,854	)	6.15
Balance, June 30, 2018	9,462,792		587,656	—		9,974,427		3.33

Stock-based compensation expense for the three and six months ended June 30, 2018, was $6.9 million and $10.2 million, respectively, and was primarily recorded in general and administrative ("G&A") expenses (three and six months ended June 30, 2017 - $2.0 million and $3.2 million, respectively).

At June 30, 2018, there was $23.0 million (December 31, 2017 - $13.7 million) of unrecognized compensation cost related to unvested PSUs and stock options which is expected to be recognized over a weighted average period of 1.8 years.

Net Income per Share

Basic net income per share is calculated by dividing net income by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income per share is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock method to reflect the potential dilution that

12

could occur if outstanding stock awards were vested at the end of the applicable period plus potentially issuable shares on conversion of the convertible notes. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

Weighted Average Shares Outstanding

	Three Months Ended June 30,			Six Months Ended June 30,
	2018		2017	2018		2017
Weighted average number of common and exchangeable shares outstanding	391,054,204		398,585,290	391,173,460		398,795,023
Shares issuable pursuant to stock options	4,894,633		—	2,420,509		625,631
Shares assumed to be purchased from proceeds of stock options	(4,308,138	)	—	(2,166,348	)	(604,563	)
Shares issuable pursuant to convertible notes	35,814,393		—	35,814,393		—
Weighted average number of diluted common and exchangeable shares outstanding	427,455,092		398,585,290	427,242,014		398,816,091

For the three months ended June 30, 2018, 5,240,018 options, on a weighted average basis, (three months ended June 30, 2017 - 10,634,157 options) were excluded from the diluted income (loss) per share calculation as the options were anti-dilutive. For the six months ended June 30, 2018, 7,385,714 options, on a weighted average basis, (six months ended June 30, 2017 - 9,616,800 options) were excluded from the diluted income per share calculation as the options were anti-dilutive. Shares issuable upon conversion of the 5.00% Convertible Notes due 2021 ("Convertible Notes") were dilutive and included in the diluted income per share calculation. For the three and six months ended June 30, 2018, the numerator used in the computation of diluted earnings per share included net income for the period adjusted for interest on convertible debentures and amortization of debt issuance costs of $1.7 million and $3.4 million, respectively.

7. Revenue

Most of the Company's revenues are from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to ICE Brent and adjusted for Vasconia crude, quality and transportation discounts each month. For the three and six months ended June 30, 2018, 100% (three and six months ended June 30, 2017 - 100%) of the Company's revenue resulted from oil sales. During the three and six months ended June 30, 2018, quality and transportation discounts were 14% and 15%, respectively, of the ICE Brent price (three and six months ended June 30, 2017 - 21% and 22%, respectively). During the three and six months ended June 30, 2018, the Company's production was sold primarily to three major customers in Colombia (three and six months ended June 30, 2017 - four).

As at June 30, 2018, accounts receivable included $4.8 million of accrued sales revenue which related to June 2018 production (December 31, 2017 - $11.1 million which related to December 31, 2017 production).

8. Taxes

The Company's effective tax rate was 58% in the six months ended June 30, 2018, compared with 84% in the comparative period in 2017. Current income tax expense was higher in the six months ended June 30, 2018, compared with the corresponding period in 2017, primarily as a result of higher taxable income in Colombia. The deferred income tax expense of $36.7 million for the six months ended June 30, 2018, was primarily due to excess tax depreciation compared with accounting depreciation in Colombia.  

For the six months ended June 30, 2018, the difference between the effective tax rate of 58% and the 21% U.S. statutory rate was primarily due to an increase to the impact of foreign taxes, valuation allowance, stock-based compensation, foreign currency translation and non-deductible third party royalty in Colombia.

For the comparative period in 2017, the effective tax rate differed from the U.S. statutory rate of 35% primarily due to an increase in the valuation allowance, which was largely attributable to losses incurred in the United States, Brazil and Colombia, as well as the impact of a non-deductible third-party royalty in Colombia, foreign and local taxes, and stock-based compensation. These items were partially offset by foreign currency translation adjustments and other permanent differences.

13

9. Contingencies

The Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“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 an additional royalty (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 $52.8 million as at June 30, 2018. At this time no amount has been accrued in the interim unaudited condensed consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

In addition to the above, the Company has a number of other lawsuits and claims pending. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, the Company 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 associated with these lawsuits and claims as they are incurred or become probable and determinable.

Letters of credit and other credit support

At June 30, 2018, the Company had provided letters of credit and other credit support totaling $69.8 million (December 31, 2017 - $76.0 million) as security relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.

10. Financial Instruments and Fair Value Measurement

Financial Instruments

At June 30, 2018, the Company’s financial instruments recognized in the balance sheet consisted of: cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; investments; derivatives, accounts payable and accrued liabilities, long-term debt and equity compensation award liability.

Fair Value Measurement

The fair value of certain investments, derivatives and equity compensation awards (PSU and DSU) liabilities are remeasured at the estimated fair value at the end of each reporting period.

The fair value of the short-term portion of the Company's investment in PetroTal Corp. ("PetroTal") (formerly Sterling Resources Ltd.) was estimated using quoted prices at June 30, 2018 and the foreign exchange rate at that time. The fair value of the long-term portion of the investment restricted by escrow conditions was estimated using observable and unobservable inputs; factors that were evaluated included quoted market prices, precedent comparable transactions, risk-free rate, measures of market risk volatility, estimates of the Company's and PetroTal's costs of capital and quotes from third parties.

The fair value of commodity price and foreign currency derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

The fair value of the PSU liability was estimated based on option pricing model using inputs such as quoted market prices in an active market, and PSU performance factors. The fair value of the DSU liabilities was estimated based on quoted market prices in an active market.

14

The fair value of the Company's investment in PetroTal, derivatives and PSU and DSU liabilities at June 30, 2018, and December 31, 2017, was as follows:

(Thousands of U.S. Dollars)	As at June 30, 2018		As at December 31, 2017
Investment in PetroTal shares - current and long-term	$	47,956	$	44,202
Foreign currency derivative asset	930		302
	$	48,886	$	44,504
Commodity price derivative liability	$	27,157	$	21,151
Equity compensation award liability - current and long-term	21,077		11,430
	$	48,234	$	32,581

The following table presents gains or losses on financial instruments recognized in the accompanying interim unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2017
Commodity price derivative loss (gain)	$	14,461		$	(1,545	)	$	19,455		$	(6,247	)
Foreign currency derivatives loss (gain)	1,945			98			(2,024		)	(639		)
Investment gain	(11,638		)	—			(5,717		)	—
Financial instruments loss (gain)	$	4,768		$	(1,447	)	$	11,714		$	(6,886	)

Investment gain for the three and six months ended June 30, 2018, related to the fair value gain on the PetroTal shares Gran Tierra received or subscribed for in connection with the sale of its Peru business unit in December 2017. For the three and six months ended June 30, 2018, this investment gain was unrealized.

Financial instruments not recorded at fair value include the Senior Notes and the Convertible Notes. At June 30, 2018, the carrying amounts of the Senior Notes and the Convertible Notes were $288.6 million and $111.5 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $282.0 million and $143.8 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.

At June 30, 2018, the fair value of the current portion of the investment and DSU liability was determined using Level 1 inputs, the fair value of derivatives and PSUs was determined using Level 2 inputs and the fair value of the long-term portion of the investment restricted by escrow conditions was determined using Level 3 inputs. The table below presents the fair value of the long-term portion of the investment:

	Six Months Ended			Year Ended
(Thousands of U.S. Dollars)	June 30, 2018			December 31, 2017
Opening balance, investment - long-term	$	19,147		$	—
Acquisition	—			19,091
Transfer from long-term (Level 3) to current (Level 1)	(4,787		)	—
Unrealized valuation gain	2,528			56
Unrealized foreign exchange loss	(1,586		)	—
Closing balance, investment - long-term	$	15,302		$	19,147

15

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 Senior Notes, Convertible Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure above regarding the fair value of the Convertible Notes was determined using Level 2 inputs based on the indicative pricing published by certain third-party services or trading levels of the Convertible Notes, which are not listed on any securities exchange or quoted on an inter-dealer automated quotation system. The disclosure in the paragraph above regarding the fair value of cash and restricted cash and cash equivalents, revolving credit facility and Senior Notes 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 June 30, 2018, the Company had outstanding commodity price derivative positions as follows:

Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

The Company does not have any outstanding commodity price derivative positions relating to 2019.

Foreign Currency Derivatives

The Company utilizes foreign currency derivatives to manage the variability in cash flows associated with the Company's forecasted Colombian peso ("COP") denominated expenses. At June 30, 2018, the Company had outstanding foreign currency derivative positions as follows:

Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: July 1, 2018 to December 31, 2018	87,000	29,685	COP	3,000	3,107

⁽¹⁾ At June 30, 2018 foreign exchange rate.

16

11. Supplemental Cash Flow Information

The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company's interim unaudited condensed consolidated balance sheet that sum to the total of the same such amounts shown in the interim unaudited condensed consolidated statements of cash flows:

(Thousands of U.S. Dollars)	As at June 30,				As at December 31,
	2018		2017		2017		2016
Cash and cash equivalents	$	125,807	$	53,310	$	12,326	$	25,175
Restricted cash and cash equivalents - current	2,836		5,844		11,787		8,322
Restricted cash and cash equivalents - long-term (included in other long-term assets)	2,282		9,897		2,565		9,770
	$	130,925	$	69,051	$	26,678	$	43,267

Net changes in assets and liabilities from operating activities were as follows:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017
Accounts receivable and other long-term assets	$	(11,723	)	$	11,024
Derivatives	3,431			—
Inventory	(3,054		)	(47		)
Prepaids	(301		)	2,190
Accounts payable and accrued and other long-term liabilities	971			(6,179		)
Taxes receivable and payable	(27,318		)	(35,100		)
Net changes in assets and liabilities from operating activities	$	(37,994	)	$	(28,112	)

The following table provides additional supplemental cash flow disclosures:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	62,009	$	56,044

17

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of our financial condition and results of operations should be read in conjunction with the "Financial Statements" as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q as well as the "Financial Statements and Supplementary Data" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in Part II, Items 8 and 7, respectively, of our 2017 Annual Report on Form 10-K, filed with the SEC on February 27, 2018. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements, as well as Part I, Item 1A “Risk Factors” in our 2017 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the second quarter of 2018⁽¹⁾ 

• Achieved a new company milestone: record Colombia working interest production before royalties of 35,400 BOEPD, 18%higher compared with 30,098 BOEPD in the second quarter of 2017. Production increased largely because of production from development activities in the Acordionero Field.

• The quarter's Colombia production was also up 57% from second quarter 2015 when the strategy to refocus Gran Tierra on Colombia began, an annual growth rate of 16%

• Since acquiring the Acordionero field in the Middle Magdalena Valley ("MMV") in August 2016, we have increased production 274% to a record high average rate during the quarter of 17,710 bopd (14,076 bopd NAR). From the acquisition date of August 23, 2016, until June 30, 2018, the MMV assets have generated $327 million in oil and natural gas sales

• Production NAR was 28,198 BOEPD, 12%higher than the second quarter of 2017.

• Continued significant exposure to oil price strength with oil representing 100% of our production

• Oil and natural gas sales volumes were 27,902 BOEPD, 11%higher than the second quarter of 2017. The quarter's increase in oil and gas sales volumes was driven by the production increase (5,302 bopd) , partially offset by higher royalties (2,383 bopd) due to higher oil prices and a change in inventories (149 bopd).

• Net income was $20.3 million compared with net loss of $6.8 million in the second quarter of 2017. Net loss in the comparative period included the loss on sale of Brazil business unit.

• Funds flow from operations⁽²⁾increased by 86% to $94.5 million compared with the second quarter of 2017, while the Brent price increased only 47% from the second quarter of 2017.

• Active quarter with capital expenditures of $84.4 million. Funds flow from operations exceeded capital expenditures by $10.2 million.

• Oil and gas sales per BOE were $64.37, 60%higher than the second quarter of 2017.

• Operating netback⁽²⁾ per BOE was $47.99, 85%higher compared with the second quarter of 2017.

• Operating expenses per BOE were $13.81, 21%higher compared with the second quarter of 2017 as a result of payments triggered by renegotiating our field operating agreements, power generation costs, equipment rental and accelerated maintenance costs, mainly in the Acordionero field, in the quarter.

• Quality and transportation discount was $10.53 per BOE compared with $10.74 per BOE in the second quarter of 2017; this $0.21 per BOE reduction resulted from optimization of transportation routes and narrowing of differentials

• Transportation expenses per BOE were $2.57, 7%lower compared with the second quarter of 2017. The decrease was due to the increased use of alternative transportation routes, which had lower costs per BOE.

• General and administrative ("G&A") expenses before stock-based compensation per BOE decreased by 18% to $2.60 per BOE compared with the second quarter of 2017.

• Exited the quarter with $125.8 million of cash and cash equivalents.

⁽¹⁾ Except for net income, funds flow from operations and G&A expenses, all numbers and comparisons above are based on Colombia only, excluding Brazil which was sold in 2017.

⁽²⁾ Funds flow from operations and operating netback are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to the non-GAAP measures disclosure below for a definition and reconciliation of these measures.

18

(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended June 30,								Three Months Ended March 31,			Six Months Ended June 30,
	2018			2017			% Change		2018			2018			2017			% Change
Average Daily Volumes (BOEPD)
Consolidated
Working Interest Production Before Royalties	35,400			31,437			13		35,075			35,239			30,663			15
Royalties	(7,202		)	(5,014		)	44		(6,886		)	(7,045		)	(5,051		)	39
Production NAR	28,198			26,423			7		28,189			28,194			25,612			10
Increase in Inventory	(296		)	(140		)	111		(986		)	(639		)	(61		)	948
Sales(1)	27,902			26,283			6		27,203			27,555			25,551			8
Colombia
Working Interest Production Before Royalties	35,400			30,098			18		35,075			35,239			29,294			20
Royalties	(7,202		)	(4,819		)	49		(6,886		)	(7,045		)	(4,843		)	45
Production NAR	28,198			25,279			12		28,189			28,194			24,451			15
Increase in Inventory	(296		)	(147		)	101		(986		)	(639		)	(70		)	813
Sales(1)	27,902			25,132			11		27,203			27,555			24,381			13
Net Income (Loss)	$	20,300		$	(6,807	)	398		$	17,861		$	38,161		$	5,964		540
Operating Netback
Oil and Natural Gas Sales	$	163,446		$	96,128		70		$	138,228		$	301,674		$	190,787		58
Operating Expenses	(35,059		)	(27,208		)	29		(26,265		)	(61,324		)	(51,145		)	20
Transportation Expenses	(6,522		)	(6,492		)	—		(6,997		)	(13,519		)	(13,434		)	1
Operating Netback(2)	$	121,865		$	62,428		95		$	104,966		$	226,831		$	126,208		80
G&A Expenses Before Stock-Based Compensation	$	6,604		$	7,610		(13	)	$	7,982		$	14,586		$	15,173		(4	)
G&A Stock-Based Compensation	6,609			1,903			247		3,178			9,787			3,052			221
General and Administrative ("G&A") Expenses, Including Stock-Based Compensation	$	13,213		$	9,513		39		$	11,160		$	24,373		$	18,225		34
EBITDA(2)	$	102,278		$	41,634		146		$	88,588		$	190,866		$	103,172		85
Funds Flow From Operations(2)	$	94,549		$	50,920		86		$	74,748		$	169,297		$	95,946		76
Capital Expenditures	$	84,394		$	57,865		46		$	72,694		$	157,088		$	104,025		51

19

	As at
(Thousands of U.S. Dollars)	June 30, 2018		December 31, 2017		% Change
Cash and Cash Equivalents	$	125,807	$	12,326	921
Revolving Credit Facility	$	—	$	148,000	(100	)
Senior Notes	$	300,000	$	—	—
Convertible Notes	$	115,000	$	115,000	—

⁽¹⁾ Sales volumes represent production NAR adjusted for inventory changes.

⁽²⁾ Non-GAAP measures

Operating netback, EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or loss or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as oil and natural gas sales less operating and transportation expenses. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil and natural gas sales to operating netback is provided in the table above.

EBITDA, as presented, is defined as net income or loss adjusted for depletion, depreciation and accretion ("DD&A") expenses, interest expense and income tax expense. Management uses this supplemental measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net loss to EBITDA is as follows:

	Three Months Ended June 30,					Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017			2018		2018		2017
Net income (loss)	$	20,300	$	(6,807	)	$	17,861	$	38,161	$	5,964
Adjustments to reconcile net income (loss) to EBITDA
DD&A expenses	46,607		31,813			39,461		86,068		58,689
Interest expense	7,375		3,331			5,495		12,870		6,426
Income tax expense	27,996		13,297			25,771		53,767		32,093
EBITDA (non-GAAP)	102,278		41,634			88,588		190,866		103,172

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense, stock-based compensation expense, amortization of debt issuance costs, cash settlement of RSUs, unrealized foreign exchange gains and losses, financial instruments gains or losses, cash settlement of financial instruments and loss on sale. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to funds flow from operations is as follows:

20

	Three Months Ended June 30,						Three Months Ended March 31,			Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2018			2017
Net income (loss)	$	20,300		$	(6,807	)	$	17,861		38,161			$	5,964
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses	46,607			31,813			39,461			86,068			58,689
Deferred tax expense	23,169			11,525			13,482			36,651			22,904
Stock-based compensation expense	6,893			1,980			3,309			10,202			3,183
Amortization of debt issuance costs	843			620			670			1,513			1,225
Cash settlement of RSUs	(240		)	(183		)	(120		)	(360		)	(501		)
Unrealized foreign exchange loss (gain)	1,583			3,895			(1,044		)	539			1,076
Financial instruments loss (gain)	4,768			(1,447		)	6,946			11,714			(6,886		)
Cash settlement of financial instruments	(9,666		)	448			(5,817		)	(15,483		)	1,216
Loss on sale	292			9,076			—			292			9,076
Funds flow from operations (non-GAAP)	$	94,549		$	50,920		$	74,748		$	169,297		$	95,946

Additional Operational Results

	Three Months Ended June 30,								Three Months Ended March 31,			Six Months Ended June 30,
	2018			2017			% Change		2018			2018			2017			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	163,446		$	96,128		70		$	138,228		$	301,674		$	190,787		58
Operating expenses	35,059			27,208			29		26,265			61,324			51,145			20
Transportation expenses	6,522			6,492			—		6,997			13,519			13,434			1
Operating netback(1)	121,865			62,428			95		104,966			226,831			126,208			80
DD&A expenses	46,607			31,813			47		39,461			86,068			58,689			47
G&A expenses before stock-based compensation	6,604			7,610			(13	)	7,982			14,586			15,173			(4	)
G&A stock-based compensation expense	6,609			1,903			247		3,178			9,787			3,052			221
Equity tax	—			—			—		—			—			1,224			(100	)
Foreign exchange loss (gain)	1,924			3,897			(51	)	(942		)	982			2,050			(52	)
Financial instruments loss (gain)	4,768			(1,447		)	430		6,946			11,714			(6,886		)	270
Interest expense	7,375			3,331			121		5,495			12,870			6,426			100
	73,887			47,107			57		62,120			136,007			79,728			71
Loss on sale	(292		)	(9,076		)	(97	)	—			(292		)	(9,076		)	(97	)
Interest income	610			245			149		786			1,396			653			114
Income before income taxes	48,296			6,490			644		43,632			91,928			38,057			142
Current income tax expense	4,827			1,772			172		12,289			17,116			9,189			86
Deferred income tax expense	23,169			11,525			101		13,482			36,651			22,904			60
	27,996			13,297			111		25,771			53,767			32,093			68
Net income (loss)	$	20,300		$	(6,807	)	398		$	17,861		$	38,161		$	5,964		540

21

Sales Volumes (NAR)
Total sales volumes, BOEPD	27,902			26,283			6		27,203			27,555			25,551			8
Average Prices
Oil and NGL's per bbl	$	64.50		$	40.44		59		$	56.63		$	60.64		$	41.65		46
Natural gas per Mcf	$	2.26		$	2.52		(10	)	$	2.91		$	2.67		$	1.91		40
Brent Price per bbl	$	74.90		$	50.92		47		$	67.18		$	71.04		$	52.79		35
Consolidated Results of Operations per BOE Sales Volumes NAR
Oil and natural gas sales	$	64.37		$	40.19		60		$	56.46		$	60.49		$	41.25		47
Operating expenses	13.81			11.38			21		10.73			12.30			11.06			11
Transportation expenses	2.57			2.71			(5	)	2.86			2.71			2.90			(7	)
Operating netback(1)	47.99			26.10			84		42.87			45.48			27.29			67
DD&A expenses	18.36			13.30			38		16.12			17.26			12.69			36
G&A expenses before stock-based compensation	2.60			3.18			(18	)	3.26			2.92			3.28			(11	)
G&A stock-based compensation expense	2.60			0.80			225		1.30			1.96			0.66			197
Equity tax	—			—			—		—			—			0.26			(100	)
Foreign exchange loss (gain)	0.76			1.63			(53	)	(0.38		)	0.20			0.44			(55	)
Financial instruments loss (gain)	1.88			(0.60		)	413		2.84			2.35			(1.49		)	258
Interest expense	2.90			1.39			109		2.24			2.58			1.39			86
	29.10			19.70			48		25.38			27.27			17.23			58
Loss on sale	(0.12		)	(3.79		)	(97	)	—			(0.06		)	(1.96		)	(97	)
Interest income	0.24			0.10			140		0.32			0.28			0.14			100
Income before income taxes	19.01			2.71			601		17.81			18.43			8.24			124
Current income tax expense	1.90			0.74			157		5.02			3.43			1.99			72
Deferred income tax expense	9.12			4.82			89		5.51			7.35			4.95			48
	11.02			5.56			98		10.53			10.78			6.94			55
Net income (loss)	$	7.99		$	(2.85	)	380		$	7.28		$	7.65		$	1.30		488

⁽¹⁾ Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures" for a definition and reconciliation of this measure.

22

Oil and Gas Production and Sales Volumes, BOEPD

	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017
Average Daily Volumes (BOEPD)	Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	35,400		30,098		1,339		31,437
Royalties	(7,202	)	(4,819	)	(195	)	(5,014	)
Production NAR	28,198		25,279		1,144		26,423
(Increase) Decrease in Inventory	(296	)	(147	)	7		(140	)
Sales	27,902		25,132		1,151		26,283
Royalties, % of Working Interest Production Before Royalties	20	%	16	%	15	%	16	%
	Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
Average Daily Volumes (BOEPD)	Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	35,239		29,294		1,369		30,663
Royalties	(7,045	)	(4,843	)	(208	)	(5,051	)
Production NAR	28,194		24,451		1,161		25,612
(Increase) Decrease in Inventory	(639	)	(70	)	9		(61	)
Sales	27,555		24,381		1,170		25,551
Royalties, % of Working Interest Production Before Royalties	20	%	17	%	15	%	16	%

Oil and gas production NAR for the three and six months ended June 30, 2018increased by 7% to 28,198 and by 10% to 28,194 BOEPD compared with 26,423 and 25,612 BOEPD, respectively, in the corresponding periods of 2017.

Colombian oil and gas production NAR for the three and six months ended June 30, 2018increased by 12% and 15%, respectively, compared with the corresponding periods of 2017.The increase in production was a result of successful drilling and a workover campaign in the Acordionero and Costayaco Fields and the Vonu-1 exploration well. Working interest production before royalties from the Acordionero Field averaged 17,710 bopd before royalties (14,076 bopd NAR) during the three months ended June 30, 2018 compared with 8,362 bopd in the corresponding period of 2017, a 112%increase. Acordionero Field production increased 959 bopd before royalties from the three months ended March 31, 2018. During the second quarter of 2018, four wells were brought on production. Production was negatively impacted by two Electronic Submersible Pumps ("ESPs") failures in Acordionero and one ESP failure in Costayaco.

Royalties as a percentage of production for the three and six months ended June 30, 2018increased compared with the corresponding periods of 2017 commensurate with the increase in oil prices due to price sensitive royalties payable in Colombia, higher API in the Acordionero Field and this field reaching the threshold for the High Price Royalties.

23

Operating Netbacks

	Three Months Ended June 30, 2018			Three Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Total			Colombia			Brazil			Total
Oil and Natural Gas Sales	$	163,446		$	91,905		$	4,223		$	96,128
Transportation Expenses	(6,522		)	(6,319		)	(173		)	(6,492		)
	156,924			85,586			4,050			89,636
Operating Expenses	(35,059		)	(26,192		)	(1,016		)	(27,208		)
Operating Netback(1)	$	121,865		$	59,394		$	3,034		$	62,428
U.S. Dollars Per BOE Sales Volumes NAR
Brent	$	74.90		$	50.92		$	50.92		$	50.92
Vasconia, Quality and Transportation Discounts	(10.53		)	(10.74		)	(10.62		)	(10.73		)
Average Realized Price	64.37			40.18			40.30			40.19
Transportation Expenses	(2.57		)	(2.76		)	(1.65		)	(2.71		)
Average Realized Price Net of Transportation Expenses	61.80			37.42			38.65			37.48
Operating Expenses	(13.81		)	(11.45		)	(9.69		)	(11.38		)
Operating Netback(1)	$	47.99		$	25.97		$	28.96		$	26.10
	Six Months Ended June 30, 2018			Six Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Total			Colombia			Brazil			Total
Oil and Natural Gas Sales	$	301,674		$	182,369		$	8,418		$	190,787
Transportation Expenses	(13,519		)	(13,084		)	(350		)	(13,434		)
	288,155			169,285			8,068			177,353
Operating Expenses	(61,324		)	(49,348		)	(1,797		)	(51,145		)
Operating Netback(1)	$	226,831		$	119,937		$	6,271		$	126,208
U.S. Dollars Per BOE Sales Volumes NAR
Brent	$	71.04		$	52.79		$	52.79		$	52.79
Vasconia, Quality and Transportation Discounts	(10.55		)	(11.46		)	(13.03		)	(11.54		)
Average Realized Price	60.49			41.33			39.76			41.25
Transportation Expenses	(2.71		)	(2.96		)	(1.65		)	(2.90		)
Average Realized Price Net of Transportation Expenses	57.78			38.37			38.11			38.35
Operating Expenses	(12.30		)	(11.18		)	(8.49		)	(11.06		)
Operating Netback(1)	$	45.48		$	27.19		$	29.62		$	27.29

⁽¹⁾ Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures" for a definition and reconciliation of this measure.

24

Oil and gas sales for the three and six months ended June 30, 2018increased by 70% to $163.4 million and 58% to $301.7 million, respectively, compared with the corresponding periods of 2017. Compared with the prior quarter, oil and gas sales increased by 18%. The increases were due to increased sales volumes and realized oil prices. The following table shows the effect of changes in realized prices and sales volumes on our oil and gas sales for the three and six months ended June 30, 2018 compared with the prior quarter and the corresponding periods in 2017:

	Second Quarter 2018 Compared with First Quarter 2018		Second Quarter 2018 Compared with Second Quarter 2017		Six Months Ended, June 30, 2018 Compared with Six Months Ended June 30, 2017
Oil and natural gas sales for the comparative period	$	138,228	$	96,128	$	190,787
Realized sales price increase effect	20,096		61,401		95,920
Sales volume increase effect	5,122		5,917		14,967
Oil and natural gas sales for period ended June 30, 2018	$	163,446	$	163,446	$	301,674

Average realized prices for the three and six months ended June 30, 2018increased by 60% and 47%, respectively, compared with the corresponding periods of 2017. Compared with the prior quarter, average realized prices increased by 14%. The increases were commensurate with increases in benchmark oil prices and lower quality and transportation discounts. Average Brent oil prices for the three and six months ended June 30, 2018increased by 47% and 35%, respectively, compared with the corresponding periods of 2017 and increased by 11% compared with the prior quarter.

We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized sales prices and transportation expenses. We focus on maximizing operating netback. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for the three and six months ended June 30, 2018 and 2017 and the prior quarter:

	Three Months Ended June 30,				Three Months Ended March 31,		Six Months Ended June 30,
	2018		2017		2018		2018		2017
Volume transported through pipeline	9	%	20	%	9	%	9	%	22	%
Volume sold at wellhead	41	%	52	%	52	%	42	%	52	%
Volume not sold at wellhead, trucking	50	%	28	%	39	%	49	%	26	%
	100	%	100	%	100	%	100	%	100	%

Volumes transported not sold at the wellhead receive higher realized prices, but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized prices, offset by lower transportation expenses.

Total Company transportation expenses for the three and six months ended June 30, 2018 of $6.5 million and $13.5 million, respectively, were comparable with the corresponding periods of 2017. On a per BOE basis, transportation expenses for the three and six months ended June 30, 2018 decreased by 5% to $2.57, and by 7% to $2.71, from $2.71 and $2.90, respectively, compared with the corresponding periods of 2017. The decrease was primarily due to the use of alternative transportation routes, which had lower costs per BOE.

Colombian transportation expenses for the three and six months ended June 30, 2018 on a per BOE basis decreased by 7% and 8% to $2.57 and $2.71 per BOE, from $2.76 and $2.96, respectively in the corresponding periods of 2017. The decrease in Colombian transportation expenses per BOE was due to renegotiation of certain sales contracts, which had lower transportation costs compared to contracts used in 2017.

Transportation expenses for the three months ended June 30, 2018decreased 7% compared with $7.0 million in the prior quarter. On a per BOE basis, transportation expenses decreased by 10% to $2.57 from $2.86 in the prior quarter. The decrease was primarily due to the use of alternative transportation routes, which had lower costs per BOE.

25

In addition to lower transportation expenses, we also achieved decreases in quality and transportation discounts. The following table shows the variance in our average realized prices net of transportation expenses in Colombia for the three and six months ended June 30, 2018 compared with the prior quarter and the corresponding periods in 2017:

U.S. Dollars Per BOE Sales Volumes NAR	Second Quarter 2018 Compared with First Quarter 2018		Second Quarter 2018 Compared with Second Quarter 2017		Six Months Ended, June 30, 2018 Compared with Six Months Ended June 30, 2017
Average realized price net of transportation expenses for the comparative period	$	53.60	$	37.42	$	38.37
Increase in benchmark prices	7.72		$	23.98	18.25
Decrease in quality and transportation discounts	0.19		0.21		0.91
Decrease in transportation expenses	0.29		0.19		0.25
Average realized price net of transportation expenses for the period ended June 30, 2018	$	61.80	$	61.80	$	57.78

Total Company operating expenses for the three and six months ended June 30, 2018increased by 29% to $35.1 million, and by 20% to $61.3 million, respectively, compared with total Company operating expenses in the corresponding periods of 2017.

Colombian operating expenses for the three and six months ended June 30, 2018 on a per BOE basis increased by $2.36 and $1.12, respectively, compared with the corresponding periods of 2017. Workover expenses increased by $0.11 and decreased by $0.27, respectively, over the same periods. Excluding workover expenses, Colombia operating expenses increased by $2.25 and $1.39, respectively, primarily as a result of payments triggered by renegotiating our field operating agreements, power generation costs, equipment rental and accelerated maintenance costs mainly in the Acordionero field during the second quarter of 2018.

Operating expenses for the three months ended June 30, 2018increased by 33% compared with the prior quarter. On a per BOE basis, operating expenses increased by $3.08. Workover expenses increased by $1.45. Excluding workover expenses, operating expenses increased by $1.63 compared with the prior quarter as a result of higher operating activities during the second quarter of 2018 mentioned in the paragraph above.

26

DD&A Expenses

	Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE		DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE
Colombia	$	46,065	$	18.14	$	30,130	$	13.17
Brazil	—		—		1,050		10.02
Peru	—		—		412		—
Corporate	542		—		221		—
	$	46,607	$	18.36	$	31,813	$	13.30
	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE		DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE
Colombia	$	84,564	$	16.96	$	55,065	$	12.48
Brazil	—		—		2,263		10.69
Peru	—		—		921		—
Corporate	1,504		—		440		—
	$	86,068	$	17.26	$	58,689	$	12.69

DD&A expenses for the three and six months ended June 30, 2018increased to $46.6 million ($18.36 per BOE) and $86.1 million ($17.26 per BOE), respectively, from $31.8 million ($13.30 per BOE) and $58.7 million ($12.69 per BOE), respectively, in the corresponding periods in 2017. On a per BOE basis, the increase was due to higher costs in the depletable base, partially offset by increased proved reserves. On a per BOE basis, DD&A expenses increased by 14% from $16.12 per BOE in the prior quarter primarily due to higher costs in the depletable base.

G&A Expenses

	Three Months Ended June 30,						Three Months Ended March 31,		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		% Change		2018		2018		2017		% Change
G&A Expenses Before Stock-Based Compensation	$	6,604	$	7,610	(13	)	$	7,982	$	14,586	$	15,173	(4	)
G&A Stock-Based Compensation	6,609		1,903		247		3,178		9,787		3,052		221
G&A Expenses, Including Stock-Based Compensation	$	13,213	$	9,513	39		$	11,160	$	24,373	$	18,225	34
U.S. Dollars Per BOE Sales Volumes NAR
G&A Expenses Before Stock-Based Compensation	$	2.60	$	3.18	(18	)	$	3.26	$	2.92	$	3.28	(11	)
G&A Stock-Based Compensation	2.60		0.80		225		1.30		1.96		0.66		197
G&A Expenses, Including Stock-Based Compensation	$	5.20	$	3.98	31		$	4.56	$	4.88	$	3.94	24

27

For the three and six months ended June 30, 2018, G&A expenses before stock-based compensation decreased by 13% and 4%, respectively, from the corresponding periods of 2017. The decrease was primarily the result of higher overhead recoveries, partially offset by increase in Colombia and Corporate G&A expenses commensurate with our growth. On a per BOE basis, G&A expenses before stock-based compensation decreased 18% and 11%, respectively, from the corresponding periods of 2017.

After stock-based compensation, G&A expenses for the three and six months ended June 30, 2018increased by 39% to $13.2 million and by 34% to $24.4 million, respectively, compared with the corresponding periods in 2017 mainly due to higher G&A Stock-Based Compensation resulting from a higher share price at June 30, 2018. G&A expenses for the three months ended June 30, 2018increased by 18% compared with the prior quarter for the same reason.

Foreign Exchange Losses

For the three and six months ended June 30, 2018 we had foreign exchange losses of $1.9 million and $1.0 million, respectively, compared with $3.9 million and $2.1 million, respectively, in the corresponding periods of 2017. Deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation was the main source of the foreign exchange gains and losses. Due to the long-term nature of deferred tax liabilities, the related foreign exchange losses are not expected to be realized in the near-term.

The following table presents the change in the U.S. dollar against the Colombian peso for the three and six months ended June 30, 2018, and 2017:

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Change in the U.S. dollar against the Colombian peso	strengthened by	strengthened by	weakened by	strengthened by
	5%	6%	2%	1%

Financial Instrument Gains and Losses

The following table presents the nature of our financial instruments gains and losses for the three and six months ended June 30, 2018, and 2017:

	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2017
Commodity price derivative loss (gain)	$	14,461		$	(1,545	)	$	19,455		$	(6,247	)
Foreign currency derivatives loss (gain)	1,945			98			(2,024		)	(639		)
Investment gain	(11,638		)	—			(5,717		)	—
	$	4,768		$	(1,447	)	$	11,714		$	(6,886	)

Income Tax Expense and Recovery

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		2018			2017
Income before income tax	$	48,296	$	6,490	$	91,928		$	38,057
Current income tax expense	$	4,827	$	1,772	$	17,116		$	9,189
Deferred income tax expense	23,169		11,525		36,651			22,904
Total income tax expense	$	27,996	$	13,297	$	53,767		$	32,093
Effective tax rate					58		%	84		%

Current income tax expense was higher in the three and six months ended June 30, 2018 compared with the corresponding periods of 2017 as a result of higher taxable income in Colombia. The deferred income tax expense for the three and six months ended

28

June 30, 2018 of $23.2 million and $36.7 million, respectively, was primarily due to excess tax depreciation as compared with accounting depreciation in Colombia.

Current income tax expense decreased to $4.8 million compared with $12.3 million in the prior quarter primarily as a result of accelerated tax write-off related to current period drilling activities.

For the six months ended June 30, 2018, the difference between the effective tax rate of 58% and the 21% U.S. statutory rate was primarily due to an increase to the impact of foreign taxes, valuation allowance, stock-based compensation, foreign currency translation and non-deductible third party royalty in Colombia.

For the six months ended June 30, 2017, the difference between the effective tax rate of 84% and the 35% U.S. statutory rate was primarily due to an increase in the impact of foreign taxes, other permanent differences, valuation allowance largely attributable to losses incurred in the United States and Colombia, as well as the impact of a non-deductible third-party royalty in Colombia, stock-based compensation and other local taxes.

29

Net Income and Funds Flow from Operations (a Non-GAAP Measure)

(Thousands of U.S. Dollars)	Second Quarter 2018 Compared with First Quarter 2018			% change		Second Quarter 2018 Compared with Second Quarter 2017			% change		Six Months Ended, June 30, 2018 Compared with Six Months Ended June 30, 2017			% change
Net income (loss) for the comparative period	$	17,861				$	(6,807	)			$	5,964
Increase (decrease) due to:
Prices	20,096					61,401					95,920
Sales volumes	5,122					5,917					14,967
Expenses:
Operating	(8,794		)			(7,851		)			(10,179		)
Transportation	475					(30		)			(85		)
Cash G&A and RSU settlements, excluding stock-based compensation expense	1,411					1,156					1,012
Interest, net of amortization of debt issuance costs	(1,707		)			(3,821		)			(6,156		)
Realized foreign exchange	(240		)			(338		)			531
Settlement of financial instruments	(3,849		)			(10,114		)			(16,699		)
Current taxes	7,462					(3,055		)			(7,927		)
Equity tax	—					—					1,224
Other	(175		)			364					743
Net change in funds flow from operations(1) from comparative period	19,801					43,629					73,351
Expenses:
Depletion, depreciation and accretion	(7,146		)			(14,794		)			(27,379		)
Deferred tax	(9,687		)			(11,644		)			(13,747		)
Amortization of debt issuance costs	(173		)			(223		)			(288		)
Stock-based compensation, net of RSU settlement	(3,464		)			(4,856		)			(7,160		)
Financial instruments gain or loss, net of financial instruments settlements	6,027					3,899					(1,901		)
Unrealized foreign exchange	(2,627		)			2,312					537
Loss on sale	(292		)			8,784					8,784
Net change in net income or loss	2,439					27,107					32,197
Net income for the current period	$	20,300		14	%	$	20,300		398	%	$	38,161		540	%

⁽¹⁾Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operational Highlights—non-GAAP measures" for a definition and reconciliation of this measure.

2018 Capital Program

Colombia remains our focus and represents 100% of the 2018 capital program. We have expanded the 2018 development capital program by an additional $15 to $30 million for;

• Ayombero appraisal drilling of 3 wells based on the success of the Ayombero-1 well;

• Costayaco development drilling in legacy reservoirs and 1 additional water injection well; and

• 2 Acordionero development wells accelerated from 2019 into fourth quarter 2018.

30

We expect the following ranges for our revised 2018 capital budget:

	Number of Wells (Gross)	Number of Wells (Net)	2018 Capital Budget ($ million)
Colombia
Development	22-24	21-22	$130-135
Exploration	8-11	7-10	80-90
Facilities	—	—	75-80
Seismic and Studies	—	—	20
	30-35	28-32	$305-325

Based on the midpoint of the guidance, the capital budget is forecasted to be approximately 68% directed to development and 32% to exploration. Between 35% and 40% of the revised 2018 development capital program is expected to be directed to facilities, with approximately 75% of this investment expected to be dedicated to the acceleration of the ongoing facilities expansion at the Acordionero Field. We expect our revised 2018 capital program to be fully funded by cash flows from operations.

Capital expenditures during the three months ended June 30, 2018, were $84.4 million:

(Thousands of U.S. Dollars)
Colombia:
Exploration	$	18,301
Development:
Facilities	16,957
Drilling and Completions	41,696
Other	6,803
	83,757
Corporate	637
	$	84,394

During the three months ended June 30, 2018, we drilled the following wells in Colombia:

	Number of wells (Gross)	Number of wells (Net)
Development	5	5.0
Exploration	1	0.5
Total Colombia	6	5.5

Five development wells were spud, consisting of two in the Midas Block (Acordionero-23-i and 24), two in the Chaza Block (Costayaco-33 and 35-i), and one in the Putumayo-7 Block (Cumplidor-2). Three of these wells are currently on production (Costayaco-33, 35-i and Cumplidor-2). Additionally, of the wells that were in-progress at March 31, 2018, three development wells (Acordionero-20, 22 and Costayaco-32) are currently producing. We also drilled the Tonga-1 exploration well in the Sinu-3 Block, which was plugged and abandoned as the well did not encounter commercial hydrocarbon quantities. This was a commitment exploration well.

We also continued facilities work at the Acordionero Field on the Midas Block and the Moqueta and Costayaco Fields on the Chaza Block.

During the three months ended June 30, 2018, we acquired additional working interests in Alea1848-A and 1947-C for total cash consideration of $3.1 million, which increased our position in these blocks to 100% and expanded our exploration opportunities in the Putumayo Basin. These acquisitions are subject to approval by the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency).

31

Liquidity and Capital Resources

	As at
(Thousands of U.S. Dollars)	June 30, 2018		% Change		December 31, 2017
Cash and Cash Equivalents	$	125,807	921		$	12,326
Current Restricted Cash and Cash Equivalents	$	2,836	(76	)	$	11,787
Revolving Credit Facility	$	—	(100	)	$	148,000
Senior Notes	$	300,000	—		$	—
Convertible Notes	$	115,000	—		$	115,000

We believe that our capital resources, including cash on hand, cash generated from operations and available capacity on our credit facility, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for 2018, given current oil price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions. 

At June 30, 2018, we had a revolving credit facility with a syndicate of lenders with a borrowing base of $300 million and we had zero drawn on this credit facility. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. The next re-determination of the borrowing base is due to occur no later than November 2018.

At June 30, 2018, we had $115 million aggregate principal amount of 5.00% Convertible Senior Notes due 2021 (the "Convertible Notes") and $300 million aggregate principal amount of 6.25% Senior Notes due 2025 (the "Senior Notes") outstanding. The Convertible Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year. The Convertible Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted. The Convertible Notes are convertible to Common Stock at a conversion price of approximately $3.21 per share of Common Stock 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 Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Under the terms of our credit facility and Senior Notes, we are required to maintain compliance with certain financial and operating covenants which include: limitations on our ratio of debt to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income ("EBITDAX") to a maximum of 4.0 to 1.0 (under the credit facility) and 3.5 to 1.0 (under the Senior Notes); the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0 (definitions of debt, EBITDAX and other relevant terms are per the credit agreement or the indenture governing the Senior Notes and may differ between these agreements). As at June 30, 2018, we were in compliance with all financial and operating covenants in these agreements. Under the terms of the credit facility and Senior Notes, we are also limited in our ability to make distributions to our shareholders.

Cash and Cash Equivalents Held Outside of Canada and the United States

At June 30, 2018, 100% of our cash and cash equivalents were held by subsidiaries and partnerships outside of Canada and the United States. This cash was generally not available to fund domestic or head office operations unless funds were repatriated. At this time, we do not intend to repatriate further funds other than to pay head office charges, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the distribution of accumulated earnings. Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.

In Colombia, we participate in a special exchange regime, and we receive revenue in U.S. dollars offshore. We may also pay invoices denominated in U.S. dollars for our Colombian business from these U.S. dollars received offshore.

32

Derivative Positions

At June 30, 2018, we had outstanding commodity price derivative positions as follows:

Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

At June 30, 2018, current liabilities on our balance sheet included $27.2 million in relation to the above outstanding commodity price derivative positions.

At June 30, 2018, we had the following outstanding foreign currency derivative positions:

Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: July 1, 2018 to December 31, 2018	87,000	29,685	COP	3,000	3,107

⁽¹⁾ At June 30, 2018 foreign exchange rate.

At June 30, 2018, current assets on our balance sheet included $0.9 million in relation to the above outstanding foreign currency derivative positions. We do not have any outstanding commodity price derivative positions relating to 2019.

33

Cash Flows

The following table presents our primary sources and uses of cash and cash equivalents for the periods presented:

	Six Months Ended June 30,
	2018			2017
Sources of cash and cash equivalents:
Net income	$	38,161		$	5,964
Adjustments to reconcile net income to EBITDA(1)  and funds flow from operations(1)
DD&A expenses	86,068			58,689
Interest expense	12,870			6,426
Income tax expense	53,767			32,093
EBITDA	190,866			103,172
Current income tax expense	(17,116		)	(9,189		)
Stock-based compensation expense	10,202			3,183
Contractual interest and other financing expenses	(11,357		)	(5,201		)
Cash settlement of RSUs	(360		)	(501		)
Unrealized foreign exchange loss	539			1,076
Financial instruments loss (gain)	11,714			(6,886		)
Cash settlement of financial instruments	(15,483		)	1,216
Loss on sale	292			9,076
Funds flow from operations	169,297			95,946
Proceeds from bank debt, net of issuance costs	4,988			98,304
Proceeds from issuance of Senior Notes, net of issuance costs	288,087			—
Proceeds from issuance of shares	845			—
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit	—			4,700
Deposit received for sale of Brazil business unit	—			34,481
	463,217			233,431
Uses of cash and cash equivalents:
Additions to property, plant and equipment	(157,088		)	(104,025		)
Additions to property, plant and equipment - property acquisitions	(3,100		)	(30,410		)
Repayment of bank debt	(153,000		)	(33,000		)
Repurchase of shares of Common Stock	(1,208		)	(10,000		)
Net changes in assets and liabilities from operating activities	(37,994		)	(28,112		)
Changes in non-cash investing working capital	(6,142		)	(627		)
Settlement of asset retirement obligations	(369		)	(298		)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(69		)	(1,175		)
	(358,970		)	(207,647		)
Net increase in cash and cash equivalents and restricted cash and cash equivalents	$	104,247		$	25,784

(1) EBITDA and funds flow from operations are a non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operational Highlights - non-GAAP measures” for a definition and reconciliation of this measure.

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices, the impact of which we partially mitigate by entering into commodity derivatives. Sales volume changes and costs related to operations

34

and debt service also impact cash flow. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes, the impact of which we partially mitigate by entering into foreign currency derivatives.

Off-Balance Sheet Arrangements

As at June 30, 2018, we had no off-balance sheet arrangements.

Contractual Obligations

During February 2018, we issued $300 million aggregate principal amount of the Senior Notes. Refer to Note 5 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Form 10-Q, incorporated herein by reference, for further information. During the six months ended June 30, 2018, we fully repaid the balance of $153 million outstanding under our revolving credit facility, which remained undrawn at June 30, 2018.

Except as noted above, as at June 30, 2018, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at December 31, 2017.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2017 Annual Report on Form 10-K, filed with the SEC on February 27, 2018, and have not changed materially since the filing of that document, other than as follows:

Revenue Recognition

We adopted ASC 606 Revenue from Contracts with Customers with a date of initial application of January 1, 2018 in accordance with the modified retrospective approach. Except for providing enhanced disclosures on our revenue transactions, the application of ASC 606 did not have an impact on our consolidated financial position, results of operations or cash flows.

We evaluate our arrangements with third parties and partners to determine if we act as a principal or an agent. In making this evaluation, management considers if we obtain control of the product delivered, which is indicated by us having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If we act in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by us from the transaction. When determining if we acted as a principal or as an agent in transactions, we determine if we obtain control of the product. As part of this assessment, management considered detailed criteria for revenue recognition set out in ASC 606.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk

Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Most of our revenues are from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to ICE Brent and adjusted for quality each month.

We have entered into commodity price derivative contracts to manage the variability in cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending.

Foreign currency risk

Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 100% of our revenues are related to the U.S. dollar price of Brent or WTI oil. We receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. The majority of income and value added taxes and G&A expenses in Colombia are in local currency. Certain G&A expenses incurred at our head office in Canada are denominated in Canadian dollars. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.

35

We have entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our current and deferred tax liabilities, which are monetary liabilities, denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency.

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our revolving credit facility, which bears floating rates of interest. At June 30, 2018, our outstanding revolving credit facility was nil (December 31, 2017 - $148.0 million).

Further Information

See Note 10 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for further information regarding our derivative contracts, including the notional amounts and call and put prices by expected (contractual) maturity dates. Expected cash flows from the derivatives equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. We do not hold any of these derivative contracts for trading purposes.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as of June 30, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - Other Information

Item 1. Legal Proceedings

See Note 9 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2017, and any material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

See Part I, Item 1A Risk Factors of our 2017 Annual Report on Form 10-K. The risks facing our company have not changed materially from those set forth in Part I, Item 1A Risk Factors of our 2017 Annual Report on Form 10-K.

36

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

	(a) Total Number of Shares Purchased(1)	(b) Average Price Paid per Share (2)	(c) Total Number of Shares Purchased as Part of Publicly Announced  Plans or Programs	(d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (3)
April 1-30, 2018	—	—	—	18,804,820
May 1-31, 2018	4,500	2.98	4,500	18,800,320
June 1- 30, 2018	—	—	—	18,800,320
	4,500	2.98	4,500	18,800,320

⁽¹⁾ Based on settlement date.

⁽²⁾ Exclusive of commissions paid to the broker to repurchase the Common Stock.

⁽³⁾ On March 7, 2018, we announced that we intended to implement a share repurchase program (the “2018 Program”) through the facilities of the TSX and eligible alternative trading platforms in Canada. We received regulatory approval from the TSX to commence the 2018 Program on March 12, 2018. We are able to purchase at prevailing market prices up to 19,269,732 shares of Common Stock, representing approximately 5% of our issued and outstanding shares of Common Stock as of March 8, 2018.

Shares purchased pursuant to the 2018 Program to date have been canceled. The 2018 Program will expire on March 11, 2019, or earlier if the 5.00% share maximum is reached. The 2018 Program could be terminated by us at any time, subject to compliance with regulatory requirements. As such, there can be no assurance regarding the total number of shares that may be repurchased under the 2018 Program.

37

Item 6. Exhibits

Exhibit No.	Description	Reference
2.1	Plan of Conversion, dated October 31, 2016.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
3.1	Certificate of Incorporation.	Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
3.2	Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
3.3	Certificate of Retirement dated July 9, 2018	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the SEC on July 9, 2018 (SEC File No. 001-34018).
4.1	Indenture related to the 5.00% Convertible Senior Notes due 2021, dated as of April 6, 2016, between Gran Tierra Energy Inc. and U.S. Bank National Association	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).
4.2	Form of 5.00% Convertible Senior Notes due 2021	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).
4.3	Subscription Receipt Agreement, dated July 8, 2016, by and between Gran Tierra Energy Inc. and Computershare Trust Company of Canada.	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).
4.4	Form of Registration Rights Agreement.	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).
4.5	Purchase Agreement, dated February 8, 2018, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc. and the subsidiary guarantors named therein, and Credit Suisse Securities (USA) LLC and RBC Capital Markets, LLC, as Representatives of the several initial purchasers.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on February 9, 2018 (SEC File No. 001-34018).
4.6	Indenture related to the 6.25% Senior Notes due 2025, dated as of February 15, 2018, between Gran Tierra Energy International Holdings Ltd., the Guarantors named therein and U.S. Bank National Association	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).
4.7	Form of 6.25% Senior Notes due 2025	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).
10.1	Tenth Amendment to Credit Agreement, dated as of May 25, 2018, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto	Filed herewith.
31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.
31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.
32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith.

38

101.INS  XBRL Instance Document

101.SCH  XBRL Taxonomy Extension Schema Document

101.CAL  XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB  XBRL Taxonomy Extension Label Linkbase Document

101.PRE  XBRL Taxonomy Extension Presentation Linkbase Document

+ Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Gran Tierra undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.

SIGNATURES

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

GRAN TIERRA ENERGY INC.

Date: August 2, 2018	/s/ Gary S. Guidry
	By: Gary S. Guidry
	President and Chief Executive Officer
	(Principal Executive Officer)

Date: August 2, 2018	/s/ Ryan Ellson
	By: Ryan Ellson
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

39

EX-10.1

EXHIBIT 10.1

Execution Version

TENTH AMENDMENT TO CREDIT AGREEMENT

This Tenth Amendment to Credit Agreement (this “Amendment”) is entered into effective as of the 25^th day of May, 2018, by and among Gran Tierra Energy International Holdings Ltd., an exempted company incorporated with limited liability under the laws of the Cayman Islands (the “Borrower”), Gran Tierra Energy Inc., a corporation duly formed and existing under the laws of the State of Nevada (the “Parent”), The Bank of Nova Scotia, as administrative agent (the “Administrative Agent”) and the Lenders party hereto.

W I T N E S S E T H:

WHEREAS, Borrower, the Parent, the Administrative Agent, and Lenders are parties to that certain Credit Agreement dated as of September 18, 2015 (as amended, supplemented or otherwise modified prior to the date hereof, the “Credit Agreement”) (unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement as amended by this Amendment);

WHEREAS, pursuant to the Credit Agreement, Lenders have made certain Loans to the Borrower and provided certain other credit accommodations to Borrower;

The parties desire to enter into this Amendment to (i) reaffirm the Borrowing Base as $300,000,000 and (ii) make certain other amendments and modifications, in each case upon the terms and conditions set forth herein and in each case to be effective as of the Tenth Amendment Effective Date (as defined below).

WHEREAS, the Administrative Agent, Borrower and the undersigned Lenders have agreed to enter into this Amendment to amend the Credit Agreement as more particularly set forth herein;

NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Borrower, Administrative Agent and undersigned Lenders hereto hereby agree as follows:

1

Section 1.Amendments. In reliance on the representations, warranties, covenants and agreements contained in this Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement and the schedules, annexes and the exhibits to the Credit Agreement and the other Loan Documents are, effective as of the Tenth Amendment Effective Date, hereby amended in the manner provided in this Section 1.

1.1Amendments to Section 1.02.

(a)    The following definitions contained in Section 1.02 of the Credit Agreement are hereby amended and restated as follows:

“Available Amount” means, at any date of determination, an aggregate amount equal to (a) the amount equal to the sum, determined on a cumulative basis, of (i) the Available Amount Cap, plus (ii) the amount of cash distributions received by the Parent, the Borrower or any Restricted Subsidiary from any Unrestricted Subsidiary or from any minority Investment or cash repayment received by the Parent, the Borrower or any Restricted Subsidiaries in respect of any Investment constituting a loan or advance, in each case to the extent such distributions or such repayments are, within 180 days from the date of receipt thereof, invested in Investments permitted by Sections 9.05(h), (j)or (l); minus (b) the amount of dollars used to make Investments to pursuant to Section 9.05(e)(ii) (exclusive of any amounts of such Investments in which the Administrative Agent has a first priority perfected security interest) or ‎Section 9.05(l).

“Permitted EDC Debt” means Debt of any Credit Party in favor of Export Development Canada for the provision by Export Development Canada of credit support in favor of an issuer of letters of credit on behalf of any Credit Party; provided, that either (i) such Debt is unsecured or (ii) if such Debt is secured, the aggregate outstanding principal amount of such Debt does not exceed $150,000,000 and such secured Debt is subject to an Intercreditor Agreement containing subordination provisions in form and substance satisfactory to the Administrative Agent and the Majority Revolving Credit Lenders in their sole discretion.

(b) The definition of “Excepted Debt” contained in Section 1.02 of the Credit Agreement is hereby amended by amending and restating clause (b) therein in its entirety to read in full as follows:

“(b) Debt in respect of direct obligations of any Credit Party regarding performance bonds, bid bonds, appeal bonds, surety bonds, completion guarantees and similar obligations (including such obligations in respect of letters of credit and bank guarantees related thereto and such obligations incurred to secure health, safety and environmental obligations), in each case, not in connection with money borrowed and provided in the ordinary course of business or consistent with past practice; provided that Permitted EDC Debt may not be permitted by this clause (b)”

(c) The definition of “Excepted Liens” contained in Section 1.02 of the Credit Agreement is hereby amended by amending and restating clause (g) therein in its entirety to read in full as follows:

2

“(g) Liens on cash or securities directly pledged to secure performance of tenders, surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business; provided that Permitted EDC Debt may not be secured by Liens in this clause (g)”

1.2Amendment to Section 2.08(b). Section 2.08(b) of the Credit Agreement is hereby amended to insert “(or thirty (30) days thereafter)” immediately after “of each year” therein.

1.3Amendment to Section 8.01(o). Section 8.01(o)(ii) of the Credit Agreement is hereby amended to delete “April 1” and insert in lieu thereof “April 30”.

1.4Amendment to Section 9.02(d). Section 9.02(d) of the Credit Agreement is hereby amended to insert “(other than Permitted EDC Debt)” immediately after “Debt” therein.

1.5Amendment to Section 9.05(l). Section 9.05(l)(ii) of the Credit Agreement is hereby amended to delete “Responsible officer” and insert in lieu thereof “Responsible Officer”.

1.6Omnibus Amendment to Loan Documents. Each reference in any Loan Document to a “Responsible Officer of the Borrower” is hereby amended to delete “Responsible Officer of the Borrower” and insert in lieu thereof “Responsible Officer of the Borrower or of the Parent”.

SECTION 2.Redetermination of Borrowing Base. Subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Lenders hereby agree that for the period from and including the Tenth Amendment Effective Date, but until the next Scheduled Redetermination Date, the next Interim Redetermination Date or the next adjustment to the Borrowing Base under Section 2.08(e), Section 2.08(f) or Section 9.11(d) of the Credit Agreement, whichever occurs first, the amount of the Borrowing Base shall be reaffirmed to be $300,000,000, which redetermination of the Borrowing Base shall constitute the May 1, 2018 Scheduled Redetermination of the Borrowing Base. This Section 2 constitutes the New Borrowing Base Notice for the May 1, 2018 Scheduled Redetermination of the Borrowing Base.

SECTION 3.Conditions Precedent. This Amendment shall be effective on the date that each of the following conditions precedent is satisfied or waived in accordance with Section 12.02 of the Credit Agreement (the “Tenth Amendment Effective Date”):

3.1Counterparts. Administrative Agent shall have received from the Required Revolving Lenders, the Parent and the Borrower counterparts (in such number as may be requested by the Administrative Agent) of this Amendment signed on behalf of such Persons.

3.2Fees and Expenses. The Borrower shall have paid to the Administrative Agent and the Lenders all fees required to be paid by the Borrower and all expenses required to be paid by the Borrower under Section 12.03 of the Credit Agreement (other than fees of counsel to the Administrative Agent).

SECTION 4.Representations and Warranties of Borrower. To induce the Lenders and Administrative Agent to enter into this Amendment, each undersigned Credit Party hereby represents and warrants to Lenders and Administrative Agent as follows:

3

4.1Reaffirmation of Loan Documents; Extension of Liens. Any and all of the terms and provisions of the Credit Agreement and the other Loan Documents shall, except as amended hereby, remain in full force and effect. The undersigned Credit Parties hereby extend the Liens securing the Secured Obligations until the Secured Obligations have been paid in full, and agree that the amendments and waivers herein contained shall in no manner affect or impair the Secured Obligations or the Liens securing payment and performance thereof, all of which are ratified and confirmed.

4.2Reaffirm Existing Representations and Warranties. Each representation and warranty of such Credit Party contained in the Credit Agreement and the other Loan Documents is true and correct in all material respects (except to the extent any such representation or warranty is qualified by materiality or Material Adverse Effect, in which case it shall be true and correct in all respects) on the date hereof after giving effect to the amendments set forth herein, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects (except to the extent any such representation or warranty is qualified by materiality or Material Adverse Effect, in which case it shall be true and correct in all respects) as of such specified earlier date.

4.3Due Authorization; No Conflict. The execution, delivery and performance by Borrower of this Amendment are within such Credit Party’s organizational powers and have been duly authorized by all necessary corporate and, if required, stockholder or shareholder action (including, without limitation, any action required to be taken by any class of directors of such Credit Party or any other Person, whether interested or disinterested, in order to ensure the due authorization of this Amendment). The execution, delivery and performance by such Credit Party of this Amendment (a) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person (including shareholders or any class of directors, whether interested or disinterested, of the Parent, such Credit Party or any other Person), nor is any such consent, approval, registration, filing or other action necessary for the validity or enforceability of this Amendment, except such as have been obtained or made and are in full force and effect other than those third party approvals or consents which, if not made or obtained, would not cause a Default hereunder, could not reasonably be expected to have a Material Adverse Effect or do not have an adverse effect on the enforceability of this Amendment, (b) will not violate any applicable law or regulation or the charter, by-laws or other organizational documents of such Credit Party or any order of any Governmental Authority, (c) will not violate or result in a default under any Material Document or any indenture, agreement or other instrument binding upon such Credit Party or its Properties, or give rise to a right thereunder to require any payment to be made such Credit Party, and (d) will not result in the creation or imposition of any Lien on any Property of any Credit Party (other than the Liens created by the Loan Documents).

4.4Validity and Enforceability. This Amendment constitutes a legal, valid and binding obligation of such Credit Party, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

4.5Acknowledgment of No Defenses. Such Credit Party acknowledges that it has no defense to (%3) such Credit Party’s obligation to pay the Obligations when due, or (%3) the validity, enforceability or binding effect against such Credit Party of the Credit Agreement or any of the other Loan Documents (to the extent a party thereto) or any Liens intended to be created thereby.

4

SECTION 5.Miscellaneous.

5.1Reaffirmation of Loan Documents. Any and all of the terms and provisions of the Credit Agreement and the Loan Documents shall, except as amended and modified hereby, remain in full force and effect. This Amendment shall not limit or impair any Liens securing the Obligations, each of which are hereby ratified, affirmed and extended to secure the Obligations as they may be increased pursuant hereto. This Amendment constitutes a Loan Document.

5.2Parties in Interest. All of the terms and provisions of this Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns.

5.3Counterparts. This Amendment may be executed in counterparts, including, without limitation, by electronic signature, and all parties need not execute the same counterpart. Facsimiles or other electronic transmissions (e.g. pdfs) of such executed counterparts shall be effective as originals.

5.4Complete Agreement. THIS AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES.

5.5Headings. The headings, captions and arrangements used in this Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Amendment, nor affect the meaning thereof.

5.6Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers on the date and year first above written.

5.7[Signature pages to follow]

5

BORROWER: GRAN TIERRA ENERGY INTERNATIONAL     HOLDINGS LTD.

By: /s/ Adrian Coral__________________________

Name:    Adrian Coral

Title:    Director

PARENT: GRAN TIERRA ENERGY INC.

By: /s/ Adam Smith__________________________

Name:    Adam Smith

Title:    Treasurer

Signature Page – Tenth Amendment

ADMINISTRATIVE AGENT:     THE BANK OF NOVA SCOTIA

By: /s/ Carolina Villegas______________________

Name:    Carolina Villegas

Title:    Director, International Banking

By: /s/ Enrique Lopez________________________

Name:    Enrique Lopez

Title:    Vice President, International Banking

Signature Page – Tenth Amendment

LENDERS:    THE BANK OF NOVA SCOTIA, as a Lender

By: /s/ Carolina Villegas______________________

Name:    Carolina Villegas

Title:    Director, International Banking

By: /s/ Enrique Lopez________________________

Name:    Enrique Lopez

Title:    Vice President, International Banking

Signature Page – Tenth Amendment

SOCIÉTÉ GÉNÉRALE,as a Lender

By: /s/ Max Sonnonstine     

Name: Max Sonnonstine

Title: Director

Signature Page – Tenth Amendment

HSBC BANK CANADA,

as a Lender

By: /s/ Duncan Levy____________________

Name: Duncan Levy

Title: Director, Global Banking

By: /s/ Adam Lamb

Name: Adam Lamb

Title: Vice President, Global Banking

Signature Page – Tenth Amendment

EXPORT DEVELOPMENT CANADA,

as a Lender

By: /s/ Trystan Glynn-Morris    

Name: Trystan Glynn-Morris

Title: Senior Associate, Structured and Project Finance

By: /s/ Frank Kelly    

Name: Frank Kelly

Title: Director, Extractive Industries, Structured and Project Finance

Signature Page – Tenth Amendment

NATIXIS, NEW YORK BRANCH,

as a Lender

By: /s/ Carla Grey    

Name: Carla Grey

Title: Director

By: /s/ A. Stevens    

Name: A. Stevens

Title: M.D.

Signature Page – Tenth Amendment

ROYAL BANK OF CANADA,

as a Lender

By: /s/ Maria E. Hushovd    

Name: Maria E. Hushovd

Title: Authorized Signatory

CANADIAN IMPERIAL BANK OF COMMERCE,

as a Lender

By: /s/ Ryan Shea    

Name: Ryan Shea

Title: Director

By: /s/ Joelle Chatwin    

Name: Joelle Chatwin

Title: Executive Director

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I,Gary S. Guidry, certify that:

1. I have reviewed this Form 10-Q of Gran Tierra Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2018	/s/ Gary S. Guidry
	By: Gary S. Guidry
	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Ryan Ellson, certify that:

1. I have reviewed this Form 10-Q of Gran Tierra Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2018	/s/ Ryan Ellson
	By: Ryan Ellson
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

EX-32.1

EXHIBIT 32.1

Certification of Chief Executive Officer and Chief Financial Officer

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to the requirement set forth in Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Section 1350, Chapter 63 of Title 18 of the United States Code (18 U.S.C-§1350), each of Gary S. Guidry, President and Chief Executive Officer of Gran Tierra Energy Inc., a Delaware corporation (the “Company”), and Ryan Ellson, Chief Financial Officer of the Company, does hereby certify, to such officer’s knowledge that:

The Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 (the “Form 10-Q”) to which this Certification is attached as Exhibit 32.1 fully complies with the requirements of Section 13(a) or 15(d) of the Exchange Act. The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned have set their hands hereto as of the 2nd day of August 2018.

/s/ Gary S. Guidry	/s/ Ryan Ellson
By: Gary S. Guidry	By: Ryan Ellson
President and Chief Executive Officer	Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Section 1350, Chapter 63 of Title 18, United States Code) and is not deemed filed with the Securities and Exchange Commission as part of the Form 10-Q or as a separate disclosure document and is not to be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Exchange Act (whether made before or after the date of the Form 10-Q), irrespective of any general incorporation language contained in such filing.

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 30, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	GRAN TIERRA ENERGY INC.
Entity Central Index Key	0001273441
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		391,175,023
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018

XML

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Statement [Abstract]
OIL AND NATURAL GAS SALES (Notes 3 and 7)	$ 163,446	$ 96,128	$ 301,674	$ 190,787
EXPENSES
Operating	35,059	27,208	61,324	51,145
Transportation	6,522	6,492	13,519	13,434
Depletion, depreciation and accretion (Note 3)	46,607	31,813	86,068	58,689
General and administrative (Note 3)	13,213	9,513	24,373	18,225
Equity tax	0	0	0	1,224
Foreign exchange loss	1,924	3,897	982	2,050
Financial instruments loss (gain) (Note 10)	4,768	(1,447)	11,714	(6,886)
Interest expense (Note 5)	7,375	3,331	12,870	6,426
EXPENSES	115,468	80,807	210,850	144,307
LOSS ON SALE	(292)	(9,076)	(292)	(9,076)
INTEREST INCOME	610	245	1,396	653
INCOME BEFORE INCOME TAXES (Note 3)	48,296	6,490	91,928	38,057
INCOME TAX EXPENSE
Current (Note 8)	4,827	1,772	17,116	9,189
Deferred (Note 8)	23,169	11,525	36,651	22,904
INCOME TAX EXPENSE	27,996	13,297	53,767	32,093
NET AND COMPREHENSIVE INCOME (LOSS)	$ 20,300	$ (6,807)	$ 38,161	$ 5,964
NET INCOME (LOSS) PER SHARE - BASIC AND DILUTED (in dollars per share)	$ 0.05	$ (0.02)	$ 0.10	$ 0.01
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6) (in shares)	391,054,204	398,585,290	391,173,460	398,795,023
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6) (in shares)	427,455,092	398,585,290	427,242,014	398,816,091

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents (Note 11)	$ 125,807	$ 12,326
Restricted cash and cash equivalents (Note 11)	2,836	11,787
Accounts receivable	63,030	45,353
Investment in PetroTal Corp. shares (Note 10)	32,654	25,055
Derivatives (Note 10)	930	302
Taxes receivable	62,689	40,831
Other current assets	14,423	9,591
Total Current Assets	302,369	145,245
Oil and Gas Properties (using the full cost method of accounting)
Proved	750,948	629,081
Unproved	423,808	464,948
Total Oil and Gas Properties	1,174,756	1,094,029
Other capital assets	3,440	5,195
Total Property, Plant and Equipment (Notes 3 and 4)	1,178,196	1,099,224
Other Long-Term Assets
Deferred tax assets	18,248	57,310
Investment in PetroTal Corp. shares (Note 10)	15,302	19,147
Other long-term assets (Note 11)	5,389	6,112
Goodwill (Note 3)	102,581	102,581
Total Other Long-Term Assets	141,520	185,150
Total Assets	1,622,085	1,429,619
Current Liabilities
Accounts payable and accrued liabilities	126,726	125,876
Derivatives (Note 10)	27,157	21,151
Taxes payable	3,848	9,324
Asset retirement obligation	110	323
Equity compensation award liability (Note 10)	11,597	295
Total Current Liabilities	169,438	156,969
Long-Term Liabilities
Long-term debt (Notes 5 and 10)	398,130	256,542
Deferred tax liabilities	24,528	28,417
Asset retirement obligation	35,839	31,241
Equity compensation award liability (Note 10)	9,480	11,135
Other long-term liabilities	9,381	8,980
Total Long-Term Liabilities	477,358	336,315
Contingencies (Note 9)
Shareholders’ Equity
Common Stock (Note 6) (390,017,518 and 385,191,042 shares of Common Stock and 1,135,239 and 6,111,665 exchangeable shares, par value $0.001 per share, issued and outstanding as at June 30, 2018, and December 31, 2017, respectively)	10,295	10,295
Additional paid in capital	1,328,037	1,327,244
Deficit	(363,043)	(401,204)
Total Shareholders’ Equity	975,289	936,335
Total Liabilities and Shareholders’ Equity	$ 1,622,085	$ 1,429,619

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common Stock, shares issued (in shares)	390,017,518	385,191,042
Common Stock, shares outstanding (in shares)	390,017,518	385,191,042
Exchangeable shares, shares issued (in shares)	1,135,239	6,111,665
Exchangeable shares, shares outstanding (in shares)	1,135,239	6,111,665
Common Stock and exchangeable shares, par value (in dollars per share)	$ 0.001	$ 0.001

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities
Net income	$ 38,161	$ 5,964
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 3)	86,068	58,689
Deferred tax expense	36,651	22,904
Stock-based compensation (Note 6)	10,202	3,183
Amortization of debt issuance costs (Note 5)	1,513	1,225
Cash settlement of restricted share units	(360)	(501)
Unrealized foreign exchange loss	539	1,076
Financial instruments loss (gain) (Note 10)	11,714	(6,886)
Cash settlement of financial instruments (Note 10)	15,483	1,216
Cash settlement of asset retirement obligation	(369)	(298)
Loss on sale	292	9,076
Net change in assets and liabilities from operating activities (Note 11)	(37,994)	(28,112)
Net cash provided by operating activities	130,934	67,536
Investing Activities
Additions to property, plant and equipment (Note 3)	(157,088)	(104,025)
Property acquisitions	(3,100)	(30,410)
Net proceeds from sale of Brazil business unit	0	34,481
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit	0	4,700
Changes in non-cash investing working capital	(6,142)	(627)
Net cash used in investing activities	(166,330)	(95,881)
Financing Activities
Proceeds from bank debt, net of issuance costs (Note 5)	4,988	98,304
Repayment of bank debt (Note 5)	(153,000)	(33,000)
Proceeds from exercise of stock options (Note 6)	845	0
Repurchase of shares of Common Stock (Note 6)	(1,208)	(10,000)
Proceeds from issuance of Senior Notes, net of issuance costs (Note 5)	288,087	0
Net cash provided by financing activities	139,712	55,304
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(69)	(1,175)
Net increase in cash, cash equivalents and restricted cash and cash equivalents	104,247	25,784
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 11)	26,678	43,267
Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 11)	$ 130,925	$ 69,051

XML

Condensed Consolidated Statements of Shareholders' Equity (Unaudited) - USD ($) $ in Thousands	Total	Share Capital	Additional Paid in Capital	Deficit
Increase (Decrease) in Stockholders' Equity
Cumulative adjustment for accounting change related to tax reorganizations				$ 124,476
Balance, beginning of period at Dec. 31, 2016		$ 10,303	$ 1,342,656	(493,972)
Increase (Decrease) in Stockholders' Equity
Repurchase of Common Stock (Note 6)			(9,996)
Exercise of stock options (Note 6)			0
Stock-based compensation (Note 6)			1,354
Net income	$ 5,964			5,964
Balance, end of period at Jun. 30, 2017	980,781	10,299	1,334,014	(363,532)
Balance, beginning of period at Dec. 31, 2016		10,303	1,342,656	(493,972)
Increase (Decrease) in Stockholders' Equity
Repurchase of Common Stock (Note 6)		(4)
Balance, end of period at Dec. 31, 2017		10,295	1,327,244	(401,204)
Increase (Decrease) in Stockholders' Equity
Cumulative adjustment for accounting change related to tax reorganizations				0
Repurchase of Common Stock (Note 6)		0	(1,208)
Exercise of stock options (Note 6)			845
Stock-based compensation (Note 6)			1,156
Net income	38,161			38,161
Balance, end of period at Jun. 30, 2018	$ 975,289	$ 10,295	$ 1,328,037	$ (363,043)

XML

Description of Business

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business

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.

XML

Significant Accounting Policies

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Significant Accounting Policies

Significant Accounting Policies

These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2017, included in the Company’s 2017 Annual Report on Form 10-K, filed with the SEC on February 27, 2018.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2017 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as noted below. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

Recently Adopted Accounting Pronouncements

Revenue from Contracts with Customers

The Company adopted Accounting Standard Codification ("ASC") 606 Revenue from Contracts with Customers with a date of initial application of January 1, 2018 in accordance with the modified retrospective approach without using the practical expedients. Except for providing enhanced disclosures about the Company's revenue transactions, the application of ASC 606 did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.

a) Significant Accounting Policy

The Company's revenue relates to oil and natural gas sales in Colombia. The Company recognizes revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents the Company's share and is recorded net of royalty payments to governments and other mineral interest owners.

The Company evaluates its arrangement with third parties and partners to determine if the Company acts as a principal or an agent. In making this evaluation, management considers if the Company obtains control of the product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by the Company from the transaction.

Tariffs, tolls and fees charged to other entities for use of pipelines owned by the Company are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements.

In the comparative period, revenue from the production of oil and natural gas was recognized when the customer took title and assumed the risks and rewards of ownership, prices were fixed or determinable, the sale was evidenced by a contract and collection of the revenue was reasonably assured.

b) Significant Judgments

When determining if the Company acted as a principal or as an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers detailed criteria for revenue recognition set out in ASC 606.

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 addressed certain aspects of recognition, measurement, presentation and disclosure of financial instruments. ASU 2016-01 was effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. The implementation of this update did not impact on the Company’s consolidated financial position, results of operations or cash flows or disclosure.

In February 2018, the FASB issued ASU 2018-03, "Recognition and Measurement of Financial Assets and Financial Liabilities". ASU 2018-03 clarified certain aspects of the guidance in ASU 2016-01. ASU 2018-03 is effective for annual reporting periods beginning after December 15, 2017 and interim reporting periods within those annual reporting periods beginning after June 15, 2018. Early adoption is permitted upon adoption of ASU 2016-01.The amendments should be applied retrospectively with a cumulative-effect adjustment to the effective date of ASU 2016-01. The Company early adopted this update on January 1, 2018. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Recently Issued but Not Yet Adopted Accounting Pronouncements

Leases

In January 2018, the FASB issued ASU 2018-01, "Land Easement Practical Expedient for Transition to Topic 842". ASU 2018-01 provides an optional transition practical expedient that, if elected, would not require an organization to reconsider their accounting for existing or expired land easements that were not previously accounted for as leases under Topic 840. The effective date and transition requirements for the amendment is the same as the effective date and transition requirements in Update 2016-02. The Company is planning to adopt ASU 2018-01 upon transition to ASU 2016-01 "Leases".

The Company is finalizing an assessment of its contract inventory using certain practical expedients to determine which contracts meet the definition of a lease. The next steps will include classifying leases as either financing or operating, establishing interest rates and determining the value of right-of-use lease assets and lease liabilities. The Company expects to apply the guidance of ASU 2016-02 using a modified retrospective transition approach.

XML

Segment and Geographic Reporting

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Segment and Geographic Reporting

Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. Commencing 2018, the Company has one reportable segment based on geographic organization, Colombia. Prior to the sale of the Company's Brazil business unit effective June 30, 2017 and Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. The "All Other" category represents the Company’s corporate activities, Mexico activities and Brazil and Peru activities until the date of sale.

The following tables present information on the Company’s reportable segments and other activities:

	Three Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	163,446	$	—		$	163,446
Depletion, depreciation and accretion	46,065		542			46,607
General and administrative expenses	7,213		6,000			13,213
Income (loss) before income taxes	51,029		(2,733		)	48,296
Segment capital expenditures	83,757		637			84,394
	Three Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	91,905	$	4,223		$	96,128
Depletion, depreciation and accretion	30,130		1,683			31,813
General and administrative expenses	5,229		4,284			9,513
Income (loss) before income taxes	21,598		(15,108		)	6,490
Segment capital expenditures	55,436		2,429			57,865
	Six Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	301,674	$	—		$	301,674
Depletion, depreciation and accretion	84,564		1,504			86,068
General and administrative expenses	14,022		10,351			24,373
Income (loss) before income taxes	112,180		(20,252		)	91,928
Segment capital expenditures	156,318		770			157,088
	Six Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	182,369	$	8,418		$	190,787
Depletion, depreciation and accretion	55,065		3,624			58,689
General and administrative expenses	10,061		8,164			18,225
Income (loss) before income taxes	58,742		(20,685		)	38,057
Segment capital expenditures	98,276		5,749			104,025

	As at June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,176,540	$	1,656	$	1,178,196
Goodwill	102,581		—		102,581
All other assets	175,563		165,745		341,308
Total Assets	$	1,454,684	$	167,401	$	1,622,085
	As at December 31, 2017
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,096,833	$	2,391	$	1,099,224
Goodwill	102,581		—		102,581
All other assets	176,980		50,834		227,814
Total Assets	$	1,376,394	$	53,225	$	1,429,619

XML

Property, Plant and Equipment

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Oil and natural gas properties
Proved	$	3,014,725		$	2,810,796
Unproved	423,808			464,948
	3,438,533			3,275,744
Other	19,086			26,401
	3,457,619			3,302,145
Accumulated depletion, depreciation and impairment	(2,279,423		)	(2,202,921		)
	$	1,178,196		$	1,099,224

The Company used an average Brent price of $62.58 per bbl for the purposes of the June 30, 2018 ceiling test calculations (March 31, 2018 - $56.92, December 31, 2017 - $54.19).

XML

Debt and Debt Issuance Costs

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Debt and Debt Issuance Costs

Debt and Debt Issuance Costs

The Company's debt at June 30, 2018 and December 31, 2017 was as follows:

(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Senior notes	$	300,000		$	—
Convertible notes	115,000			115,000
Revolving credit facility	—			148,000
Unamortized debt issuance costs	(16,870		)	(6,458		)
Long-term debt	$	398,130		$	256,542

Senior Notes

On February 15, 2018, Gran Tierra Energy International Holdings Ltd. ("GTEIH"), an indirect, wholly owned subsidiary of the Company, issued $300 million of 6.25% Senior Notes due 2025 (the "Senior Notes"). The Senior Notes are fully and unconditionally guaranteed by the Company and certain subsidiaries of the Company that guarantee its revolving credit facility. Net proceeds from the sale of the Senior Notes were $288.1 million, after deducting the initial purchasers' discounts and commission and the offering expenses payable by the Company.

The Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Before February 15, 2022, GTEIH may, at its option, redeem all or a portion of the Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2022 - 103.125%; 2023 - 101.563%; 2024 and thereafter - 100%.

Interest Expense

The following table presents total interest expense recognized in the accompanying interim unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		2018		2017
Contractual interest and other financing expenses	$	6,532	$	2,711	$	11,357	$	5,201
Amortization of debt issuance costs	843		620		1,513		1,225
	$	7,375	$	3,331	$	12,870	$	6,426

XML

Share Capital

6 Months Ended

Jun. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share Capital

Share Capital

On  May 1, 2018, Gran Tierra Exchangeco Inc., a subsidiary of the Company, announced that it had established a redemption date of July 5, 2018 in respect of all of its outstanding exchangeable shares. Effective July 5, 2018, all remaining outstanding exchangeable shares of record on July 4, 2018 were acquired for purchase consideration of one share of Gran Tierra common stock, and on July 9, 2018, the Company retired and canceled one share of Special A Voting Stock and one share of Special B Voting Stock, which held voting rights in connection with those exchangeable shares. As a result, no shares of Special A Voting Stock and Special B Voting Stock remain outstanding.

	Shares of Common Stock		Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2017	385,191,042		4,422,776		1,688,889
Options exercised	319,462		—		—
Shares repurchased and canceled	(469,412	)	—		—
Exchange of exchangeable shares	4,976,426		(3,287,537	)	(1,688,889	)
Balance, June 30, 2018	390,017,518		1,135,239		—

On March 7, 2018, the Company announced that it intended to implement a share repurchase program (the “2018 Program”) through the facilities of the Toronto Stock Exchange ("TSX") and eligible alternative trading platforms in Canada. Under the 2018 Program, the Company is able to purchase at prevailing market prices up to 19,269,732 shares of Common Stock, representing approximately 5.00% of the issued and outstanding shares of Common Stock as of March 8, 2018. Shares purchased pursuant to 2018 Program will be canceled. The 2018 Program will expire on March 11, 2019, or earlier if the 5.00% share maximum is reached.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock option activity for the six months ended June 30, 2018:

	PSUs		DSUs	RSUs		Stock Options
	Number of Outstanding Share Units		Number of Outstanding Share Units	Number of Outstanding Share Units		Number of Outstanding Stock Options		Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2017	6,131,951		455,768	122,090		8,960,692		3.65
Granted	3,544,001		131,888	—		1,996,526		2.51
Exercised	—		—	(120,268	)	(319,462	)	2.65
Forfeited	(213,160	)	—	(1,822	)	(491,475	)	5.42
Expired	—		—	—		(171,854	)	6.15
Balance, June 30, 2018	9,462,792		587,656	—		9,974,427		3.33

Stock-based compensation expense for the three and six months ended June 30, 2018, was $6.9 million and $10.2 million, respectively, and was primarily recorded in general and administrative ("G&A") expenses (three and six months ended June 30, 2017 - $2.0 million and $3.2 million, respectively).

At June 30, 2018, there was $23.0 million (December 31, 2017 - $13.7 million) of unrecognized compensation cost related to unvested PSUs and stock options which is expected to be recognized over a weighted average period of 1.8 years.

Net Income per Share

Basic net income per share is calculated by dividing net income by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income per share is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock awards were vested at the end of the applicable period plus potentially issuable shares on conversion of the convertible notes. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

Weighted Average Shares Outstanding

	Three Months Ended June 30,			Six Months Ended June 30,
	2018		2017	2018		2017
Weighted average number of common and exchangeable shares outstanding	391,054,204		398,585,290	391,173,460		398,795,023
Shares issuable pursuant to stock options	4,894,633		—	2,420,509		625,631
Shares assumed to be purchased from proceeds of stock options	(4,308,138	)	—	(2,166,348	)	(604,563	)
Shares issuable pursuant to convertible notes	35,814,393		—	35,814,393		—
Weighted average number of diluted common and exchangeable shares outstanding	427,455,092		398,585,290	427,242,014		398,816,091

For the three months ended June 30, 2018, 5,240,018 options, on a weighted average basis, (three months ended June 30, 2017 - 10,634,157 options) were excluded from the diluted income (loss) per share calculation as the options were anti-dilutive. For the six months ended June 30, 2018, 7,385,714 options, on a weighted average basis, (six months ended June 30, 2017 - 9,616,800 options) were excluded from the diluted income per share calculation as the options were anti-dilutive. Shares issuable upon conversion of the 5.00% Convertible Notes due 2021 ("Convertible Notes") were dilutive and included in the diluted income per share calculation. For the three and six months ended June 30, 2018, the numerator used in the computation of diluted earnings per share included net income for the period adjusted for interest on convertible debentures and amortization of debt issuance costs of $1.7 million and $3.4 million, respectively.

XML

Revenue

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

Most of the Company's revenues are from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to ICE Brent and adjusted for Vasconia crude, quality and transportation discounts each month. For the three and six months ended June 30, 2018, 100% (three and six months ended June 30, 2017 - 100%) of the Company's revenue resulted from oil sales. During the three and six months ended June 30, 2018, quality and transportation discounts were 14% and 15%, respectively, of the ICE Brent price (three and six months ended June 30, 2017 - 21% and 22%, respectively). During the three and six months ended June 30, 2018, the Company's production was sold primarily to three major customers in Colombia (three and six months ended June 30, 2017 - four).

As at June 30, 2018, accounts receivable included $4.8 million of accrued sales revenue which related to June 2018 production (December 31, 2017 - $11.1 million which related to December 31, 2017 production).

XML

Taxes

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

Taxes

Taxes

The Company's effective tax rate was 58% in the six months ended June 30, 2018, compared with 84% in the comparative period in 2017. Current income tax expense was higher in the six months ended June 30, 2018, compared with the corresponding period in 2017, primarily as a result of higher taxable income in Colombia. The deferred income tax expense of $36.7 million for the six months ended June 30, 2018, was primarily due to excess tax depreciation compared with accounting depreciation in Colombia.  

For the six months ended June 30, 2018, the difference between the effective tax rate of 58% and the 21% U.S. statutory rate was primarily due to an increase to the impact of foreign taxes, valuation allowance, stock-based compensation, foreign currency translation and non-deductible third party royalty in Colombia.

For the comparative period in 2017, the effective tax rate differed from the U.S. statutory rate of 35% primarily due to an increase in the valuation allowance, which was largely attributable to losses incurred in the United States, Brazil and Colombia, as well as the impact of a non-deductible third-party royalty in Colombia, foreign and local taxes, and stock-based compensation. These items were partially offset by foreign currency translation adjustments and other permanent differences.

XML

Contingencies

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Contingencies

Contingencies

The Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“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 an additional royalty (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 $52.8 million as at June 30, 2018. At this time no amount has been accrued in the interim unaudited condensed consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

In addition to the above, the Company has a number of other lawsuits and claims pending. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, the Company 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 associated with these lawsuits and claims as they are incurred or become probable and determinable.

Letters of credit and other credit support

At June 30, 2018, the Company had provided letters of credit and other credit support totaling $69.8 million (December 31, 2017 - $76.0 million) as security relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.

XML

Financial Instruments and Fair Value Measurement

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Financial Instruments and Fair Value Measurement

Financial Instruments and Fair Value Measurement

Financial Instruments

At June 30, 2018, the Company’s financial instruments recognized in the balance sheet consisted of: cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; investments; derivatives, accounts payable and accrued liabilities, long-term debt and equity compensation award liability.

Fair Value Measurement

The fair value of certain investments, derivatives and equity compensation awards (PSU and DSU) liabilities are remeasured at the estimated fair value at the end of each reporting period.

The fair value of the short-term portion of the Company's investment in PetroTal Corp. ("PetroTal") (formerly Sterling Resources Ltd.) was estimated using quoted prices at June 30, 2018 and the foreign exchange rate at that time. The fair value of the long-term portion of the investment restricted by escrow conditions was estimated using observable and unobservable inputs; factors that were evaluated included quoted market prices, precedent comparable transactions, risk-free rate, measures of market risk volatility, estimates of the Company's and PetroTal's costs of capital and quotes from third parties.

The fair value of commodity price and foreign currency derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

The fair value of the PSU liability was estimated based on option pricing model using inputs such as quoted market prices in an active market, and PSU performance factors. The fair value of the DSU liabilities was estimated based on quoted market prices in an active market.

The fair value of the Company's investment in PetroTal, derivatives and PSU and DSU liabilities at June 30, 2018, and December 31, 2017, was as follows:

(Thousands of U.S. Dollars)	As at June 30, 2018		As at December 31, 2017
Investment in PetroTal shares - current and long-term	$	47,956	$	44,202
Foreign currency derivative asset	930		302
	$	48,886	$	44,504
Commodity price derivative liability	$	27,157	$	21,151
Equity compensation award liability - current and long-term	21,077		11,430
	$	48,234	$	32,581

The following table presents gains or losses on financial instruments recognized in the accompanying interim unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2017
Commodity price derivative loss (gain)	$	14,461		$	(1,545	)	$	19,455		$	(6,247	)
Foreign currency derivatives loss (gain)	1,945			98			(2,024		)	(639		)
Investment gain	(11,638		)	—			(5,717		)	—
Financial instruments loss (gain)	$	4,768		$	(1,447	)	$	11,714		$	(6,886	)

Investment gain for the three and six months ended June 30, 2018, related to the fair value gain on the PetroTal shares Gran Tierra received or subscribed for in connection with the sale of its Peru business unit in December 2017. For the three and six months ended June 30, 2018, this investment gain was unrealized.

Financial instruments not recorded at fair value include the Senior Notes and the Convertible Notes. At June 30, 2018, the carrying amounts of the Senior Notes and the Convertible Notes were $288.6 million and $111.5 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $282.0 million and $143.8 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.

At June 30, 2018, the fair value of the current portion of the investment and DSU liability was determined using Level 1 inputs, the fair value of derivatives and PSUs was determined using Level 2 inputs and the fair value of the long-term portion of the investment restricted by escrow conditions was determined using Level 3 inputs. The table below presents the fair value of the long-term portion of the investment:

	Six Months Ended			Year Ended
(Thousands of U.S. Dollars)	June 30, 2018			December 31, 2017
Opening balance, investment - long-term	$	19,147		$	—
Acquisition	—			19,091
Transfer from long-term (Level 3) to current (Level 1)	(4,787		)	—
Unrealized valuation gain	2,528			56
Unrealized foreign exchange loss	(1,586		)	—
Closing balance, investment - long-term	$	15,302		$	19,147

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s Senior Notes, Convertible Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure above regarding the fair value of the Convertible Notes was determined using Level 2 inputs based on the indicative pricing published by certain third-party services or trading levels of the Convertible Notes, which are not listed on any securities exchange or quoted on an inter-dealer automated quotation system. The disclosure in the paragraph above regarding the fair value of cash and restricted cash and cash equivalents, revolving credit facility and Senior Notes 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 June 30, 2018, the Company had outstanding commodity price derivative positions as follows:

Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

The Company does not have any outstanding commodity price derivative positions relating to 2019.

Foreign Currency Derivatives

The Company utilizes foreign currency derivatives to manage the variability in cash flows associated with the Company's forecasted Colombian peso ("COP") denominated expenses. At June 30, 2018, the Company had outstanding foreign currency derivative positions as follows:

Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: July 1, 2018 to December 31, 2018	87,000	29,685	COP	3,000	3,107

⁽¹⁾ At June 30, 2018 foreign exchange rate.

XML

Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company's interim unaudited condensed consolidated balance sheet that sum to the total of the same such amounts shown in the interim unaudited condensed consolidated statements of cash flows:

(Thousands of U.S. Dollars)	As at June 30,				As at December 31,
	2018		2017		2017		2016
Cash and cash equivalents	$	125,807	$	53,310	$	12,326	$	25,175
Restricted cash and cash equivalents - current	2,836		5,844		11,787		8,322
Restricted cash and cash equivalents - long-term (included in other long-term assets)	2,282		9,897		2,565		9,770
	$	130,925	$	69,051	$	26,678	$	43,267

Net changes in assets and liabilities from operating activities were as follows:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017
Accounts receivable and other long-term assets	$	(11,723	)	$	11,024
Derivatives	3,431			—
Inventory	(3,054		)	(47		)
Prepaids	(301		)	2,190
Accounts payable and accrued and other long-term liabilities	971			(6,179		)
Taxes receivable and payable	(27,318		)	(35,100		)
Net changes in assets and liabilities from operating activities	$	(37,994	)	$	(28,112	)

The following table provides additional supplemental cash flow disclosures:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	62,009	$	56,044

XML

Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Recently Adopted Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Revenue from Contracts with Customers

The Company adopted Accounting Standard Codification ("ASC") 606 Revenue from Contracts with Customers with a date of initial application of January 1, 2018 in accordance with the modified retrospective approach without using the practical expedients. Except for providing enhanced disclosures about the Company's revenue transactions, the application of ASC 606 did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.

a) Significant Accounting Policy

The Company's revenue relates to oil and natural gas sales in Colombia. The Company recognizes revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents the Company's share and is recorded net of royalty payments to governments and other mineral interest owners.

The Company evaluates its arrangement with third parties and partners to determine if the Company acts as a principal or an agent. In making this evaluation, management considers if the Company obtains control of the product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by the Company from the transaction.

Tariffs, tolls and fees charged to other entities for use of pipelines owned by the Company are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements.

In the comparative period, revenue from the production of oil and natural gas was recognized when the customer took title and assumed the risks and rewards of ownership, prices were fixed or determinable, the sale was evidenced by a contract and collection of the revenue was reasonably assured.

b) Significant Judgments

When determining if the Company acted as a principal or as an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers detailed criteria for revenue recognition set out in ASC 606.

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 addressed certain aspects of recognition, measurement, presentation and disclosure of financial instruments. ASU 2016-01 was effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. The implementation of this update did not impact on the Company’s consolidated financial position, results of operations or cash flows or disclosure.

In February 2018, the FASB issued ASU 2018-03, "Recognition and Measurement of Financial Assets and Financial Liabilities". ASU 2018-03 clarified certain aspects of the guidance in ASU 2016-01. ASU 2018-03 is effective for annual reporting periods beginning after December 15, 2017 and interim reporting periods within those annual reporting periods beginning after June 15, 2018. Early adoption is permitted upon adoption of ASU 2016-01.The amendments should be applied retrospectively with a cumulative-effect adjustment to the effective date of ASU 2016-01. The Company early adopted this update on January 1, 2018. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Recently Issued but Not Yet Adopted Accounting Pronouncements

Leases

In January 2018, the FASB issued ASU 2018-01, "Land Easement Practical Expedient for Transition to Topic 842". ASU 2018-01 provides an optional transition practical expedient that, if elected, would not require an organization to reconsider their accounting for existing or expired land easements that were not previously accounted for as leases under Topic 840. The effective date and transition requirements for the amendment is the same as the effective date and transition requirements in Update 2016-02. The Company is planning to adopt ASU 2018-01 upon transition to ASU 2016-01 "Leases".

The Company is finalizing an assessment of its contract inventory using certain practical expedients to determine which contracts meet the definition of a lease. The next steps will include classifying leases as either financing or operating, establishing interest rates and determining the value of right-of-use lease assets and lease liabilities. The Company expects to apply the guidance of ASU 2016-02 using a modified retrospective transition approach.

XML

Segment and Geographic Reporting (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule of Information on Reportable Segments and Other Activities

The following tables present information on the Company’s reportable segments and other activities:

	Three Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	163,446	$	—		$	163,446
Depletion, depreciation and accretion	46,065		542			46,607
General and administrative expenses	7,213		6,000			13,213
Income (loss) before income taxes	51,029		(2,733		)	48,296
Segment capital expenditures	83,757		637			84,394
	Three Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	91,905	$	4,223		$	96,128
Depletion, depreciation and accretion	30,130		1,683			31,813
General and administrative expenses	5,229		4,284			9,513
Income (loss) before income taxes	21,598		(15,108		)	6,490
Segment capital expenditures	55,436		2,429			57,865
	Six Months Ended June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	301,674	$	—		$	301,674
Depletion, depreciation and accretion	84,564		1,504			86,068
General and administrative expenses	14,022		10,351			24,373
Income (loss) before income taxes	112,180		(20,252		)	91,928
Segment capital expenditures	156,318		770			157,088
	Six Months Ended June 30, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	182,369	$	8,418		$	190,787
Depletion, depreciation and accretion	55,065		3,624			58,689
General and administrative expenses	10,061		8,164			18,225
Income (loss) before income taxes	58,742		(20,685		)	38,057
Segment capital expenditures	98,276		5,749			104,025

Schedule of Long-lived Assets by Geographical Area

	As at June 30, 2018
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,176,540	$	1,656	$	1,178,196
Goodwill	102,581		—		102,581
All other assets	175,563		165,745		341,308
Total Assets	$	1,454,684	$	167,401	$	1,622,085
	As at December 31, 2017
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,096,833	$	2,391	$	1,099,224
Goodwill	102,581		—		102,581
All other assets	176,980		50,834		227,814
Total Assets	$	1,376,394	$	53,225	$	1,429,619

XML

Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Oil and natural gas properties
Proved	$	3,014,725		$	2,810,796
Unproved	423,808			464,948
	3,438,533			3,275,744
Other	19,086			26,401
	3,457,619			3,302,145
Accumulated depletion, depreciation and impairment	(2,279,423		)	(2,202,921		)
	$	1,178,196		$	1,099,224

XML

Debt and Debt Issuance Costs (Tables)

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Schedule of Debt

The Company's debt at June 30, 2018 and December 31, 2017 was as follows:

(Thousands of U.S. Dollars)	As at June 30, 2018			As at December 31, 2017
Senior notes	$	300,000		$	—
Convertible notes	115,000			115,000
Revolving credit facility	—			148,000
Unamortized debt issuance costs	(16,870		)	(6,458		)
Long-term debt	$	398,130		$	256,542

Schedule of Interest Expense Recognized

The following table presents total interest expense recognized in the accompanying interim unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017		2018		2017
Contractual interest and other financing expenses	$	6,532	$	2,711	$	11,357	$	5,201
Amortization of debt issuance costs	843		620		1,513		1,225
	$	7,375	$	3,331	$	12,870	$	6,426

XML

Share Capital (Tables)

6 Months Ended

Jun. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Common Stock

	Shares of Common Stock		Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2017	385,191,042		4,422,776		1,688,889
Options exercised	319,462		—		—
Shares repurchased and canceled	(469,412	)	—		—
Exchange of exchangeable shares	4,976,426		(3,287,537	)	(1,688,889	)
Balance, June 30, 2018	390,017,518		1,135,239		—

Schedule of PSU, DSU, RSU and Stock Option Activity

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock option activity for the six months ended June 30, 2018:

	PSUs		DSUs	RSUs		Stock Options
	Number of Outstanding Share Units		Number of Outstanding Share Units	Number of Outstanding Share Units		Number of Outstanding Stock Options		Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2017	6,131,951		455,768	122,090		8,960,692		3.65
Granted	3,544,001		131,888	—		1,996,526		2.51
Exercised	—		—	(120,268	)	(319,462	)	2.65
Forfeited	(213,160	)	—	(1,822	)	(491,475	)	5.42
Expired	—		—	—		(171,854	)	6.15
Balance, June 30, 2018	9,462,792		587,656	—		9,974,427		3.33

Schedule of Weighted Average Shares Outstanding

Weighted Average Shares Outstanding

	Three Months Ended June 30,			Six Months Ended June 30,
	2018		2017	2018		2017
Weighted average number of common and exchangeable shares outstanding	391,054,204		398,585,290	391,173,460		398,795,023
Shares issuable pursuant to stock options	4,894,633		—	2,420,509		625,631
Shares assumed to be purchased from proceeds of stock options	(4,308,138	)	—	(2,166,348	)	(604,563	)
Shares issuable pursuant to convertible notes	35,814,393		—	35,814,393		—
Weighted average number of diluted common and exchangeable shares outstanding	427,455,092		398,585,290	427,242,014		398,816,091

XML

Financial Instruments and Fair Value Measurement (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Derivatives and RSU, PSU and DSU Liabilities

The fair value of the Company's investment in PetroTal, derivatives and PSU and DSU liabilities at June 30, 2018, and December 31, 2017, was as follows:

(Thousands of U.S. Dollars)	As at June 30, 2018		As at December 31, 2017
Investment in PetroTal shares - current and long-term	$	47,956	$	44,202
Foreign currency derivative asset	930		302
	$	48,886	$	44,504
Commodity price derivative liability	$	27,157	$	21,151
Equity compensation award liability - current and long-term	21,077		11,430
	$	48,234	$	32,581

Schedule of Gains or Losses on Financial Instruments Recognized

The following table presents gains or losses on financial instruments recognized in the accompanying interim unaudited condensed consolidated statements of operations:

	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017			2018			2017
Commodity price derivative loss (gain)	$	14,461		$	(1,545	)	$	19,455		$	(6,247	)
Foreign currency derivatives loss (gain)	1,945			98			(2,024		)	(639		)
Investment gain	(11,638		)	—			(5,717		)	—
Financial instruments loss (gain)	$	4,768		$	(1,447	)	$	11,714		$	(6,886	)

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The table below presents the fair value of the long-term portion of the investment:

	Six Months Ended			Year Ended
(Thousands of U.S. Dollars)	June 30, 2018			December 31, 2017
Opening balance, investment - long-term	$	19,147		$	—
Acquisition	—			19,091
Transfer from long-term (Level 3) to current (Level 1)	(4,787		)	—
Unrealized valuation gain	2,528			56
Unrealized foreign exchange loss	(1,586		)	—
Closing balance, investment - long-term	$	15,302		$	19,147

Schedule of Commodity Price Derivative Positions and Commodity Foreign Currency Contracts

At June 30, 2018, the Company had outstanding commodity price derivative positions as follows:

Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: July 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

Schedule of Outstanding Foreign Currency Derivative Positions

At June 30, 2018, the Company had outstanding foreign currency derivative positions as follows:

Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: July 1, 2018 to December 31, 2018	87,000	29,685	COP	3,000	3,107

⁽¹⁾ At June 30, 2018 foreign exchange rate.

XML

Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Elements [Abstract]

Reconciliation of Cash, Cash Equivalents and Restricted Cash and Cash Equivalents

The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company's interim unaudited condensed consolidated balance sheet that sum to the total of the same such amounts shown in the interim unaudited condensed consolidated statements of cash flows:

(Thousands of U.S. Dollars)	As at June 30,				As at December 31,
	2018		2017		2017		2016
Cash and cash equivalents	$	125,807	$	53,310	$	12,326	$	25,175
Restricted cash and cash equivalents - current	2,836		5,844		11,787		8,322
Restricted cash and cash equivalents - long-term (included in other long-term assets)	2,282		9,897		2,565		9,770
	$	130,925	$	69,051	$	26,678	$	43,267

Schedule of Net Changes in Assets and Liabilities

Net changes in assets and liabilities from operating activities were as follows:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018			2017
Accounts receivable and other long-term assets	$	(11,723	)	$	11,024
Derivatives	3,431			—
Inventory	(3,054		)	(47		)
Prepaids	(301		)	2,190
Accounts payable and accrued and other long-term liabilities	971			(6,179		)
Taxes receivable and payable	(27,318		)	(35,100		)
Net changes in assets and liabilities from operating activities	$	(37,994	)	$	(28,112	)

Schedule of Additional Supplemental Cash Flow Disclosures

The following table provides additional supplemental cash flow disclosures:

	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2018		2017
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	62,009	$	56,044

XML

Significant Accounting Policies (Details)	6 Months Ended
	Jun. 30, 2018 day
Accounting Policies [Abstract]
Payment terms, number of days	3

XML

Segment and Geographic Reporting - Schedule of Information on Reportable Segments and Other Activities (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) segment	Jun. 30, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment			1
Oil and natural gas sales	$ 163,446	$ 96,128	$ 301,674	$ 190,787
Depletion, depreciation and accretion	46,607	31,813	86,068	58,689
General and administrative expenses	13,213	9,513	24,373	18,225
Income (loss) before income taxes	48,296	6,490	91,928	38,057
Segment capital expenditures	84,394	57,865	157,088	104,025
Reportable Segments | Colombia
Segment Reporting Information [Line Items]
Oil and natural gas sales	163,446	91,905	301,674	182,369
Depletion, depreciation and accretion	46,065	30,130	84,564	55,065
General and administrative expenses	7,213	5,229	14,022	10,061
Income (loss) before income taxes	51,029	21,598	112,180	58,742
Segment capital expenditures	83,757	55,436	156,318	98,276
All Other
Segment Reporting Information [Line Items]
Oil and natural gas sales	0	4,223	0	8,418
Depletion, depreciation and accretion	542	1,683	1,504	3,624
General and administrative expenses	6,000	4,284	10,351	8,164
Income (loss) before income taxes	(2,733)	(15,108)	(20,252)	(20,685)
Segment capital expenditures	$ 637	$ 2,429	$ 770	$ 5,749

XML

Segment and Geographic Reporting - Schedule of Long-lived Assets by Geographical Area (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Property, plant and equipment	$ 1,178,196	$ 1,099,224
Goodwill	102,581	102,581
All other assets	341,308	227,814
Total Assets	1,622,085	1,429,619
Reportable Segments | Colombia
Segment Reporting Information [Line Items]
Property, plant and equipment	1,176,540	1,096,833
Goodwill	102,581	102,581
All other assets	175,563	176,980
Total Assets	1,454,684	1,376,394
All Other
Segment Reporting Information [Line Items]
Property, plant and equipment	1,656	2,391
Goodwill	0	0
All other assets	165,745	50,834
Total Assets	$ 167,401	$ 53,225

XML

Property, Plant and Equipment - Schedule of Property, Plant, and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Oil and natural gas properties	$ 3,457,619	$ 3,302,145
Accumulated depletion, depreciation and impairment	(2,279,423)	(2,202,921)
Total Property, Plant and Equipment (Notes 3 and 4)	1,178,196	1,099,224
Oil and natural gas properties
Property, Plant and Equipment [Line Items]
Oil and natural gas properties	3,438,533	3,275,744
Proved
Property, Plant and Equipment [Line Items]
Oil and natural gas properties	3,014,725	2,810,796
Unproved
Property, Plant and Equipment [Line Items]
Oil and natural gas properties	423,808	464,948
Other
Property, Plant and Equipment [Line Items]
Oil and natural gas properties	$ 19,086	$ 26,401

XML

Property, Plant and Equipment - Property, Plant and Equipment (Narrative) (Details) - $ / bbl	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Jun. 30, 2018
Crude Oil and NGL
Property, Plant and Equipment [Line Items]
Average Brent price per bbl (in dollars per barrel)	56.92	54.19	62.58

XML

Debt and Debt Issuance Costs - Schedule of Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Feb. 15, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (16,870)		$ (6,458)
Long-term debt	398,130		256,542
Convertible notes
Debt Instrument [Line Items]
Convertible senior notes and revolving credit facility	115,000		115,000
Revolving credit facility | Revolving credit facility
Debt Instrument [Line Items]
Convertible senior notes and revolving credit facility	0		148,000
Senior Notes Unsecured 6.25% | Senior notes
Debt Instrument [Line Items]
Convertible senior notes and revolving credit facility	$ 300,000	$ 300,000	$ 0

XML

Debt and Debt Issuance Costs - Narrative (Details) - USD ($) $ in Thousands		6 Months Ended
	Feb. 15, 2018	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Line of Credit Facility [Line Items]
Proceeds from issuance of Senior Notes, net of issuance costs (Note 5)		$ 288,087	$ 0
Senior Notes Unsecured 6.25% | Senior Notes
Line of Credit Facility [Line Items]
Long-term debt, gross	$ 300,000	$ 300,000		$ 0
Debt instrument, interest rate, stated percentage	6.25%	6.25%
Proceeds from issuance of Senior Notes, net of issuance costs (Note 5)	$ 288,100
Prior to February 15th, 2022 | Senior Notes Unsecured 6.25% | Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, redemption price, percentage	100.00%
2022 | Senior Notes Unsecured 6.25% | Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, redemption price, percentage	103.125%
2023 | Senior Notes Unsecured 6.25% | Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, redemption price, percentage	101.563%
2024 and thereafter | Senior Notes Unsecured 6.25% | Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, redemption price, percentage	100.00%

XML

Debt and Debt Issuance Costs - Schedule of Interest Expense Recognized (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Debt Disclosure [Abstract]
Contractual interest and other financing expenses	$ 6,532	$ 2,711	$ 11,357	$ 5,201
Amortization of debt issuance costs	843	620	1,513	1,225
Total interest expense recognized	$ 7,375	$ 3,331	$ 12,870	$ 6,426

XML

Share Capital - Additional Information (Details) - $ / shares	Jul. 09, 2018	Jul. 05, 2018	Mar. 08, 2018	Jun. 30, 2018	Mar. 07, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, par value (in dollars per share)				$ 0.001		$ 0.001
The 2018 Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized under the 2018 Program (up to) (in shares)					19,269,732
Shares authorized representing issued and outstanding shares of Common Stock (as a percent)			5.00%
Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Business combination consideration transferred equity interests issued and issuable number of shares for each share of acquired entity shares		1
Special A Voting Stock | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued during period, shares, cancelled	1
Preferred stock, shares outstanding	0
Special B Voting Stock | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued during period, shares, cancelled	1
Preferred stock, shares outstanding	0

XML

Share Capital - Schedule of Common Stock (Details)	6 Months Ended
	Jun. 30, 2018 shares
Increase (Decrease) in Common Stock
Beginning balance (in shares)	385,191,042
Exercised (in shares)	319,462
Ending balance (in shares)	390,017,518
Shares of Common Stock
Increase (Decrease) in Common Stock
Beginning balance (in shares)	385,191,042
Exercised (in shares)	319,462
Shares repurchased and canceled (in shares)	469,412
Exchange of exchangeable shares (in shares)	4,976,426
Ending balance (in shares)	390,017,518
Shares of Common Stock | Exchangeable Shares of Gran Tierra Exchangeco Inc.
Increase (Decrease) in Common Stock
Beginning balance (in shares)	4,422,776
Exercised (in shares)	0
Shares repurchased and canceled (in shares)	0
Exchange of exchangeable shares (in shares)	(3,287,537)
Ending balance (in shares)	1,135,239
Shares of Common Stock | Exchangeable Shares of Gran Tierra Goldstrike Inc.
Increase (Decrease) in Common Stock
Beginning balance (in shares)	1,688,889
Exercised (in shares)	0
Shares repurchased and canceled (in shares)	0
Exchange of exchangeable shares (in shares)	(1,688,889)
Ending balance (in shares)	0

XML

Share Capital - Schedule of PSU, DSU, RSU and Stock Option Activity (Details)	6 Months Ended
	Jun. 30, 2018 $ / shares shares
Number of Outstanding Stock Options
Beginning Balance (in shares)	8,960,692
Granted (in shares)	1,996,526
Exercised (in shares)	(319,462)
Forfeited (in shares)	(491,475)
Expired (in shares)	(171,854)
Ending Balance (in shares)	9,974,427
Weighted Average Exercise Price/Stock Option ($)
Beginning balance (in dollars per share) | $ / shares	$ 3.65
Granted (in dollars per share) | $ / shares	2.51
Exercised (in dollars per share) | $ / shares	2.65
Forfeited (in dollars per share) | $ / shares	5.42
Expired (in dollars per share) | $ / shares	(6.15)
Ending balance (in dollars per share) | $ / shares	$ 3.33
PSUs
Number of Outstanding Share Units
Beginning Balance (in shares)	6,131,951
Granted (in shares)	3,544,001
Exercised (in shares)	0
Forfeited (in shares)	(213,160)
Expired (in shares)	0
Ending Balance (in shares)	9,462,792
DSUs
Number of Outstanding Share Units
Beginning Balance (in shares)	455,768
Granted (in shares)	131,888
Exercised (in shares)	0
Forfeited (in shares)	0
Expired (in shares)	0
Ending Balance (in shares)	587,656
RSUs
Number of Outstanding Share Units
Beginning Balance (in shares)	122,090
Granted (in shares)	0
Exercised (in shares)	(120,268)
Forfeited (in shares)	(1,822)
Expired (in shares)	0
Ending Balance (in shares)	0

XML

Share Capital - Equity Compensation Awards (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 23.0		$ 23.0		$ 13.7
Weighted average period for recognition			1 year 10 months 5 days
General and administrative (G&A) expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 6.9	$ 2.0	$ 10.2	$ 3.2

XML

Share Capital - Schedule of Weighted Average Shares Outstanding (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Weighted average number of common and exchangeable shares outstanding (in shares)	391,054,204	398,585,290	391,173,460	398,795,023
Shares issuable pursuant to stock options (in shares)	4,894,633	0	2,420,509	625,631
Shares assumed to be purchased from proceeds of stock options (in shares)	(4,308,138)	0	(2,166,348)	(604,563)
Shares issuable pursuant to convertible notes due 2021			35,814,393	0
Weighted average number of diluted common and exchangeable shares outstanding (in shares)	427,455,092	398,585,290	427,242,014	398,816,091

XML

Share Capital - Weighted Average Shares Outstanding (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Convertible debt	$ 1.7		$ 1.7
Accumulated amortization of debt issuance costs, line of credit arrangements	$ 3.4		$ 3.4
Convertible notes | Notes
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Stated interest rate	5.00%		5.00%
Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options excluded from diluted income (loss) per share calculation (in shares)	5,240,018	10,634,157	7,385,714	9,616,800

XML

Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Concentration Risk [Line Items]
Variable adjustment for transportation, location, quality, and other elements, percentage	(14.00%)	(21.00%)	(15.00%)	(22.00%)
Accrued sales revenue	$ 4.8		$ 4.8		$ 11.1
Product Concentration Risk | Revenue from Contract with Customer
Concentration Risk [Line Items]
Concentration risk, percentage	100.00%	100.00%

XML

Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Effective tax rate			58.00%	84.00%
Deferred income tax expense	$ 23,169	$ 11,525	$ 36,651	$ 22,904

XML

Contingencies (Details) - USD ($)	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Loss Contingencies [Line Items]
Letters of credit and other credit support provided	$ 69,800,000	$ 76,000,000
Pending Litigation Royalty, Transportation and Related Costs
Loss Contingencies [Line Items]
Estimated compensation which would be payable if the ANH's interpretation is correct	52,800,000
Amount accrued	$ 0

XML

Financial Instruments and Fair Value Measurement - Schedule of Fair Value of Derivatives and RSU, PSU and DSU Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Investment in PetroTal shares - current and long-term	$ 47,956	$ 44,202
Foreign currency derivative asset	930	302
Assets, fair value disclosure	48,886	44,504
PSU, DSU and RSU liability - current and long-term	21,077	11,430
Liabilities, fair value disclosure	48,234	32,581
Foreign currency derivative asset
Derivatives, Fair Value [Line Items]
Foreign currency derivative asset	930	302
Commodity Hedge
Derivatives, Fair Value [Line Items]
Commodity price derivative liability	$ 27,157	$ 21,151

XML

Financial Instruments and Fair Value Measurement - Schedule of Gains or Losses on Financial Instruments Recognized (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Investment gain	$ (11,638)	$ 0	$ (5,717)	$ 0
Financial instruments loss (gain)	4,768	(1,447)	11,714	(6,886)
Commodity price derivative loss (gain)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative (loss) gain	14,461	(1,545)	19,455	(6,247)
Foreign currency derivatives loss (gain)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative (loss) gain	$ 1,945	$ 98	$ (2,024)	$ (639)

XML

Financial Instruments and Fair Value Measurement - Narrative (Details) $ in Millions	Jun. 30, 2018 USD ($)
Carrying amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument, fair value disclosure	$ 288.6
Value of the notes	111.5
Fair value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument, fair value disclosure	282.0
Value of the notes	$ 143.8

XML

Financial Instruments and Fair Value Measurement - Rollforward of Level 3 Financial Asset (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Transfer from long-term (Level 3) to current (Level 1)	$ (4,787)	$ 0
Equity Securities
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Opening balance, investment - long-term	15,302	19,147	$ 0
Acquisition	0	19,091
Unrealized valuation gain	2,528	56
Unrealized foreign exchange loss	(1,586)	0
Closing balance, investment - long-term	$ 15,302	$ 19,147

XML

Financial Instruments and Fair Value Measurement - Schedule of Commodity Price Derivative Positions and Commodity Foreign Currency Contracts (Details) - Commodity Hedge bbl in Thousands	6 Months Ended
	Jun. 30, 2018 $ / bbl bbl
Commodity Foreign Currency Contract, Swap April 1 To December 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (in barrels of oil per day) | bbl	5
Commodity Foreign Currency Contract, Swap April 1 To December 31, 2018 | Purchased | Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Floor price (in dollars per barrel)	55.9
Participating Swaps: July 1, to December 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Volume (in barrels of oil per day) | bbl	5
Participating Swaps: July 1, to December 31, 2018 | Purchased | Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Floor price (in dollars per barrel)	52.5
Participating Swaps: July 1, to December 31, 2018 | Purchased | Call
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Floor price (in dollars per barrel)	56.11

XML

Financial Instruments and Fair Value Measurement - Schedule of Outstanding Foreign Currency Derivative Positions (Details) - Collars: July 1, 2018 to December 31, 2018 $ in Thousands, $ in Millions	Jun. 30, 2018 COP ($) $ / collar	Jun. 30, 2018 USD ($) $ / collar
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Amount hedged	$ 87,000	$ 29,685
Purchased | Call
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Purchased call (in COP per collar)	3,000.000	3,000.000
Sold | Put
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Sold put (in COP per collar)	3,107	3,107

XML

Supplemental Cash Flow Information - Reconciliation of Cash, Cash Equivalents and Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 125,807	$ 12,326	$ 53,310	$ 25,175
Restricted cash and cash equivalents - current	2,836	11,787	5,844	8,322
Restricted cash and cash equivalents - long-term (included in other long-term assets)	2,282	2,565	9,897	9,770
Cash, cash equivalents and restricted cash and cash equivalents	$ 130,925	$ 26,678	$ 69,051	$ 43,267

XML

Supplemental Cash Flow Information - Schedule of Net Changes in Assets and Liabilities (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Supplemental Cash Flow Elements [Abstract]
Accounts receivable and other long-term assets	$ (11,723)	$ 11,024
Derivatives	3,431	0
Inventory	(3,054)	(47)
Prepaids	(301)	2,190
Accounts payable and accrued and other long-term liabilities	971	(6,179)
Taxes receivable and payable	(27,318)	(35,100)
Net changes in assets and liabilities from operating activities	$ (37,994)	$ (28,112)

XML

Supplemental Cash Flow Information - Schedule of Additional Supplemental Cash Flow Disclosures (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Jun. 30, 2017
Supplemental Cash Flow Elements [Abstract]
Net liabilities related to property, plant and equipment, end of period	$ 62,009	$ 56,044