GRAN TIERRA ENERGY INC. - FORM 10-Q

Attached files

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EX-32.1 - EXHIBIT 32.1 - GRAN TIERRA ENERGY INC.	gte-20180331xex321.htm
EX-31.2 - EXHIBIT 31.2 - GRAN TIERRA ENERGY INC.	gte-20180331xex312.htm
EX-31.1 - EXHIBIT 31.1 - GRAN TIERRA ENERGY INC.	gte-20180331xex311.htm

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 March 31, 2018



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 April 27, 2018, the following number of shares of the registrant’s capital stock were outstanding: 385,258,378 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 1,688,889 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 4,078,174 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended March 31, 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	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.	Controls and Procedures	32

PART II	Other Information
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 6.	Exhibits	33
SIGNATURES		35

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.

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 March 31,
	2018			2017
OIL AND NATURAL GAS SALES (NOTES 3 and 7)	$	138,228		$	94,659

EXPENSES
Operating	26,265			23,937
Transportation	6,997			6,942
Depletion, depreciation and accretion (Note 3)	39,461			26,593
Asset impairment	—			283
General and administrative (Note 3)	11,160			8,712
Equity tax	—			1,224
Foreign exchange gain	(942		)	(1,847		)
Financial instruments loss (gain) (Note 10)	6,946			(5,439		)
Interest expense (Note 5)	5,495			3,095
	95,382			63,500

INTEREST INCOME	786			408
INCOME BEFORE INCOME TAXES (NOTE 3)	43,632			31,567

INCOME TAX EXPENSE
Current (Note 8)	12,289			7,417
Deferred (Note 8)	13,482			11,379
	25,771			18,796
NET INCOME AND COMPREHENSIVE INCOME	$	17,861		$	12,771

NET INCOME PER SHARE
- BASIC AND DILUTED	$	0.05		$	0.03
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	391,294,042			399,007,086
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	391,379,013			399,046,114

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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



	As at March 31, 2018			As at December 31, 2017

ASSETS
Current Assets
Cash and cash equivalents (Note 11)	$	160,474		$	12,326
Restricted cash and cash equivalents (Note 11)	3,294			11,787
Accounts receivable	49,239			45,353
Investment (Note 10)	21,265			25,055
Derivatives (Note 10)	3,769			302
Taxes receivable	55,024			40,831
Other current assets	10,952			9,591
Total Current Assets	304,017			145,245

Oil and Gas Properties (using the full cost method of accounting)
Proved	676,520			629,081
Unproved	452,865			464,948
Total Oil and Gas Properties	1,129,385			1,094,029
Other capital assets	4,802			5,195
Total Property, Plant and Equipment (Notes 3 and 4)	1,134,187			1,099,224

Other Long-Term Assets
Deferred tax assets	43,547			57,310
Investment (Note 10)	15,964			19,147
Other long-term assets (Note 11)	6,492			6,112
Goodwill (Note 3)	102,581			102,581
Total Other Long-Term Assets	168,584			185,150
Total Assets (Note 3)	$	1,606,788		$	1,429,619
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	126,756		$	125,876
Derivatives (Note 10)	21,672			21,151
Taxes payable	23,203			9,324
Asset retirement obligation	111			323
Equity compensation award liability (Note 10)	8,633			295
Total Current Liabilities	180,375			156,969

Long-Term Liabilities
Long-term debt (Notes 5 and 10)	397,568			256,542
Deferred tax liabilities	26,467			28,417
Asset retirement obligation	33,405			31,241
Equity compensation award liability (Note 10)	5,724			11,135
Other long-term liabilities	9,610			8,980
Total Long-Term Liabilities	472,774			336,315

Contingencies (Note 9)

Shareholders’ Equity
Common Stock (Note 6) (384,959,730 and 385,191,042 shares of Common Stock and 5,908,065 and 6,111,665 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2018, and December 31, 2017, respectively)	10,295			10,295
Additional paid in capital	1,326,687			1,327,244
Deficit	(383,343		)	(401,204		)
Total Shareholders’ Equity	953,639			936,335
Total Liabilities and Shareholders’ Equity	$	1,606,788		$	1,429,619

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Three Months Ended March 31,
	2018			2017
Operating Activities
Net income	$	17,861		$	12,771
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 3)	39,461			26,593
Asset impairment	—			283
Deferred tax expense	13,482			11,379
Stock-based compensation (Note 6)	3,309			1,203
Amortization of debt issuance costs (Note 5)	670			605
Cash settlement of restricted share units	(120		)	(318		)
Unrealized foreign exchange gain	(1,044		)	(2,819		)
Financial instruments loss (gain) (Note 10)	6,946			(5,439		)
Cash settlement of financial instruments (Note 10)	(5,817		)	768
Cash settlement of asset retirement obligation	(192		)	(13		)
Net change in assets and liabilities from operating activities (Note 11)	(3,464		)	4,930
Net cash provided by operating activities	71,092			49,943

Investing Activities
Additions to property, plant and equipment (Note 3)	(72,694		)	(46,160		)
Deposit received for sale of Brazil business unit	—			3,500
Changes in non-cash investing working capital	1,957			(1,797		)
Net cash used in investing activities	(70,737		)	(44,457		)

Financing Activities
Proceeds from bank debt, net of issuance costs (Note 5)	4,988			18,471
Repayment of bank debt (Note 5)	(153,000		)	(23,000		)
Proceeds exercise of stock options (Note 6)	74			—
Repurchase of shares of Common Stock (Note 6)	(1,194		)	—
Proceeds from issuance of Senior Notes, net of issuance costs (Note 5)	288,368			—
Net cash provided by (used in) financing activities	139,236			(4,529		)

Foreign exchange gain on cash, cash equivalents and restricted cash and cash equivalents	663			474

Net increase in cash, cash equivalents and restricted cash and cash equivalents	140,254			1,431
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)	$	166,932		$	44,698

Supplemental cash flow disclosures (Note 11)

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Three Months Ended March 31,			Three Months Ended March 31,
	2018			2017
Share Capital
Balance, beginning of period	$	10,295		$	10,303
Balance, end of period	10,295			10,303

Additional Paid in Capital
Balance, beginning of period	1,327,244			1,342,656
Exercise of stock options (Note 6)	74			—
Stock-based compensation (Note 6)	563			709
Repurchase of Common Stock (Note 6)	(1,194		)	—
Balance, end of period	1,326,687			1,343,365

Deficit
Balance, beginning of period	(401,204		)	(493,972		)
Net income (loss)	17,861			12,771
Cumulative adjustment for accounting change related to tax reorganizations	—			124,476
Balance, end of period	(383,343		)	(356,725		)

Total Shareholders’ Equity	$	953,639		$	996,943

(See notes to the condensed consolidated financial statements)

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.

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 considered 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 clarifies 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 on the Company’s consolidated financial position, results of operations or cash flows or disclosure.

3. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. Commencing in 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 its Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. The "All Other" category represents the Company’s corporate, Brazil and Peru activities until the date of sale.

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



	Three Months Ended March 31, 2018
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	138,228	$	—		$	138,228
Depletion, depreciation and accretion	38,499		962			39,461
General and administrative expenses	6,809		4,351			11,160
Income (loss) before income taxes	61,151		(17,519		)	43,632
Segment capital expenditures	72,561		133			72,694

	Three Months Ended March 31, 2017
(Thousands of U.S. Dollars)	Colombia		All Other			Total
Oil and natural gas sales	$	90,464	$	4,195		$	94,659
Depletion, depreciation and accretion	24,935		1,658			26,593
General and administrative expenses	4,832		3,880			8,712
Income (loss) before income taxes	37,144		(5,577		)	31,567
Segment capital expenditures	42,840		3,320			46,160



	As at March 31, 2018
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,132,626	$	1,561	$	1,134,187
Goodwill	102,581		—		102,581
All other assets	182,440		187,580		370,020
Total Assets	$	1,417,647	$	189,141	$	1,606,788

	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

4. Property, Plant and Equipment



(Thousands of U.S. Dollars)	As at March 31, 2018			As at December 31, 2017
Oil and natural gas properties
Proved	$	2,896,700		$	2,810,796
Unproved	452,865			464,948
	3,349,565			3,275,744
Other	23,633			26,401
	3,373,198			3,302,145
Accumulated depletion, depreciation and impairment	(2,239,011		)	(2,202,921		)
	$	1,134,187		$	1,099,224

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

5. Debt and Debt Issuance Costs

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



(Thousands of U.S. Dollars)	As at March 31, 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	(17,432		)	(6,458		)
Long-term debt	$	397,568		$	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 $288.4 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 March 31,
(Thousands of U.S. Dollars)	2018		2017
Contractual interest and other financing expenses	$	4,825	$	2,490
Amortization of debt issuance costs	670		605
	$	5,495	$	3,095

6. Share Capital

The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as Common Stock, par value $0.001 per share, 25 million are designated as Preferred Stock, par value $0.001 per share, one share is designated as Special A Voting Stock, par value $0.001 per share, and one share is designated as Special B Voting Stock, par value $0.001 per share.



	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	30,000		—		—
Shares repurchased and canceled	(464,912	)	—		—
Exchange of exchangeable shares	203,600		(203,600	)	—
Balance, March 31, 2018	384,959,730		4,219,176		1,688,889

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 three months ended March 31, 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	3,305,486		67,926	—		1,890,413		2.47
Exercised	—		—	(48,600	)	(30,000	)	(2.46	)
Forfeited	(108,195	)	—	(1,822	)	(349,878	)	(5.17	)
Expired	—		—	—		(8,334	)	(3.50	)
Balance, March 31, 2018	9,329,242		523,694	71,668		10,462,893		3.39

Stock-based compensation expense for the three months ended March 31, 2018, was $3.3 million and was primarily recorded in general and administrative ("G&A") expenses (three months ended March 31, 2017 - $1.2 million).

At March 31, 2018, there was $22.0 million (December 31, 2017 - $13.7 million) of unrecognized compensation cost related to unvested PSUs, RSUs and stock options which is expected to be recognized over a weighted average period of 2.0 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 March 31,
	2018		2017
Weighted average number of common and exchangeable shares outstanding	391,294,042		399,007,086
Shares issuable pursuant to stock options	867,427		635,484
Shares assumed to be purchased from proceeds of stock options	(782,456	)	(596,456	)
Weighted average number of diluted common and exchangeable shares outstanding	391,379,013		399,046,114

For the three months ended March 31, 2018, 8,599,422 options, on a weighted average basis, (three months ended March 31, 2017 - 9,210,869 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 anti-dilutive and excluded from the diluted income per share calculation.

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 quality each month. For the three months ended March 31, 2018, 100% (three months ended March 31, 2017 - 100%) of the Company's revenue resulted from oil sales. In the three months ended March 31, 2018, quality and transportation discounts were 16% of the ICE Brent price (three months ended March 31, 2017 - 22%). During the three months ended March 31, 2018, the Company's production was sold primarily to four major customers in Colombia (three months ended March 31, 2017 - three).

As at March 31, 2018, accounts receivable included $7.1 million of accrued sales revenue which related to March 2018 production (December 31, 2017 - $11.1 million which related to December 31, 2017 production). December 31, 2017 accrued sales revenue was collected during the three months ended March 31, 2018 without significant adjustment to revenue for that period.

8. Taxes

The Company's effective tax rate was 59% in the three months ended March 31, 2018, compared with 60% in the comparable period in 2017. Current income tax expense was higher in the three months ended March 31, 2018, compared with the corresponding period in 2017, primarily as a result of higher taxable income in Colombia. The deferred income tax expense of $13.5 million for the three months ended March 31, 2018, was primarily due to excess tax depreciation compared with accounting depreciation in Colombia.

For the three months ended March 31, 2018, the difference between the effective tax rate of 59% and the 21% U.S. statutory rate was primarily due to an increase to the impact of foreign taxes, valuation allowance, other permanent differences, non-deductible third party royalty in Colombia, stock based compensation, other local taxes and foreign currency translation.

For the comparable period in 2017, the effective rate differed from the U.S. statutory rate of 35% primarily due to an increase to 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 taxes, local taxes, and stock-based compensation. These items were partially offset by foreign currency translation adjustments and other permanent differences.

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 $51.8 million as at March 31, 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 March 31, 2018, the Company had provided letters of credit and other credit support totaling $76.5 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 March 31, 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 award (PSU, DSU and RSU) 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 Sterling Resources Ltd. ("Sterling") was estimated using quoted prices at March 31, 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 Sterling'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 and RSU liabilities were estimated based on quoted market prices in an active market.

The fair value of derivatives and RSU, PSU and DSU liabilities at March 31, 2018, and December 31, 2017, were as follows:



(Thousands of U.S. Dollars)	As at March 31, 2018		As at December 31, 2017
Investment - current and long-term assets	$	37,229	$	44,202
Foreign currency derivative asset	3,769		302
	$	40,998	$	44,504

Commodity price derivative liability	$	21,672	$	21,151
Equity compensation award liability - current and long-term	14,357		11,430
	$	36,029	$	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 March 31,
(Thousands of U.S. Dollars)	2018			2017
Commodity price derivative loss (gain)	$	4,995		$	(4,703	)
Foreign currency derivatives gain	(3,970		)	(736		)
Investment loss	5,921			—
Financial instruments loss (gain)	$	6,946		$	(5,439	)

These gains and losses are presented as financial instrument gains and losses in the interim unaudited condensed consolidated statements of operations and cash flows.

Investment loss for the three months ended March 31, 2018 related to the fair value loss on the Sterling shares Gran Tierra received or subscribed for in connection with the sale of its Peru business unit in December 2017. For the three months ended March 31, 2018, this investment loss was unrealized.

Financial instruments not recorded at fair value include the Senior Notes and the Convertible Notes. At March 31, 2018, the carrying amounts of the Senior Notes and the Convertible Notes were $288.5 million and $111.2 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $292.5 million and $130.0 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 March 31, 2018, the fair value of the current portion of the investment, DSU and RSU 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:



	Three Months Ended			Year Ended
	March 31, 2018			December 31, 2017
(Thousands of U.S. Dollars)
Opening balance	$	19,147		$	—
Acquisition	—			19,091
Unrealized valuation (loss) gain	(2,703		)	56
Unrealized foreign exchange loss	(480		)	—
Closing balance	$	15,964		$	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 March 31, 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: April 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: April 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

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 March 31, 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: April 1, 2018 to December 31, 2018	130,500	46,935	COP	3,000	3,107

⁽¹⁾At March 31, 2018 foreign exchange rate.

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 March 31,				As at December 31,
	2018		2017		2017		2016
Cash and cash equivalents	$	160,474	$	26,716	$	12,326	$	25,175
Restricted cash and cash equivalents - current	3,294		7,663		11,787		8,322
Restricted cash and cash equivalents - long-term (included in other long-term assets)	3,164		10,319		2,565		9,770
	$	166,932	$	44,698	$	26,678	$	43,267

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



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2018			2017
Accounts receivable and other long-term assets	$	(1,982	)	$	(2,428	)
Derivatives	1,847			—
Inventory	(1,785		)	207
Prepaids	1,498			1,078
Accounts payable and accrued and other long-term liabilities	(2,495		)	4,310
Taxes receivable and payable	(547		)	1,763
Net changes in assets and liabilities from operating activities	$	(3,464	)	$	4,930

The following table provides additional supplemental cash flow disclosures:



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2018		2017
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	70,108	$	54,875

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 first quarter of 2018⁽¹⁾


•	Working interest production before royalties was 35,075 BOEPD, 23% higher compared with 28,481 BOEPD in the first quarter of 2017.


•	Production net after royalty ("NAR") was 28,189 BOEPD, 19% higher than the first quarter of 2017. We increased production NAR largely because of production from development activities in the Acordionero Field.


•	Oil and natural gas sales volumes were 27,203 BOEPD, 15% higher than the first quarter of 2017.


•	Net income was $17.9 million compared with $12.8 million in the first quarter of 2017.


•	Funds flow from operations⁽³⁾ increased by 66% to $74.7 million compared with the first quarter of 2017.


•	Oil and gas sales per BOE were $56.46, 33% higher than the first quarter of 2017. Brent price increased 23% compared with the first quarter of 2017.


•	Operating netback⁽³⁾ per BOE was $42.87 per BOE, 51% higher compared with the first quarter of 2017.


•	Operating expenses per BOE were $10.73 per BOE, which was comparable with the first quarter of 2017.


•	Transportation expenses per BOE were $2.86 per BOE, 10% lower compared with the first quarter of 2017. The decrease was due to a higher percentage of volumes sold at the wellhead and the increased use of transportation routes that had lower costs than the routes used in the first quarter of 2017.


•	General and administrative ("G&A") expenses before stock-based compensation per BOE decreased by 4% to $3.26 per BOE compared with the first quarter of 2017.

⁽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.



(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended December 31,			Three Months Ended March 31,
	2017			2018			2017			% Change
Average Daily Volumes (BOEPD)
Consolidated
Working Interest Production Before Royalties	34,477			35,075			29,879			17
Royalties	(6,114		)	(6,886		)	(5,089		)	35
Production NAR	28,363			28,189			24,790			14
(Increase) Decrease in Inventory	(194		)	(986		)	18			—
Sales⁽²⁾	28,169			27,203			24,808			10

Colombia
Working Interest Production Before Royalties	34,477			35,075			28,481			23
Royalties	(6,114		)	(6,886		)	(4,868		)	41
Production NAR	28,363			28,189			23,613			19
(Increase) Decrease in Inventory	(194		)	(986		)	7			—
Sales⁽²⁾	28,169			27,203			23,620			15

Net Income (Loss)	$	(40,802	)	$	17,861		$	12,771		40

Operating Netback
Oil and Natural Gas Sales	$	127,179		$	138,228		$	94,659		46
Operating Expenses	(31,403		)	(26,265		)	(23,937		)	10
Transportation Expenses	(5,635		)	(6,997		)	(6,942		)	1
Operating Netback⁽³⁾	$	90,141		$	104,966		$	63,780		65

G&A Expenses Before Stock-Based Compensation, Gross	$	7,637		$	7,982		$	7,563		6
G&A Stock-Based Compensation	4,501			3,178			1,149			177
General and Administrative ("G&A") Expenses, Including Stock-Based Compensation	$	12,138		$	11,160		$	8,712		28

EBITDA⁽³⁾	$	20,123		$	88,588		$	61,255		45

Adjusted EBITDA⁽³⁾	$	78,180		$	88,775		$	55,020		61

Funds Flow From Operations⁽³⁾	$	69,123		$	74,748		$	45,026		66

Capital Expenditures	$	75,322		$	72,694		$	46,160		57



	As at
(Thousands of U.S. Dollars)	March 31, 2018		December 31, 2017		% Change
Cash and Cash Equivalents	$	160,474	$	12,326	—

Revolving Credit Facility	$	—	$	148,000	(100	)

Senior Notes	$	300,000	$	—	—

Convertible Notes	$	115,000	$	115,000	—

⁽²⁾Sales volumes represent production NAR adjusted for inventory changes.

⁽³⁾Non-GAAP measures

Operating netback, adjusted 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 recovery or expense. Adjusted EBITDA is EBITDA adjusted for asset impairment, unrealized financial instruments loss or gain, loss on sale of business units and foreign exchange gains or losses. Management uses these supplemental measures 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 these financial measures are useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net loss to EBITDA and adjusted EBITDA is as follows:



	Three Months Ended December 31,			Three Months Ended March 31,
(Thousands of U.S. Dollars)	2017			2018			2017
Net income (loss)	$	(40,802	)	$	17,861		$	12,771
Adjustments to reconcile net income (loss) to EBITDA and adjusted EBITDA
DD&A expenses	38,606			39,461			26,593
Interest expense	3,467			5,495			3,095
Income tax expense	18,852			25,771			18,796
EBITDA (non-GAAP)	20,123			88,588			61,255
Asset impairment	275			—			283
Unrealized financial instruments loss (gain)	21,185			1,129			(4,671		)
Loss on sale of business units	35,309			—			—
Foreign exchange loss (gain)	1,288			(942		)	(1,847		)
Adjusted EBITDA (non-GAAP)	$	78,180		$	88,775		$	55,020

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, asset impairment, deferred tax expense or recovery, 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 of business units. 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:



	Three Months Ended December 31,			Three Months Ended March 31,
(Thousands of U.S. Dollars)	2017			2018			2017
Net income (loss)	$	(40,802	)	17,861			$	12,771
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses	38,606			39,461			26,593
Asset impairment	275			—			283
Deferred tax expense	8,052			13,482			11,379
Stock-based compensation expense	4,840			3,309			1,203
Amortization of debt issuance costs	547			670			605
Cash settlement of RSUs	(30		)	(120		)	(318		)
Unrealized foreign exchange loss (gain)	1,141			(1,044		)	(2,819		)
Financial instruments loss (gain)	21,140			6,946			(5,439		)
Cash settlement of financial instruments	45			(5,817		)	768
Loss on sale of business units	35,309			—			—
Funds flow from operations (non-GAAP)	$	69,123		$	74,748		$	45,026

Additional Operational Results



	Three Months Ended December 31,			Three Months Ended March 31,
	2017			2018			2017			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	127,179		$	138,228		$	94,659		46
Operating expenses	31,403			26,265			23,937			10
Transportation expenses	5,635			6,997			6,942			1
Operating netback⁽¹⁾	90,141			104,966			63,780			65

DD&A expenses	38,606			39,461			26,593			48
Asset impairment	275			—			283			(100	)
G&A expenses before stock-based compensation	7,637			7,982			7,563			6
G&A stock-based compensation expense	4,501			3,178			1,149			177
Severance expenses	123			—			—			—
Equity tax	—			—			1,224			(100	)
Foreign exchange loss (gain)	1,288			(942		)	(1,847		)	49
Financial instruments loss (gain)	21,140			6,946			(5,439		)	228
Interest expense	3,467			5,495			3,095			78
	77,037			62,120			32,621			90

Loss on sale of business units	(35,309		)	—			—			—
Interest income	255			786			408			93

(Loss) income before income taxes	(21,950		)	43,632			31,567			38

Current income tax expense	10,800			12,289			7,417			66
Deferred income tax expense	8,052			13,482			11,379			18
	18,852			25,771			18,796			37
Net income (loss)	$	(40,802	)	$	17,861		$	12,771		40

Sales Volumes (NAR)
Total sales volumes, BOEPD	28,169			27,203			24,808			10

Average Prices
Oil and NGL's per bbl	$	49.37		$	56.63		$	42.96		32
Natural gas per Mcf	$	1.88		$	2.91		$	1.52		91

Brent Price per bbl	$	61.54		$	67.18		$	54.66		23

Consolidated Results of Operations per BOE Sales Volumes NAR
Oil and natural gas sales	$	49.07		$	56.46		$	42.40		33
Operating expenses	12.12			10.73			10.72			—
Transportation expenses	2.17			2.86			3.11			(8	)
Operating netback⁽¹⁾	34.78			42.87			28.57			50




DD&A expenses	14.90			16.12			11.91			35
Asset impairment	0.11			—			0.13			(100	)
G&A expenses before stock-based compensation	2.95			3.26			3.39			(4	)
G&A stock-based compensation expense	1.74			1.30			0.51			155
Severance expenses	0.05			—			—			—
Equity tax	—			—			0.55			(100	)
Foreign exchange loss (gain)	0.50			(0.38		)	(0.83		)	54
Financial instruments loss (gain)	8.16			2.84			(2.44		)	216
Interest expense	1.34			2.24			1.39			61
	29.75			25.38			14.61			74

Loss on sale of business units	(13.62		)	—			—			—
Interest income	0.10			0.32			0.18			78

(Loss) income before income taxes	(8.49		)	17.81			14.14			26
Current income tax expense	4.17			5.02			3.32			51
Deferred income tax expense	3.11			5.51			5.10			8
	7.28			10.53			8.42			25
Net income (loss)	$	(15.77	)	$	7.28		$	5.72		27

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

Oil and Gas Production and Sales Volumes, BOEPD



	Three Months Ended March 31, 2018						Three Months Ended March 31, 2017
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	35,075		—		35,075		28,481		1,398		29,879
Royalties	(6,886	)	—		(6,886	)	(4,868	)	(221	)	(5,089	)
Production NAR	28,189		—		28,189		23,613		1,177		24,790
(Increase) Decrease in Inventory	(986	)	—		(986	)	7		11		18
Sales	27,203		—		27,203		23,620		1,188		24,808

Royalties, % of Working Interest Production Before Royalties	20	%	—	%	20	%	17	%	16	%	17	%

Oil and gas production NAR for the three months ended March 31, 2018 increased by 14% to 28,189 BOEPD, compared with 24,790 BOEPD in the comparable period of 2017. Colombian NAR production for the three months ended March 31, 2018 increased 19% compared with the comparable period of 2017. We increased oil and gas production NAR as a result of successful drilling and a workover campaign in the Acordionero Field, the Vonu-1 exploration well and a workover campaign in the Cumplidor Field in Colombia. Working interest production before royalties from the Acordionero Field averaged 16,751 bopd before royalties during the three months ended March 31, 2018 compared with 6,198 bopd in the comparative period of 2017, a 170% increase.

Royalties as a percentage of production for the three months ended March 31, 2018 increased compared with the comparative period in the prior year commensurate with the increase in oil prices due to price sensitive royalties payable in Colombia, higher API in the Acordionero Field and Acordionero reaching the threshold for the High Price Royalties.

Operating Netbacks



	Three Months Ended March 31, 2018								Three Months Ended March 31, 2017
(Thousands of U.S. Dollars)	Colombia			Brazil		Total			Colombia			Brazil			Total
Oil and Natural Gas Sales	$	138,228		$	—	$	138,228		$	90,464		$	4,195		$	94,659
Transportation Expenses	(6,997		)	—		(6,997		)	(6,765		)	(177		)	(6,942		)
	131,231			—		131,231			83,699			4,018			87,717
Operating Expenses	(26,265		)	—		(26,265		)	(23,156		)	(781		)	(23,937		)
Operating Netback⁽¹⁾	$	104,966		$	—	$	104,966		$	60,543		$	3,237		$	63,780

U.S. Dollars Per BOE Sales Volumes NAR
Brent	$	67.18		$	—	$	67.18		$	54.66		$	54.66		$	54.66
Quality and Transportation Discounts	(10.72		)	—		(10.72		)	(12.11		)	(15.42		)	(12.26		)
Average Realized Price	56.46			—		56.46			42.55			39.24			42.40
Transportation Expenses	(2.86		)	—		(2.86		)	(3.18		)	(1.66		)	(3.11		)
Average Realized Price Net of Transportation Expenses	53.60			—		53.60			39.37			37.58			39.29
Operating Expenses	(10.73		)	—		(10.73		)	(10.89		)	(7.31		)	(10.72		)
Operating Netback⁽¹⁾	$	42.87		$	—	$	42.87		$	28.48		$	30.27		$	28.57

⁽¹⁾Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to non-GAAP measures disclosure above regarding this measure.

Oil and gas sales for the three months ended March 31, 2018, increased by 46% to $138.2 million from $94.7 million, in the comparable period of 2017 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 months ended March 31, 2018 compared with the prior quarter and the comparative period in 2017:



	First Quarter 2018 Compared with Fourth Quarter 2017			First Quarter 2018 Compared with First Quarter 2017
Oil and natural gas sales for the comparative period	$	127,179		$	94,659
Realized sales price increase effect	18,078			34,426
Sales volume (decrease) increase effect	(7,029		)	9,143
Oil and natural gas sales for period ended March 31, 2018	$	138,228		$	138,228

Average realized prices for the three months ended March 31, 2018, increased by 33% commensurate with the increase in benchmark oil prices and lower transportation and quality discounts compared with the comparable period of 2017. Average Brent oil prices for the three months ended March 31, 2018, increased by 23% compared with the comparable period of 2017.

Oil and gas sales for the three months ended March 31, 2018, increased by 9% to $138.2 million from $127.2 million compared with the prior quarter due to higher realized oil prices, partially offset by lower sales volumes. Lower sales volumes were the net result of higher working interest production before royalties being more than offset by an increase in inventory and higher price sensitive royalties as a result of increased Brent prices. Average realized prices increased by 15% to $56.46 per BOE for the three months ended March 31, 2018, compared with $49.07 per BOE in the prior quarter. Average Brent oil prices for the three months ended March 31, 2018, increased by 9% to $67.18 per bbl, compared with $61.54 per bbl in the prior quarter.

We have options to sell our oil though 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 months ended March 31, 2018 and 2017 and the prior quarter:



	Three Months Ended December 31,		Three Months Ended March 31,
	2017		2018		2017
Volume transported through pipeline	10	%	9	%	25	%
Volume sold at wellhead	47	%	52	%	50	%
Volume sold not at wellhead, trucking	43	%	39	%	25	%
	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 months ended March 31, 2018, increased by 1% to $7.0 million compared with the corresponding period in 2017. On a per BOE basis, transportation expenses decreased by 8% to $2.86 from $3.11 in the corresponding period in 2017.

Colombian transportation expenses for the three months ended March 31, 2018 on a per BOE basis, decreased by 10% to $2.86 per from $3.18 in the corresponding period in 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.

Total Company transportation expenses for the three months ended March 31, 2018 increased 24% to $7.0 million compared with $5.6 million in the prior quarter. On a per BOE basis, transportation expenses increased by 32% to $2.86 from $2.17 in the prior quarter. The increase was primarily due to the use of alternative transportation routes, which had higher costs per BOE.

The quarterly increase in Colombia transportation expenses was more than offset by a decrease in quality and transportation discounts. On a per BOE basis, quality and transportation discounts decreased by 14% to $10.72 from $12.47 in the prior quarter, a reduction which resulted from optimization of transportation routes and narrowing of differentials.

The following table shows the variance in our average realized prices net of transportation expenses in Colombia for the three months ended March 31, 2018 compared with the prior quarter and the comparative period in 2017:



U.S. Dollars Per BOE Sales Volumes NAR	First Quarter 2018 Compared with Fourth Quarter 2017			First Quarter 2018 Compared with First Quarter 2017
Average realized price net of transportation expenses for the comparative period	$	46.90		$	39.37
Increase in benchmark prices	5.64			$	12.52
Decrease in quality and transportation discounts	1.75			1.39
(Increase) decrease in transportation expenses	(0.69		)	0.32
Average realized price net of transportation expenses for the period ended March 31, 2018	$	53.60		$	53.60

Total Company operating expenses for the three months ended March 31, 2018 increased by 10% to $26.3 million compared with the corresponding period in 2017. The increase was due to higher sales volumes and the increased operating costs per BOE.

On a per BOE basis, Colombian operating expenses decreased by $0.16 and workover expenses decreased by $0.65 compared with the corresponding period in 2017. Excluding workover expenses, Colombia operating expenses increased by $0.49 per BOE primarily as a result of power disruption costs in the Putumayo region as a result of Mocoa natural disaster, the NaturAmazonas reforestation and conservation program and water injection activities conducted in the Acordionero Field during the first quarter of 2018.

Total Company operating expenses for the three months ended March 31, 2018 decreased by 16% to $26.3 million compared with the prior quarter. On a per BOE basis, operating expenses decreased by $1.39 to $10.73 for the three months ended March 31, 2018, from $12.12 in the prior quarter and workover expenses increased by $0.25. Excluding workover expenses, operating expenses decreased by $1.64 per BOE compared with the prior quarter primarily as a result of lower slickline testing service and maintenance activity in the quarter.

DD&A Expenses



	Three Months Ended March 31, 2018				Three Months Ended March 31, 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	$	38,499	$	15.72	$	24,935	$	11.73
Brazil	—		—		1,213		11.35
Peru	—		—		226		—
Corporate	962		—		219		—
	$	39,461	$	16.12	$	26,593	$	11.91

DD&A expenses for the three months ended March 31, 2018, increased to $39.5 million ($16.12 per BOE) from $26.6 million ($11.91 per BOE) in the comparable period 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 8% to $16.12 per BOE for the three months ended March 31, 2018, from $14.90 per BOE in the prior quarter due to higher costs in the depletable base.

G&A Expenses



	Three Months Ended December 31,		Three Months Ended March 31,
(Thousands of U.S. Dollars)	2017		2018		2017		% Change
G&A Expenses Before Stock-Based Compensation	$	7,637	$	7,982	$	7,563	6
G&A Stock-Based Compensation	4,501		3,178		1,149		177
G&A Expenses, Including Stock-Based Compensation	$	12,138	$	11,160	$	8,712	28

U.S. Dollars Per BOE Sales Volumes NAR
G&A Expenses Before Stock-Based Compensation	$	2.95	$	3.26	$	3.39	(4	)
G&A Stock-Based Compensation	1.74		1.30		0.51		155
G&A Expenses, Including Stock-Based Compensation	$	4.69	$	4.56	$	3.90	17

G&A expenses for the three months ended March 31, 2018, decreased by 8% to $11.2 million compared with $12.1 million in the prior quarter primarily due to lower stock-based compensation.

For the three months ended March 31, 2018, G&A expenses before stock-based compensation increased by 6% from the corresponding period in 2017. The increase was commensurate with our growth and activity. On a per BOE basis, G&A expenses decreased 4% from the comparative period. After stock-based compensation, G&A expenses for the three months ended March 31, 2018 increased by 28% to $11.2 million from $8.7 million in the corresponding period in 2017. The increase was mainly due to the increase in G&A Stock-Based Compensation resulting from additional PSUs outstanding and higher share price at March 31, 2018.

Foreign Exchange Gains and Losses

For the three months ended March 31, 2018, we had foreign exchange gains of $0.9 million, compared to $1.8 million in the corresponding period in 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. The following table presents the change in the U.S. dollar against the Colombian peso for the three months ended March 31, 2018, and 2017:



	Three Months Ended March 31,
	2018	2017
Change in the U.S. dollar against the Colombian peso	weakened by	weakened by
Change in the U.S. dollar against the Colombian peso	7%	4%

Financial Instrument Gains and Losses

The following table presents the nature of our financial instruments gains and losses for the three months ended March 31, 2018, and 2017:



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2018			2017
Commodity price derivative loss (gain)	$	4,995		$	(4,703	)
Foreign currency derivatives gain	(3,970		)	(736		)
Investment loss	5,921			—
	$	6,946		$	(5,439	)

Income Tax Expense and Recovery



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2018			2017
Income before income tax	$	43,632		$	31,567

Current income tax expense	$	12,289		$	7,417
Deferred income tax expense	13,482			11,379
Total income tax expense	$	25,771		$	18,796

Effective tax rate	59		%	60		%

Current income tax expense was higher in the three months ended March 31, 2018, compared with the corresponding period in 2017 as a result of higher taxable income in Colombia. The deferred income tax expense of $13.5 million for the three months ended March 31, 2018, was primarily due to excess tax depreciation as compared with accounting depreciation in Colombia.

For the three months ended March 31, 2017, the difference between the effective tax rate of 60% and the 35% U.S. statutory rate was 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 taxes, local taxes, and stock based compensation. These items were partially offset by foreign currency translation adjustments and other permanent differences.

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



(Thousands of U.S. Dollars)	First Quarter 2018 Compared with Fourth Quarter 2017			% change		First Quarter 2018 Compared with First Quarter 2017			% change
Net income (loss) for the comparative period	$	(40,802	)			$	12,771
Increase (decrease) due to:
Prices	18,078					34,426
Sales volumes	(7,029		)			9,143
Expenses:
Operating	5,138					(2,328		)
Transportation	(1,362		)			(55		)
Cash G&A and RSU settlements, excluding stock-based compensation expense	(643		)			(144		)
Severance	123					—
Interest, net of amortization of debt issuance costs	(1,905		)			(2,335		)
Realized foreign exchange	44					869
Settlement of financial instruments	(5,862		)			(6,585		)
Current taxes	(1,489		)			(4,872		)
Equity tax	—					1,224
Other	532					379
Net change in funds flow from operations⁽¹⁾ from comparative period	5,625					29,722
Expenses:
Depletion, depreciation and accretion	(855		)			(12,868		)
Asset impairment	275					283
Deferred tax	(5,430		)			(2,103		)
Amortization of debt issuance costs	(123		)			(65		)
Stock-based compensation, net of RSU settlement	1,621					(2,304		)
Financial instruments gain or loss, net of financial instruments settlements	20,056					(5,800		)
Unrealized foreign exchange	2,185					(1,775		)
Loss on sale of business units	35,309					—
Net change in net income or loss	58,663					5,090
Net income for the current period	$	17,861		144	%	$	17,861		40	%

⁽¹⁾Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to non-GAAP measures disclosure above regarding this measure.

2018 Capital Program

Colombia remains our focus and represents 100% of the 2018 capital program. We have increased the 2018 facilities capital program by $25 million; $5 million related to the acceleration of facilities expansion in Acordionero to support the better than expected production results to date and $20 million allocated to Gran Tierra owned gas-to-power projects. The gas-to-power projects include $17 million for the construction of a 22 megawatt gas-to-power facilities in Acordionero and $3 million for remote power generation capacity in the Putumayo Basin. These Gran Tierra owned facilities are designed to improve the reliability of power generation and will support production consistency, water injection reliability and reduce costly artificial lift failures caused by power interruptions. In addition, we expect to save $8 to $10 million per year in operating costs in Acordionero as a result of these projects.

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	19-21	18-20	$100-105
Exploration	8-11	7-10	80-90
Facilities	—	—	75-80
Seismic and Studies	—	—	20
	27-32	25-30	$275-295

Based on the midpoint of the guidance, the capital budget is forecasted to be approximately 65% directed to development and 35% to exploration. Between 40% and 45% 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 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 March 31, 2018, were $72.7 million:



(Thousands of U.S. Dollars)
Colombia:
Exploration	$	19,234
Development:
Facilities	11,002
Drilling and Completions	35,498
Other	6,827
	72,561
Corporate	133
	$	72,694

During the three months ended March 31, 2018, we drilled the following wells in Colombia:



	Number of wells (Gross)	Number of wells (Net)
Development	5	4.2
Exploration	1	1.0
Total Colombia	6	5.2

The Ayombero-1 well, which was in-progress at December 31, 2017, was brought on production during the first quarter of 2018. We spud an exploration well in the Midas Block (Totumillo-1), which was in-progress as of March 31, 2018. These wells are targeting the conversion of prospective resources to reserves.

Development wells were spud in the Chaza Block (Costayaco-31 and 32), the Midas Block (Acordionero-6 and 22) and the Suroriente Block (Cohembi-16), with two of these wells are currently on production (Costayaco-31 and Acordionero-6). Acordionero-20, which was in-progress as of December 31, 2017, was brought on production during the first quarter of 2018.

We also continued facilities work at the Acordionero Field on the Midas Block and the Moqueta and Costayaco Fields on the Chaza Block. The Acordionero facilities expansion has been accelerated due to better than expected results to date and is designed to handle 30,000 bopd.

Liquidity and Capital Resources



	As at
(Thousands of U.S. Dollars)	March 31, 2018		% Change		December 31, 2017
Cash and Cash Equivalents	$	160,474	—		$	12,326

Current Restricted Cash and Cash Equivalents	$	3,294	(72	)	$	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.

On February 15, 2018, through our indirect wholly owned subsidiary, Gran Tierra Energy International Holdings Ltd., we issued $300 million aggregate principal amount of Senior Notes. 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. The net proceeds of the Senior Notes were used to repay the outstanding amount on the revolving credit facility, with the remainder for general corporate purposes.

At March 31, 2018, we had a revolving credit facility with a syndicate of lenders with a borrowing base of $300 million. At March 31, 2018 we had zero drawn on our 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 May 2018.

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 the these agreements). As at March 31, 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.

At March 31, 2018, we had $115 million aggregate principal amount of 5.00% Convertible Senior Notes due 2021 (the "Convertible Notes") outstanding. The Convertible Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year. 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.

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

At March 31, 2018, 97% 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.

Derivative Positions

At March 31, 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: April 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: April 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

At March 31, 2018, current liabilities on our balance sheet included $21.7 million in relation to the above outstanding commodity price derivative positions

At March 31, 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: April 1, 2018 to December 31, 2018	130,500	46,935	COP	3,000	3,107

⁽¹⁾At March 31, 2018 foreign exchange rate.

At March 31, 2018, current assets on our balance sheet included $3.8 million in relation to the above outstanding foreign currency derivative positions

Cash Flows

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



	Three Months Ended March 31,
	2018			2017
Sources of cash and cash equivalents:
Net income	$	17,861		$	12,771
Adjustments to reconcile net income to funds flow from operations
DD&A expenses	39,461			26,593
Asset impairment	—			283
Deferred tax expense	13,482			11,379
Stock-based compensation expense	3,309			1,203
Amortization of debt issuance costs	670			605
Cash settlement of RSUs	(120		)	(318		)
Unrealized foreign exchange loss (gain)	(1,044		)	(2,819		)
Financial instruments loss (gain)	6,946			(5,439		)
Cash settlement of financial instruments	(5,817		)	768
Funds flow from operations⁽¹⁾	74,748			45,026
Proceeds from bank debt, net of issuance costs	4,988			18,471
Proceeds from issuance of Senior Notes, net of issuance costs	288,368			—
Changes in non-cash investing working capital	1,957			—
Proceeds from issuance of shares	74			—
Net changes in assets and liabilities from operating activities	—			4,930
Deposit received for sale of Brazil business unit	—			3,500
Foreign exchange gain on cash, cash equivalents and restricted cash and cash equivalents	663			474
	370,798			72,401

Uses of cash and cash equivalents:
Additions to property, plant and equipment	(72,694		)	(46,160		)
Repayment of bank debt	(153,000		)	(23,000		)
Repurchase of shares of Common Stock	(1,194		)	—
Net changes in assets and liabilities from operating activities	(3,464		)	—
Changes in non-cash investing working capital	—			(1,797		)
Settlement of asset retirement obligations	(192		)	(13		)
	(230,544		)	(70,970		)
Net increase in cash and cash equivalents and restricted cash and cash equivalents	$	140,254		$	1,431

(1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operating 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 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 March 31, 2018, we had no off-balance sheet arrangements.

Contractual Obligations

During the three months ended March 31, 2018, we fully repaid the balance of $153.0 million outstanding under our revolving credit facility, which remained undrawn at March 31, 2018.

During February 2018, we issued $300 million aggregate principal amount of 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.

Except as noted above, as at March 31, 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 modified retrospective approach. Apart from 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 arrangement with third parties and partners to determine if we acted 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.

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 March 31, 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 March 31, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 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.

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
January 1-31, 2018	—	—	—	11,835,982	⁽³	⁾
February 1-28, 2018	—	—	—	11,835,982	⁽³	⁾
March 1- 31, 2018	464,912	2.57	464,912	18,804,820	⁽⁴	⁾
	464,912	2.57	464,912	18,804,820

⁽¹⁾ Based on settlement date.

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

⁽³⁾ On January 30, 2017, we announced that we intended to implement a share repurchase program or normal course issuer bid (the “2017 Program”) through the facilities of the TSX, the NYSE American and eligible alternative trading platforms in Canada and the United States. We received regulatory approval from the TSX to commence the 2017 Program on February 6, 2017. We were able to purchase at prevailing market prices up to 19,540,359 shares of Common Stock, representing approximately 5.00% of our issued and outstanding shares of Common Stock as of January 27, 2017. The 2017 Program expired on February 7, 2018, at which time 7,704,377 million shares had been repurchased at a weighted average price per share of $2.33.

⁽⁴⁾ 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.

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).

4.1	Details of the Goldstrike Special Voting Share.	Incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005, and filed with the SEC on April 21, 2006 (SEC File No. 333-111656).

4.2	Goldstrike Exchangeable Share Provisions.	Incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the SEC on April 21, 2006 (SEC File No. 333-111656).

4.3	Provisions Attaching to the GTE–Solana Exchangeable Shares.	Incorporated by reference to Annex E to the Proxy Statement on Schedule 14A filed with the SEC on October 14, 2008 (SEC File No. 001-34018).

4.4	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).

4.5	Form of 5.00% Convertible Senior Notes due 2021	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

4.6	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).

4.7	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).

4.8	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).

4.9	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).

4.10	Form of 6.25% Senior Notes due 2025	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).

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.

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: May 1, 2018		/s/ Gary S. Guidry
		By: Gary S. Guidry
		President and Chief Executive Officer
		(Principal Executive Officer)



Date: May 1, 2018		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

Attached files

GRAN TIERRA ENERGY INC. Reports

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