GRAN TIERRA ENERGY INC. - Quarter Report: 2019 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2019



☐		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)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.001 per share	GTE	NYSE American
		Toronto Stock Exchange
		London Stock Exchange

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

Yes ☒ No ☐

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	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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. ☐

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

On August 5, 2019, 380,974,707 shares of the registrant’s Common Stock, $0.001 par value, were issued with 6,516,200 of shares owned by Gran Tierra Energy Inc.

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended June 30, 2019

Table of contents



		Page
PART I	Financial Information
Item 1.	Financial Statements	3
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	30

PART II	Other Information
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 6.	Exhibits	32
SIGNATURES		33

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 and other local conditions; 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; our ability to raise capital; our ability to identify and complete successful acquisitions; our ability to execute business plans; 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; current global economic and credit market conditions may impact oil prices and oil consumption differently 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 2018 Annual Report on Form 10-K, as amended (the "2018 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 June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
OIL AND NATURAL GAS SALES (Note 6)	$	157,993		$	163,446	$	310,558		$	301,674

EXPENSES
Operating	33,733			26,732		68,516			48,508
Workover	12,757			8,327		19,046			12,816
Transportation	4,885			6,522		12,988			13,519
Depletion, depreciation and accretion	51,697			46,607		114,618			86,068
General and administrative	8,641			12,202		18,237			23,362
Severance	270			1,011		942			1,011
Foreign exchange loss (gain)	1,175			2,216		(1,259		)	1,274
Financial instruments (gain) loss (Note 9)	(18,340		)	4,768		(15,175		)	11,714
Interest expense (Note 4)	10,564			7,375		18,502			12,870
	105,382			115,760		236,415			211,142

INTEREST INCOME	397			610		530			1,396
INCOME BEFORE INCOME TAXES	53,008			48,296		74,673			91,928

INCOME TAX EXPENSE
Current (Note 7)	(489		)	4,827		10,874			17,116
Deferred (Note 7)	14,957			23,169		23,280			36,651
	14,468			27,996		34,154			53,767
NET AND COMPREHENSIVE INCOME	$	38,540		$	20,300	$	40,519		$	38,161

NET INCOME PER SHARE
- BASIC	$	0.10		$	0.05	$	0.11		$	0.10
- DILUTED	$	0.10		$	0.05	$	0.10		$	0.10
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)	379,942,355			391,054,204		383,491,798			391,173,460
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)	415,756,748			427,455,092		419,306,907			427,242,014

(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 June 30, 2019			As at December 31, 2018

ASSETS
Current Assets
Cash and cash equivalents (Note 10)	$	147,712		$	51,040
Restricted cash and cash equivalents (Note 10)	699			1,269
Accounts receivable	38,286			26,177
Investment (Note 9)	53,308			32,724
Taxes receivable	87,297			78,259
Other assets	13,268			13,056
Total Current Assets	340,570			202,525

Oil and Gas Properties
Proved	992,187			853,428
Unproved	502,770			456,598
Total Oil and Gas Properties	1,494,957			1,310,026
Other capital assets	5,931			2,751
Total Property, Plant and Equipment	1,500,888			1,312,777

Other Long-Term Assets
Deferred tax assets	46,213			45,437
Investment (Note 9)	6,181			8,711
Taxes receivable	30,814			—
Other	4,581			4,553
Goodwill	102,581			102,581
Total Other Long-Term Assets	190,370			161,282
Total Assets	$	2,031,828		$	1,676,584

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	184,525		$	154,670
Derivatives (Note 9)	413			1,017
Taxes payable	59			4,149
Equity compensation award liability (Note 5)	4,189			9,544
Total Current Liabilities	189,186			169,380

Long-Term Liabilities
Long-term debt (Notes 4 and 9)	692,558			399,415
Deferred tax liabilities	47,053			23,419
Asset retirement obligation	43,974			43,676
Equity compensation award liability (Note 5)	4,397			8,139
Other	7,728			2,805
Total Long-Term Liabilities	795,710			477,454

Contingencies (Note 8)

Shareholders’ Equity
Common Stock (Note 5) (380,974,707 and 387,079,027 shares issued; 376,636,307 and 387,079,027 shares outstanding of Common Stock par value $0.001 per share, as at June 30, 2019, and December 31, 2018, respectively)	10,285			10,290
Additional paid in capital	1,295,106			1,318,048
Deficit	(258,459		)	(298,588		)
Total Shareholders’ Equity	1,046,932			1,029,750
Total Liabilities and Shareholders’ Equity	$	2,031,828		$	1,676,584

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Six Months Ended June 30,
	2019			2018
Operating Activities
Net income	$	40,519		$	38,161
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion	114,618			86,068
Deferred tax expense	23,280			36,651
Stock-based compensation (Note 5)	1,100			10,202
Amortization of debt issuance costs (Note 4)	1,785			1,513
Unrealized foreign exchange (gain) loss	(1,109		)	831
Financial instruments (gain) loss (Note 9)	(15,175		)	11,714
Cash settlement of financial instruments	(1,345		)	(15,483		)
Cash settlement of asset retirement obligation	(510		)	(369		)
Non-cash lease expenses	894			—
Lease payments	(848		)	—
Cash settlement of restricted share units	—			(360		)
Net change in assets and liabilities from operating activities (Note 10)	(70,194		)	(37,994		)
Net cash provided by operating activities	93,015			130,934

Investing Activities
Additions to property, plant and equipment	(194,084		)	(157,088		)
Property acquisitions, net of cash acquired (Note 3)	(77,772		)	(3,100		)
Changes in non-cash investing working capital	11,116			(6,142		)
Net cash used in investing activities	(260,740		)	(166,330		)

Financing Activities
Proceeds from bank debt, net of issuance costs	163,000			4,988
Repayment of bank debt	(163,000		)	(153,000		)
Repurchase of shares of Common Stock (Note 5)	(23,951		)	(1,208		)
Proceeds from exercise of stock options	—			845
Proceeds from issuance of Senior Notes, net of issuance costs	289,117			288,087
Net cash provided by financing activities	265,166			139,712

Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(1,073		)	(69		)

Net increase in cash, cash equivalents and restricted cash and cash equivalents	96,368			104,247
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 10)	54,308			26,678
Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 10)	$	150,676		$	130,925

Supplemental cash flow disclosures (Note 10)

(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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Share Capital
Balance, beginning of period	$	10,287		$	10,295		$	10,290		$	10,295
Issuance of Common Stock	—			—			—			—
Repurchase and cancellation of Common Stock (Note 5)	(2		)	—			(5		)	—
Balance, end of period	10,285			10,295			10,285			10,295

Additional Paid in Capital
Balance, beginning of period	1,312,371			1,326,687			1,318,048			1,327,244
Exercise of stock options	—			771			—			845
Treasury Stock, at cost (Note 5)	(9,267		)	—			(9,267		)	—
Stock-based compensation (Note 5)	529			593			1,003			1,156
Repurchase and cancellation of Common Stock (Note 5)	(8,527		)	(14		)	(14,678		)	(1,208		)
Balance, end of period	1,295,106			1,328,037			1,295,106			1,328,037

Deficit
Balance, beginning of period	(296,999		)	(383,343		)	(298,588		)	(401,204		)
Net income	38,540			20,300			40,519			38,161
Cumulative adjustment for accounting change related to leases (Note 2)	—			—			(390		)	—
Balance, end of period	(258,459		)	(363,043		)	(258,459		)	(363,043		)

Total Shareholders’ Equity	$	1,046,932		$	975,289		$	1,046,932		$	975,289

(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 and Ecuador.

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, 2018, included in the Company’s 2018 Annual Report on Form 10-K.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2018 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

Leases

The Company adopted Accounting Standard Codification ("ASC") 842 Leases with a date of initial application on January 1, 2019 in accordance with the modified retrospective transition approach using the practical expedients available for land easements and short-term leases. The Company did not elect the "suite" of practical expedients or use the hindsight expedient in its adoption.

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At inception of a contract that contains a lease component, the Company allocates the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, and subsequently at cost less any accumulated depreciation and impairment losses, and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.

The Company has applied judgment to determine the lease term for contracts which include renewal or termination options. The assessment of whether the Company is reasonably certain to exercise such options impacts the lease term, which significantly affects the amount of lease liabilities and right-of-use assets recognized.

All leases identified relate to office leases.

The transition resulted in the recognition of a right-of-use asset presented in other capital assets of $3.8 million at January 1, 2019, the recognition of lease liabilities of $4.2 million and a $0.4 million impact on retained earnings. When measuring the lease liabilities, the Company's incremental borrowing rate was used. At January 1, 2019 the rates applied ranged between 5.6% and 9.1%.

3. Property, Plant and Equipment

On February 20, 2019, the Company acquired 36.2% working interest ("WI") in the Suroriente Block and a 100% WI of the Llanos-5 Block for cash consideration of $79.1 million and a promissory note of $1.5 million included in current accounts payable on the Company's condensed consolidated balance sheet. The cost of the assets was allocated to proved properties using relative fair values. The entire consideration of $0.3 million for Llanos-5 was allocated to unproved properties.



(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash	$	79,100
Promissory note	1,500
	$	80,600

Allocation of Consideration Paid:
Oil and gas properties
Proved	$	52,496
Unproved	44,739
	97,235
Net working capital (including cash acquired of $5.3 million)	(16,635		)
	$	80,600

4. Debt and Debt Issuance Costs

The Company's debt at June 30, 2019 and December 31, 2018 was as follows:



(Thousands of U.S. Dollars)	As at June 30, 2019			As at December 31, 2018
6.25% Senior notes	$	300,000		$	300,000
7.75% Senior notes	300,000			—
Convertible notes	115,000			115,000
Unamortized debt issuance costs	(24,683		)	(15,585		)
Long-term debt	690,317			399,415
Long-term lease obligation⁽¹⁾	2,241			—
	$	692,558		$	399,415

⁽¹⁾The current portion of the lease obligation has been included in accounts payable and totaled $2.2 million as at June 30, 2019 (December 31, 2018 - nil).

Senior Notes

On May 20, 2019, the Company, issued $300 million of 7.75% Senior Notes due 2027 (the "7.75% Senior Notes"). The 7.75% Senior Notes are fully and unconditionally guaranteed by certain subsidiaries of the Company that guarantee its revolving credit facility. Net proceeds from the issue of the 7.75% Senior Notes were $289 million, after deducting the initial purchasers' discounts and commission and the offering expenses payable by the Company.

The 7.75% Senior Notes bear interest at a rate of 7.75% per year, payable semi-annually in arrears on May 23 and November 23 of each year, beginning on November 23, 2019. The Senior Notes will mature on May 23, 2027, unless earlier redeemed or repurchased.

Before May 23, 2023, the Company may, at its option, redeem all or a portion of the 7.75% 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 7.75% Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2023 - 103.875%; 2024 - 101.938%; 2025 and thereafter - 100%.

Convertible Notes

On July 17, 2019, pursuant to a previously announced offer to purchase for cash all outstanding Convertible Notes, the Company purchased and canceled $114,997,000 aggregate principal amount of Convertible Notes at a purchase price of $1,075 in cash per $1,000 principal amount of Convertible Notes plus $1.6 million of accrued and unpaid interest outstanding on such Convertible Notes up to, but not excluding the date of purchase. After giving effect to the purchase and cancellation of the Convertible Notes, $3,000 aggregate principal amount of Convertible Notes remain outstanding.

Interest Expense

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



	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019		2018		2019		2018
Contractual interest and other financing expenses	$	9,617	$	6,532	$	16,717	$	11,357
Amortization of debt issuance costs	947		843		1,785		1,513
	$	10,564	$	7,375	$	18,502	$	12,870

5. Share Capital



	Shares of Common Stock
Balance, December 31, 2018	387,079,027
Shares repurchased and canceled	(6,104,320	)
Balance, June 30, 2019	380,974,707

In Q1 2019, the Company implemented a share repurchase program (the “2019 Program”) through the facilities of the Toronto Stock Exchange ("TSX") and eligible alternative trading platforms in Canada. Under the 2019 Program, the Company is able to purchase at prevailing market prices up to 19,353,951 shares of Common Stock, representing approximately 5.00% of the issued and outstanding shares of Common Stock as of March 1, 2019. The 2019 Program will expire on March 12, 2020, or earlier if the 5.00% share maximum is reached.

During the three and six months ended June 30, 2019, the Company repurchased 7,856,425 and 10,442,720 shares at a weighted average prices of $2.27 and $2.29, respectively. Of the shares repurchased, 743,520 shares at a weighted average price of $2.34 were repurchased under 2018 share repurchase program and 4,338,400 shares at a weighted average price of $2.14 have not been canceled by the Company and were designated as treasury stock as at June 30, 2019.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), and stock option activity for the six months ended June 30, 2019:



	PSUs		DSUs	Stock Options
	Number of Outstanding Share Units		Number of Outstanding Share Units	Number of Outstanding Stock Options		Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2018	9,004,661		684,893	9,034,412		3.18
Granted	5,039,365		189,188	2,315,006		2.29
Exercised	(2,725,877	)	—	—		—
Forfeited	(574,010	)	—	(885,956	)	3.89
Expired	—		—	(89,940	)	4.94
Balance, June 30, 2019	10,744,139		874,081	10,373,522		2.90

For the three and six months ended June 30, 2019, stock-based compensation recovery and expense was $0.6 million and $1.1 million, respectively (three and six months ended June 30, 2018 - $6.9 million and $10.2 million, respectively, of expense).

At June 30, 2019, there was $12.3 million (December 31, 2018 - $9.2 million) of unrecognized compensation cost related to unvested PSUs and stock options which is expected to be recognized over a weighted average period of 1.7 years. During the six months ended June 30, 2019, the Company paid out $10.2 million (six months ended June 30, 2018 - nil) for performance share units which were vested December 31, 2018.

Net Income per Share

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

Weighted Average Shares Outstanding



	Three Months Ended June 30,			Six Months Ended June 30,
	2019	2018		2019		2018
Weighted average number of common and exchangeable shares outstanding	379,942,355	391,054,204		383,491,798		391,173,460
Shares issuable pursuant to stock options	—	4,894,633		126,325		2,420,509
Shares assumed to be purchased from proceeds of stock options	—	(4,308,138	)	(125,609	)	(2,166,348	)
Shares issuable pursuant to convertible notes	35,814,393	35,814,393		35,814,393		35,814,393
Weighted average number of diluted common and exchangeable shares outstanding	415,756,748	427,455,092		419,306,907		427,242,014

For the three and six months ended June 30, 2019, 10,373,522 and 9,945,406 options, respectively (three and six months ended June 30, 2018 - 5,240,018 and 7,385,714, respectively), on a weighted average basis, were excluded from the diluted income per share calculation as the options were anti-dilutive. Subsequent to period end, the Convertible Notes were purchased and subsequently canceled.

6. Revenue

The Company's revenues are generated from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to ICE Brent and adjusted for Vasconia or Castilla crude differentials, quality, and transportation discounts each month. For the three and six months ended June 30, 2019, 100% (three and six months ended June 30, 2018 - 100%) of the Company's revenue resulted from oil sales. During the three and six months

ended June 30, 2019, quality and transportation discounts were 13% and 15%, respectively, of the average ICE Brent price (three and six months ended June 30, 2018 - 14% and 15%, respectively). During the three and six months ended June 30, 2019, the Company's production was sold primarily to three major customers in Colombia (three and six months ended June 30, 2018 - three).

As at June 30, 2019, accounts receivable included $3.0 million of accrued sales revenue related to June 2019 production (December 31, 2018 - $4.2 million related to December 31, 2018 production).

7. Taxes

The Company's effective tax rate was 46% for the six months ended June 30, 2019, compared to 58% in the comparative period of 2018. Current income tax expense was lower in the six months ended June 30, 2019, compared with the corresponding period of 2018, primarily as a result of lower Colombian income and higher tax depreciation in Colombia. The deferred income tax expense of $23.3 million was lower in the six months ended June 30, 2019, compared to the corresponding period of 2018 primarily due to lower excess tax depreciation compared with accounting depreciation in Colombia, a reduction in the Colombian tax rate and a reduction to the valuation allowance in Colombia.

For the six months ended June 30, 2019, the difference between the effective tax rate of 46% and the 33% Colombian tax rate was primarily due to foreign currency translation adjustments and an increase in the valuation allowance.

For the comparative period in 2018, the 58% effective tax rate differed from the Colombian tax rate of 37% primarily due to the impact of foreign tax rates, stock based compensation, foreign currency translation adjustments and an increase in the valuation allowance.

8. Contingencies

Legal Proceedings

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 $55.6 million as at June 30, 2019 (December 31, 2018 - $56.3 million). At this time no amount has been accrued in the interim unaudited condensed consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

In addition to the above, the Company has a number of other lawsuits and claims pending. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, the Company believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Gran Tierra records costs associated with these lawsuits and claims as they are incurred or become probable and determinable.

Letters of credit and other credit support

At June 30, 2019, the Company had provided letters of credit and other credit support totaling $122.5 million (December 31, 2018 - $76.7 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts and other capital or operating requirements.

9. Financial Instruments and Fair Value Measurement

Financial Instruments

At June 30, 2019, the Company’s financial instruments recognized in the balance sheet consisted of: cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; investment; accounts payable and accrued liabilities, derivatives, long-term debt, equity compensation award liability and other long-term liabilities.

Fair Value Measurement

The fair value of investment, derivatives and PSU liability is remeasured at the estimated fair value at the end of each reporting period.

The fair value of the short-term portion of the Company's investment in PetroTal Corp. ("PetroTal"), which was received on the sale of the Company's Peru business unit, was estimated using quoted prices at June 30, 2019, and the foreign exchange rate at that date. PetroTal is a publicly-traded energy company incorporated and domiciled in Canada engaged in exploration, appraisal and development of crude oil and natural gas in Peru, South America. PetroTal's shares are listed on the Toronto Stock Exchange Venture under the trading symbol 'TAL' and on the London Stock Exchange under the trading symbol 'PTAL'. Gran Tierra directly and indirectly holds approximately 246 million common shares representing approximately 37% of PetroTal's issued and outstanding common shares. Gran Tierra has the right to nominate two directors to the board of PetroTal. The fair value of the long-term portion of the investment restricted by escrow conditions was estimated using observable and unobservable inputs; factors that were evaluated included quoted market prices, precedent comparable transactions, risk free rate, measures of market risk volatility, estimates of the Company's and PetroTal’s cost of capital and quotes from third parties.

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

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

The fair value of investment, derivatives and equity compensation award liability (PSU and DSU) at June 30, 2019, and December 31, 2018, was as follows:



(Thousands of U.S. Dollars)	As at June 30, 2019		As at December 31, 2018
Investment - current and long-term	$	59,489	$	41,435
Derivative asset	857		—
	60,346		41,435

Derivative liability	$	413	$	1,017
PSU and DSU liability	8,586		17,683
	$	8,999	$	18,700

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



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Commodity price derivative (gain) loss	$	(706	)	$	14,461		$	488		$	19,455
Foreign currency derivatives loss (gain)	55			1,945			55			(2,024		)
Investment gain	(17,689		)	(11,638		)	(15,718		)	(5,717		)
Financial instruments (gain) loss	$	(18,340	)	$	4,768		$	(15,175	)	$	11,714

Investment gain for the three and six months ended June 30, 2019, was related to the fair value gain on the PetroTal shares Gran Tierra received in connection with the sale of its Peru business unit in December 2017. For the three and six months ended June 30, 2019 and 2018, this investment gain was unrealized.

Financial instruments not recorded at fair value include the Company's 6.25% Senior Notes due 2025 (the "6.25% Senior Notes") and 7.75% Senior Notes and the Convertible Notes. At June 30, 2019, the carrying amounts of the 6.25% Senior Notes, the 7.75% Senior Notes and the Convertible Notes were $290.0 million, $289.2 million and $112.7 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $280.5 million, $294.8 million and $123.6 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

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

At June 30, 2019, the fair value of the current portion of the investment and DSU liability was determined using Level 1 inputs, the fair value of derivatives and PSUs was determined using Level 2 inputs and the fair value of the long-term portion of the investment restricted by escrow conditions was determined using Level 3 inputs. The table below presents the fair value of the long-term portion of the investment:



	Six Months Ended			Year Ended
(Thousands of U.S. Dollars)	June 30, 2019			December 31, 2018
Opening balance, investment - long-term	$	8,711		$	19,147
Transfer from long-term (Level 3) to current (Level 1)	(4,352		)	(10,522		)
Unrealized valuation gain	1,394			846
Unrealized foreign exchange gain (loss)	428			(760		)
Closing balance, investment - long-term	$	6,181		$	8,711

With all other variables held constant, a $0.01 change in the CAD price of PetroTal shares would result in a $1.9 million change in the total investment in PetroTal as at June 30, 2019.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s Senior Notes, Convertible Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure above regarding the fair value of the Convertible Notes was determined using Level 2 inputs based on the indicative pricing published by certain third-party services or trading levels of the Convertible Notes, which are not listed on any securities exchange or quoted on an inter-dealer automated quotation system. The disclosure in the paragraph above regarding the fair value of cash and restricted cash and cash equivalents, revolving credit facility and Senior Notes was based on Level 1 inputs.

The Company’s non-recurring fair value measurements include asset retirement obligations. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. The significant level 3 inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free interest rate, inflation rates and estimated dates of abandonment. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets.

Commodity Price Derivatives

The Company utilizes commodity price derivatives to manage the variability in cash flows associated with the forecasted sale of its oil production, reduce commodity price risk and provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.

At June 30, 2019, the Company had outstanding commodity price derivative positions as follows:



Period and type of instrument	Volume, bopd	Reference	Purchased Put ($/bbl, Weighted Average)		Sold Call ($/bbl, Weighted Average)		Premium ($/bbl, Weighted Average)
Purchased Puts: July 1, to December 31, 2019	5,000	ICE Brent	$	60.00	n/a		$	2.39
Collars: July 1, to December 31, 2019	5,000	ICE Brent	$	60.00	$	71.53	n/a

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. Subsequent to June 30, 2019, the Company entered into 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	Floor Price (COP, Weighted Average)	Cap Price (COP, Weighted Average)
Collars: July 1, to December 31, 2019	135,000	42,109	COP	3,019	3,446

⁽¹⁾At June 30, 2019 foreign exchange rate.

10. Supplemental Cash Flow Information

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



(Thousands of U.S. Dollars)	As at June 30,				As at December 31,
	2019		2018		2018		2017
Cash and cash equivalents	$	147,712	$	125,807	$	51,040	$	12,326
Restricted cash and cash equivalents - current	699		2,836		1,269		11,787
Restricted cash and cash equivalents - long-term (included in other long-term assets)	2,265		2,282		1,999		2,565
	$	150,676	$	130,925	$	54,308	$	26,678

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



	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018
Accounts receivable and other long-term assets	$	(7,465	)	$	(11,723	)
Derivatives	(659		)	3,431
Inventory	(1,387		)	(3,054		)
Prepaids	870			(301		)
Accounts payable and accrued and other long-term liabilities	(18,841		)	971
Taxes receivable and payable	(42,712		)	(27,318		)
Net changes in assets and liabilities from operating activities	$	(70,194	)	$	(37,994	)

The following table provides additional supplemental cash flow disclosures:



	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019		2018
Cash paid for income taxes	$	29,339	$	21,032
Cash paid for interest	$	13,545	$	3,788

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	96,320	$	62,009

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 2018 Annual Report on Form 10-K. 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 2018 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the second quarter of 2019


•	Net after royalties production ("NAR") was 29,193 BOEPD, 4% higher than the second quarter of 2018. Production increased largely due to production from development activities in the Acordionero Field, a decrease in royalties driven by lower oil prices and the acquisition of additional working interest ("WI") in Suroriente Block

•

The production increases were partially offset by the temporary suspension of Suroriente production due to community blockades from June17 through July 9, 2019, and, starting late May 2019, downtime from ESP failures in Acordionero and the temporary shut-in of two large producers in Acordionero with high gas oil ratio ("GOR"). The successful commissioning of water injection facilities in Acordionero in July 2019 and associated increase in water injection is

expected to reduce the GOR in the field and the planned transition to gas to power in August 2019 is expected to reduce ESP failures due to unreliable power. Both activities in Acordionero are expected to allow us to restore production in the coming months


•	Oil and natural gas sales volumes were 29,277 BOEPD, 5% higher than the second quarter of 2018. The quarter's increase in oil and gas sales volumes was due to the reduction of inventory


•	Net income was $38.5 million compared with $20.3 million in the second quarter of 2018


•	Funds flow from operations⁽²⁾ decreased by 7% to $88.3 million compared with the second quarter of 2018, while Brent price decreased 9% from the second quarter of 2018


•	EBITDA⁽²⁾ was $115.3 million compared with $102.3 million in the second quarter of 2018


•	Q2 2019 was an active quarter with capital expenditures of $99.6 million


•	Oil and gas sales per BOE were $59.30, 8% lower than the second quarter of 2018


•	Operating netback⁽²⁾ per BOE was $40.02 for the second quarter 2019


•	Operating expenses per BOE were $12.66, 20% higher than the second quarter of 2018 as a result of higher power generation, field operations maintenance and equipment rental costs


•	Workover expenses per BOE were $4.79, 46% higher compared to the second quarter of 2018 as a result of submersible pump failures during the second quarter of 2019


•	Quality and transportation discount per BOE was $9.02 compared with $10.53 in the second quarter of 2018; this $1.51 per BOE reduction resulted from renegotiation of several sales agreements which use Castilla differential and smaller fixed discount during the second quarter of 2019 opposed to using Vasconia and higher fixed discount in the sales agreements during the second quarter of 2018


•	Transportation expenses per BOE were $1.83, compared to $2.57 per BOE for the second quarter of 2018



(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended June 30,								Three Months Ended March, 31			Six Months Ended June 30,
	2019			2018			% Change		2019			2019			2018			% Change
Average Daily Volumes (BOEPD)
Consolidated
Working Interest Production Before Royalties	35,340			35,400			—		38,163			36,744			35,239			4
Royalties	(6,147		)	(7,202		)	15		(6,499		)	(6,322		)	(7,045		)	10
Production NAR	29,193			28,198			4		31,664			30,422			28,194			8
Decrease (Increase) in Inventory	84			(296		)	128		169			127			(639		)	120
Sales⁽¹⁾	29,277			27,902			5		31,833			30,549			27,555			11


Net Income	$	38,540		$	20,300		90		$	1,979		$	40,519		$	38,161		6

Operating Netback
Oil and Natural Gas Sales	$	157,993		$	163,446		(3	)	$	152,565		$	310,558		$	301,674		3
Operating Expenses	(33,733		)	(26,732		)	26		(34,783		)	(68,516		)	(48,508		)	41
Workover Expenses	(12,757		)	(8,327		)	53		(6,289		)	(19,046		)	(12,816		)	49
Transportation Expenses	(4,885		)	(6,522		)	(25	)	(8,103		)	(12,988		)	(13,519		)	(4	)
Operating Netback⁽²⁾	$	106,618		$	121,865		(13	)	$	103,390		$	210,008		$	226,831		(7	)

G&A Expenses Before Stock-Based Compensation	$	9,268		$	5,593		66		$	7,869		$	17,137		$	13,575		26
G&A Stock-Based Compensation (Recovery)	(627		)	6,609			(109	)	1,727			1,100			9,787			(89	)
G&A Expenses, Including Stock-Based Compensation	$	8,641		$	12,202		(29	)	$	9,596		$	18,237		$	23,362		(22	)

EBITDA⁽²⁾	$	115,269		$	102,278		13		$	92,524		$	207,793		$	190,866		9

Funds Flow From Operations⁽²⁾	$	88,269		$	94,549		(7	)	$	75,450		$	163,719		$	169,297		(3	)

Capital Expenditures	$	99,595		$	84,394		18		$	94,489		$	194,084		$	157,088		24



	As at
(Thousands of U.S. Dollars)	June 30, 2019		December 31, 2018		% Change
Cash and Cash Equivalents and Current Restricted Cash and Cash Equivalents	$	148,411	$	52,309	184

Working Capital, Including Cash and Cash Equivalents	$	151,384	$	33,145	357

7.75% Senior notes	$	300,000	$	—	100

6.25% Senior notes	$	300,000	$	300,000	—

Convertible Notes	$	115,000	$	115,000	—

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

⁽²⁾Non-GAAP measures

Operating netback, EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or 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, workover 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 adjusted for depletion, depreciation and accretion ("DD&A") expenses, interest expense and income tax expense. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income to EBITDA is as follows:



	Three Months Ended June 30,				Three Months Ended March, 31		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019		2018		2019		2019		2018
Net income	$	38,540	$	20,300	$	1,979	$	40,519	$	38,161
Adjustments to reconcile net income to EBITDA
DD&A expenses	51,697		46,607		62,921		114,618		86,068
Interest expense	10,564		7,375		7,938		18,502		12,870
Income tax expense	14,468		27,996		19,686		34,154		53,767
EBITDA (non-GAAP)	115,269		102,278		92,524		207,793		190,866

Funds flow from operations, as presented, is defined as net income adjusted for DD&A expenses, deferred tax expense, stock-based compensation expense, amortization of debt issuance costs, cash settlement of RSUs, non-cash lease expense, lease payments, unrealized foreign exchange gains and losses, financial instruments gains or losses and cash settlement of financial instruments. Management uses this financial measure to analyze performance and income 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 to funds flow from operations is as follows:



	Three Months Ended June 30,						Three Months Ended March, 31			Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2019			2018
Net income	$	38,540		$	20,300		$	1,979		$	40,519		$	38,161
Adjustments to reconcile net income to funds flow from operations
DD&A expenses	51,697			46,607			62,921			114,618			86,068
Deferred tax expense	14,957			23,169			8,323			23,280			36,651
Stock-based compensation expense (recovery)	(627		)	6,893			1,727			1,100			10,202
Amortization of debt issuance costs	947			843			838			1,785			1,513
Cash settlement of RSUs	—			(240		)	—			—			(360		)
Non-cash lease expense	894			—			—			894			—
Lease payments	(848		)	—			—			(848		)	—
Unrealized foreign exchange (gain) loss	2,174			1,875			(3,283		)	(1,109		)	831
Financial instruments (gain) loss	(18,340		)	4,768			3,165			(15,175		)	11,714
Cash settlement of financial instruments	(1,125		)	(9,666		)	(220		)	(1,345		)	(15,483		)
Funds flow from operations (non-GAAP)	$	88,269		$	94,549		$	75,450		$	163,719		$	169,297

Additional Operational Results



	Three Months Ended June 30,							Three Months Ended March, 31			Six Months Ended June 30,
	2019			2018		% Change		2019			2019			2018		% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	157,993		$	163,446	(3	)	$	152,565		$	310,558		$	301,674	3
Operating expenses	33,733			26,732		26		34,783			68,516			48,508		41
Workover expenses	12,757			8,327		53		6,289			19,046			12,816		49
Transportation expenses	4,885			6,522		(25	)	8,103			12,988			13,519		(4	)
Operating netback⁽¹⁾	106,618			121,865		(13	)	103,390			210,008			226,831		(7	)

DD&A expenses	51,697			46,607		11		62,921			114,618			86,068		33
G&A expenses before stock-based compensation	9,268			5,593		66		7,869			17,137			13,575		26
G&A stock-based compensation expense (recovery)	(627		)	6,609		(109	)	1,727			1,100			9,787		(89	)
Severance expenses	270			1,011		(73	)	672			942			1,011		(7	)
Foreign exchange (gain) loss	1,175			2,216		47		(2,434		)	(1,259		)	1,274		(199	)
Financial instruments (gain) loss	(18,340		)	4,768		(485	)	3,165			(15,175		)	11,714		(230	)
Interest expense	10,564			7,375		43		7,938			18,502			12,870		44
	54,007			74,179		(27	)	81,858			135,865			136,299		—

Interest income	397			610		(35	)	133			530			1,396		(62	)

Income before income taxes	53,008			48,296		10		21,665			74,673			91,928		(19	)

Current income tax expense (recovery)	(489		)	4,827		(110	)	11,363			10,874			17,116		(36	)
Deferred income tax expense	14,957			23,169		(35	)	8,323			23,280			36,651		(36	)
	14,468			27,996		(48	)	19,686			34,154			53,767		(36	)
Net income	$	38,540		$	20,300	90		$	1,979		$	40,519		$	38,161	6

Sales Volumes (NAR)
Total sales volumes, BOE	2,664,257			2,539,089		5		2,865,040			5,529,297			4,987,456		11

Total sales volumes, BOEPD	29,277			27,902		5		31,833			30,549			27,555		11

Brent Price per bbl	$	68.32		$	74.90	(9	)	$	63.90		$	66.11		$	71.04	(7	)

Consolidated Results of Operations per BOE Sales Volumes NAR
Oil and natural gas sales	$	59.30		$	64.37	(8	)	$	53.25		$	56.17		$	60.49	(7	)
Operating expenses	12.66			10.52		20		12.14			12.39			9.73		27
Workover expenses	4.79			3.29		46		2.20			3.44			2.57		34
Transportation expenses	1.83			2.57		(29	)	2.83			2.35			2.71		(13	)
Operating netback⁽¹⁾	40.02			47.99		(17	)	36.08			37.99			45.48		(16	)




DD&A expenses	19.40			18.36		6		21.96			20.73			17.26		20
G&A expenses before stock-based compensation	3.48			2.20		58		2.75			3.10			2.72		14
G&A stock-based compensation expense (recovery)	(0.24		)	2.60		(109	)	0.60			0.20			1.96		(90	)
Severance expenses	0.10			0.40		(75	)	0.23			0.17			0.20		(15	)
Foreign exchange (gain) loss	0.44			0.88		50		(0.85		)	(0.23		)	0.26		188
Financial instruments (gain) loss	(6.88		)	1.88		466		1.10			(2.74		)	2.35		217
Interest expense	3.97			2.90		37		2.77			3.35			2.58		30
	20.27			29.22		(31	)	28.56			24.58			27.33		(10	)

Interest income	0.15			0.24		(38	)	0.05			0.10			0.28		(64	)

Income before income taxes	19.90			19.01		5		7.57			13.50			18.43		(27	)
Current income tax expense (recovery)	(0.18		)	1.90		(109	)	3.97			1.97			3.43		(43	)
Deferred income tax expense	5.61			9.12		(38	)	2.91			4.21			7.35		(43	)
	5.43			11.02		(51	)	6.88			6.18			10.78		(43	)
Net income	$	14.47		$	7.99	81		$	0.69		$	7.32		$	7.65	(4	)

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

Oil and Gas Production and Sales Volumes, BOEPD



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Average Daily Volumes (BOEPD)
Working Interest Production Before Royalties	35,340		35,400		36,744		35,239
Royalties	(6,147	)	(7,202	)	(6,322	)	(7,045	)
Production NAR	29,193		28,198		30,422		28,194
Decrease (Increase) in Inventory	84		(296	)	127		(639	)
Sales	29,277		27,902		30,549		27,555

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

Oil and gas production NAR for the three and six months ended June 30, 2019 increased by 4% and 8% respectively, compared with the corresponding periods of 2018. The increase in production was a result of successful drilling and workover campaign in the Acordionero Field and acquisition of additional WI in Suroriente Block during the first quarter of 2019. These increases were partially offset by the temporary suspension of Suroriente production due to community blockades from June 17 through July 9, 2019, and, starting late May 2019, downtime from ESP failures in Acordionero and the temporary shut-in of two large producers in Acordionero with high GOR. The successful commissioning of water injection facilities in Acordionero in July 2019 and associated increase in water injection is expected to reduce the GOR in the field and the planned transition to gas to power in August 2019 is expected to reduce ESP failures due to unreliable power. Both activities in Acordionero are expected to allow us to restore production in the coming months.

Royalties as a percentage of production for the three and six months ended June 30, 2019 decreased compared with the corresponding periods of 2018 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia.

Operating Netbacks



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Oil and Natural Gas Sales	$	157,993		$	163,446		$	310,558		$	301,674
Transportation Expenses	(4,885		)	(6,522		)	(12,988		)	(13,519		)
	153,108			156,924			297,570			288,155
Operating Expenses	(33,733		)	(26,732		)	(68,516		)	(48,508		)
Workover Expenses	(12,757		)	(8,327		)	(19,046		)	(12,816		)
Operating Netback⁽¹⁾	$	106,618		$	121,865		$	210,008		$	226,831

U.S. Dollars Per BOE Sales Volumes NAR
Brent	$	68.32		$	74.90		$	66.11		$	71.04
Quality and Transportation Discounts	(9.02		)	(10.53		)	(9.94		)	(10.55		)
Average Realized Price	59.30			64.37			56.17			60.49
Transportation Expenses	(1.83		)	(2.57		)	(2.35		)	(2.71		)
Average Realized Price Net of Transportation Expenses	57.47			61.80			53.82			57.78
Operating Expenses	(12.66		)	(10.53		)	(12.39		)	(9.73		)
Workover Expenses	(4.79		)	(3.28		)	(3.44		)	(2.57		)
Operating Netback⁽¹⁾	$	40.02		$	47.99		$	37.99		$	45.48

Oil and gas sales for the three months ended June 30, 2019 decreased 3% to $158.0 million as a result of 9% decrease in Brent partially offset by higher sales volumes, compared with the corresponding period of 2018. Oil and gas sales for the six months ended June 30, 2019 increased 3% to $310.6 million as a result of higher sales volumes and lower quality and transportation discounts partially offset by lower realized prices as a result of 7% decrease in Brent, compared with the corresponding period of 2018. Compared with the prior quarter, oil and gas sales increased 4% as a result of higher realized prices as a result of 7% increase in Brent partially offset by lower sales volumes.

The following table shows the effect of changes in realized prices and sales volumes on our oil and gas sales for the three and six months ended June 30, 2019 compared with the prior quarter and the corresponding periods of 2018:



(Thousands of U.S. Dollars)	Second Quarter 2019 Compared with First Quarter 2019			Second Quarter 2019 Compared with Second Quarter 2018			Six Months Ended, June 30, 2019 Compared with Six Months Ended June 30, 2018
Oil and natural gas sales for the comparative period	$	152,565		$	163,446		$	301,674
Realized sales prices increase (decrease) effect	16,120			(13,510		)	(23,890		)
Sales volumes (decrease) increase effect	(10,692		)	8,057			32,774
Oil and natural gas sales for the three and six months ended June 30, 2019	$	157,993		$	157,993		$	310,558

Average realized prices for the three and six months ended June 30, 2019 decreased 8% and 7%, respectively, compared with the corresponding periods of 2018. The decrease was commensurate with decreases in benchmark oil prices partially offset by lower quality and transportation discounts. Compared with the prior quarter, average realized prices increased 11%.

We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized sales prices and transportation expenses and we primarily focus on maximizing operating netback. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for the three and six months ended June 30, 2019 and 2018, and the prior quarter:



	Three Months Ended June 30,				Three Months Ended March, 31		Six Months Ended June 30,
	2019		2018		2019		2019		2018
Volume transported through pipeline	1	%	9	%	3	%	2	%	9	%
Volume sold at wellhead	51	%	41	%	43	%	47	%	42	%
Volume transported via truck	48	%	50	%	54	%	51	%	49	%
	100	%	100	%	100	%	100	%	100	%

Volumes transported through pipeline or via truck 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.

Transportation expenses for the three and six months ended June 30, 2019 decreased 25% and 4% to $4.9 and $13.0 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, transportation expenses decreased 29% and 13% to $1.83 and $2.35, respectively, compared with the corresponding periods of 2018. Lower transportation expenses were a result of higher volumes sold at wellhead during the three and six months ended June 30, 2019.

For the three months ended June 30, 2019, transportation expenses decreased 40% compared with $8.1 million in the prior quarter. On a per BOE basis, transportation expenses decreased 35% from $2.83 in the prior quarter. Lower transportation expenses were a result of higher volumes sold at wellhead, which had lower costs per BOE.

Operating expenses for the three and six months ended June 30, 2019 increased 26% and 41% to $33.7 and $68.5 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, operating expenses increased by $2.14 and $2.66, respectively, compared to the corresponding periods of 2018, primarily as a result of higher power generation, field operations maintenance and equipment rental costs. The Acordionero facilities expansion was fully commissioned at the beginning of the third quarter of 2019 and the gas-to-power will be commissioned in mid-August 2019. These projects will allow expanded water injection and delivery of enhanced power reliability by the end of third quarter, which are expected to reduce operating costs and enhance ultimate recovery of oil and gas in the Acordionero field. With the commissioning of the permanent facilities and gas-to-power projects, the Company expects to reduce operating costs by terminating contracts related to rental facilities in the field and generating power through natural gas produced in the field instead of purchased diesel.

Operating expenses for the three months ended June 30, 2019 decreased by 3% compared with the prior quarter. On a per BOE basis, operating expenses for the three months ended June 30, 2019 increased by 4%, or $0.52, as a result of lower sales volumes during the second quarter of 2019.

Workover expenses increased to $4.79 and $3.44 per BOE, respectively, during the three and six months ended June 30, 2019, compared to $3.29 and $2.57 in the corresponding periods of 2018 due to submersible pump failures during the second quarter of 2019 as a result of unstable power. Workover expenses increased by $2.59 per BOE compared to the prior quarter as a result of higher frequency of pump failures during the second quarter of 2019.

DD&A Expenses



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
DD&A Expenses, thousands of U.S. Dollars	$	51,697	$	46,607	$	114,618	$	86,068
DD&A Expenses, U.S. Dollars per BOE	19.40		18.36		20.73		17.26

DD&A expenses for the three and six months ended June 30, 2019 increased 11% and 33% or $1.04 and $3.47 per BOE, respectively, compared to the corresponding periods of 2018. The increase in DD&A expenses was due to higher costs in the depletable base, partially offset by an allocation to proved reserves related to Acordionero field and Suroriente Block.

For the three months ended June 30, 2019, DD&A expenses decreased 18% or $2.56 per BOE from the prior quarter primarily due to lower DD&A rate resulting from increased allocation to proved reserves.

G&A Expenses



	Three Months Ended June 30,							Three Months Ended March, 31		Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018		% Change		2019		2019		2018		% Change
G&A Expenses Before Stock-Based Compensation	$	9,268		$	5,593	66		$	7,869	$	17,137	$	13,575	26
G&A Stock-Based Compensation (Recovery)	(627		)	6,609		(109	)	1,727		1,100		9,787		(89	)
G&A Expenses, Including Stock-Based Compensation	$	8,641		$	12,202	(29	)	$	9,596	$	18,237	$	23,362	(22	)
U.S. Dollars Per BOE Sales Volumes NAR
G&A Expenses Before Stock-Based Compensation	$	3.48		$	2.20	58		$	2.75	$	3.10	$	2.72	14
G&A Stock-Based Compensation (Recovery)	(0.24		)	2.60		(109	)	0.60		0.20		1.96		(90	)
G&A Expenses, Including Stock-Based Compensation	$	3.24		$	4.80	(33	)	$	3.35	$	3.30	$	4.68	(29	)

For the three and six months ended June 30, 2019, G&A expenses before stock-based compensation increased 66% and 26%, respectively, from the corresponding periods of 2018. On a per BOE basis, G&A expenses before stock-based compensation increased 58% and 14%, from the corresponding periods of 2018. The increase was mainly a result of lower recoveries and capitalization.

For the three months ended June 30, 2019, G&A expenses before stock-based compensation increased 18% (27% per BOE) from the prior quarter primarily due to lower recoveries and capitalization during current quarter.

After stock-based compensation, G&A expenses for the three and six months ended June 30, 2019 decreased 29% and 22% (33% and 29% per BOE), respectively, compared to the corresponding periods of 2018, mainly due to lower G&A stock-based compensation resulting from a lower share price compared to the corresponding periods of 2018.

G&A expenses after stock-based compensation for the three months ended June 30, 2019 decreased by 10% (3% per BOE) compared with the prior quarter primarily due to lower G&A stock-based compensation resulting from lower share price in the current period.

Severance

For the three and six months ended June 30, 2019, severance costs decreased 73% and 7% to $0.3 and $0.9 million, compared with the corresponding periods in 2018 and decreased 60% compared with the prior quarter. The decrease is a result of head-count optimization during comparative periods of 2018 and first quarter of 2019.

Foreign Exchange Gains and Losses

For the three and six months ended June 30, 2019, we had a $1.2 million loss and $1.3 million gain on foreign exchange, compared with $2.2 million and $1.3 million losses in the corresponding periods of 2018. Taxes receivable, deferred income taxes and investment are considered monetary assets, 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 losses and gains in the periods.

The following table presents the change in the U.S. dollar against the Colombian peso for the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Change in the U.S. dollar against the Colombian peso	strengthened by	strengthened by	weakened by	weakened by
Change in the U.S. dollar against the Colombian peso	1%	5%	1%	2%
Change in the U.S. dollar against the Canadian dollar	weakened by	strengthened by	weakened by	strengthened by
Change in the U.S. dollar against the Canadian dollar	2%	2%	4%	5%

Financial Instrument Gains and Losses

The following table presents the nature of our financial instruments gains and losses for the three and six months ended June 30, 2019, and 2018:



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Commodity price derivative (gain) loss	$	(706	)	$	14,461		$	488		$	19,455
Foreign currency derivatives loss (gain)	55			1,945			55			(2,024		)
Investment gain	(17,689		)	(11,638		)	(15,718		)	(5,717		)
Financial instruments (gain) loss	$	(18,340	)	$	4,768		$	(15,175	)	$	11,714

Income Tax Expense



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Income before income tax	$	53,008		$	48,296		$	74,673		$	91,928

Current income tax expense (recovery)	$	(489	)	$	4,827		$	10,874		$	17,116
Deferred income tax expense	14,957			23,169			23,280			36,651
Total income tax expense	$	14,468		$	27,996		$	34,154		$	53,767

Effective tax rate	27		%	58		%	46		%	58		%

Current income tax expense was lower for the six months ended June 30, 2019, compared with the corresponding period of 2018 primarily as a result of lower Colombian taxable income and higher tax depreciation in Colombia. The deferred income tax expense of $23.3 million for the six months ended June 30, 2019, was lower compared with the corresponding period of 2018 primarily due to lower excess tax depreciation compared with accounting depreciation in Colombia, a reduction in the Colombian tax rate and a reduction to the valuation allowance in Colombia.

For the six months ended June 30, 2018, the difference between the effective tax rate of 58% and the 37% Colombian tax rate was primarily due to the impact of foreign tax rates, stock based compensation, foreign currency translation adjustments and an increase in the valuation allowance.

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



(Thousands of U.S. Dollars)	Second Quarter 2019 Compared with First Quarter 2019			% change		Second Quarter 2019 Compared with Second Quarter 2018			% change		Six Months Ended, June 30, 2019 Compared with Six Months Ended June 30, 2018			% change
Net income for the comparative period	$	1,979				$	20,300				38,161
Increase (decrease) due to:
Prices	16,120					(13,510		)			(23,890		)
Sales volumes	(10,692		)			8,057					32,774
Expenses:
Operating	1,050					(7,001		)			(20,008		)
Workover	(6,468		)			(4,430		)			(6,230		)
Transportation	3,218					1,637					531
Cash G&A, RSU settlements and lease payments, excluding stock-based compensation expense	(1,353		)			(3,673		)			(3,571		)
Severance	402					741					69
Interest, net of amortization of debt issuance costs	(2,517		)			(3,085		)			(5,360		)
Realized foreign exchange	1,848					1,340					593
Settlement of financial instruments	(905		)			8,541					14,138
Current taxes	11,852					5,316					6,242
Other	264					(213		)			(866		)
Net change in funds flow from operations⁽¹⁾ from comparative period	12,819					(6,280		)			(5,578		)
Expenses:
Depletion, depreciation and accretion	11,224					(5,090		)			(28,550		)
Deferred tax	(6,634		)			8,212					13,371
Amortization of debt issuance costs	(109		)			(104		)			(272		)
Non-cash lease expenses net of lease payments	(46		)			(46		)			(46		)
Stock-based compensation, net of RSU settlement	2,354					7,280					8,742
Financial instruments gain or loss, net of financial instruments settlements	22,410					14,567					12,751
Unrealized foreign exchange	(5,457		)			(299		)			1,940
Net change in net income	36,561					18,240					2,358
Net income for the current period	$	38,540		1,847	%	$	38,540		90	%	$	40,519		6	%

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

Capital expenditures during the three months ended June 30, 2019 were $99.6 million:



(Millions of U.S. Dollars)
Colombia:
Exploration	$	36.2
Development:
Drilling and Completions	28.3
Facilities	18.6
Other	16.5
	99.6
Corporate	—
	$	99.6

During the three months ended June 30, 2019, we drilled the following wells in Colombia:



	Number of wells (Gross)	Number of wells (Net)
Development	6	6
Total	6	6

We spud 6 development wells, five in Midas and one in Chaza Blocks. Of the wells spud during the quarter, two development wells were completed as of June 30, 2019.

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

Liquidity and Capital Resources



	As at
(Thousands of U.S. Dollars)	June 30, 2019		% Change		December 31, 2018
Cash and Cash Equivalents	$	147,712	189		$	51,040

Current Restricted Cash and Cash Equivalents	$	699	(45	)	$	1,269

Working Capital, Including Cash and Cash Equivalents	$	151,384	357		$	33,145

6.25% Senior notes	$	300,000	—		$	300,000

7.75% 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 2019, given current oil price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions.

At June 30, 2019, we had an undrawn revolving credit facility with a syndicate of lenders with a borrowing base of $300 million. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. The next re-determination of the borrowing base is due to occur no later than November 2019.

At June 30, 2019, we had $115 million aggregate principal amount of 5.00% Convertible Senior Notes due 2021, $300 million aggregate principal amount of 6.25% Senior Notes due 2025, and $300 million aggregate principal amount of 7.75% Senior Notes due 2027 outstanding.

On July 17, 2019, pursuant to a previously announced offer to purchase for cash all outstanding Convertible Notes, the Company purchased and canceled $114,997,000 aggregate principal amount of Convertible Notes at a purchase price of $1,075 in cash per $1,000 principal amount of Convertible Notes plus $1.6 million of accrued and unpaid interest outstanding on such Convertible Notes up to, but not excluding the date of purchase. After giving effect to the purchase and cancellation of the Convertible Notes, 3,000 aggregate principal amount of Convertible Notes remain outstanding.

Under the terms of our credit facility and Senior Notes, we are required to maintain compliance with certain financial and operating covenants which include: limitations on our ratio of debt to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income ("EBITDAX") to a maximum of 4.0 to 1.0 (under the credit facility) and 3.5 to 1.0 (under the Senior Notes); the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0 (definitions of debt, EBITDAX and other relevant terms are per the credit agreement or the indenture governing the Senior Notes and may differ between these agreements). As at June 30, 2019, 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 June 30, 2019, net debt to EBITDA was 1.4 times on a trailing twelve month basis and 1.2 times on the basis of the Quarter's annualized results

Derivative Positions

At June 30, 2019, we had outstanding commodity price derivative positions as follows:



Period and type of instrument	Volume, bopd	Reference	Purchased Put ($/bbl, Weighted Average)		Sold Call ($/bbl, Weighted Average)		Premium ($/bbl, Weighted Average)
Purchased Puts: July 1, to December 31, 2019	5,000	ICE Brent	$	60.00	n/a		$	2.39
Collars: July 1, to December 31, 2019	5,000	ICE Brent	$	60.00	$	71.53	n/a

At June 30, 2019, current liabilities on our balance sheet included $0.4 million and current assets on our balance sheet included $0.9 million in relation to the above outstanding commodity price derivative positions.

Foreign Currency Derivatives

At June 30, 2019, the Company entered into 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	Floor Price (COP, Weighted Average)	Cap Price (COP, Weighted Average)
Collars: July 1, to December 31, 2019	135,000	42,109	COP	3,019	3,446

⁽¹⁾At June 30, 2019 foreign exchange rate.

Cash Flows

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



	Six Months Ended June 30,
(Thousands of U.S. Dollars)	2019			2018
Sources of cash and cash equivalents:
Net income	$	40,519		$	38,161
Adjustments to reconcile net income to EBITDA⁽¹⁾ and funds flow from operations⁽¹⁾
DD&A expenses	114,618			86,068
Interest expense	18,502			12,870
Income tax expense	34,154			53,767
EBITDA	207,793			190,866
Current income tax expense	(10,874		)	(17,116		)
Contractual interest and other financing expenses	(16,717		)	(11,357		)
Stock-based compensation expense	1,100			10,202
Cash settlement of RSUs	—			(360		)
Unrealized foreign exchange (gain) loss	(1,109		)	831
Financial instruments (gain) loss	(15,175		)	11,714
Non-cash lease expenses	894			—
Lease payments	(848		)	—
Cash settlement of financial instruments	(1,345		)	(15,483		)
Funds flow from operations	163,719			169,297
Proceeds from bank debt, net of issuance costs	163,000			4,988
Proceeds from issuance of Senior Notes, net of issuance costs	289,117			288,087
Proceeds from issuance of shares	—			845
	615,836			463,217

Uses of cash and cash equivalents:
Additions to property, plant and equipment	(194,084		)	(157,088		)
Additions to property, plant and equipment - property acquisitions	(77,772		)	(3,100		)
Repayment of bank debt	(163,000		)	(153,000		)
Repurchase of shares of Common Stock	(23,951		)	(1,208		)
Net changes in assets and liabilities from operating activities	(70,194		)	(37,994		)
Changes in non-cash investing working capital	11,116			(6,142		)
Settlement of asset retirement obligations	(510		)	(369		)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(1,073		)	(69		)
	(519,468		)	(358,970		)
Net increase in cash and cash equivalents and restricted cash and cash equivalents	$	96,368		$	104,247

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

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices, the impact of which we partially mitigate by entering into commodity derivatives. Sales volume changes and costs related to operations and debt service also impact cash flow. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes, the impact of which we partially mitigate by entering into foreign currency derivatives.

Off-Balance Sheet Arrangements

As at June 30, 2019, we had no off-balance sheet arrangements.

Contractual Obligations

On May 20, 2019, we issued $300 million aggregate principal amount of the 7.75% Senior Notes. Refer to Note 4 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Form 10-Q.

During the six months ended June 30, 2019, we re-paid a balance of $163 million outstanding under our revolving credit facility, which was undrawn as at June 30, 2019.

Subsequent to June 30, 2019, we purchased and canceled $114,997,000 aggregate principal amount of Convertible Notes at a purchase price of $1,075 in cash per $1,000 principal amount of Convertible Notes plus $1.6 million of accrued and unpaid interest outstanding on such Convertible Notes up to, but not excluding the date of purchase

Except for noted above, as at June 30, 2019, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at December 31, 2018.

Critical Accounting Policies and Estimates

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

Leases

We adopted Accounting Standard Codification ("ASC") 842 Leases with a date of initial application on January 1, 2019 in accordance with the modified retrospective transition approach using the practical expedients available for land easements and short-term leases. We did not elect the "suite" of practical expedients or use the hindsight expedient in its adoption.

The transition resulted in the recognition of a right-of-use asset presented in other capital assets of $3.8 million, the recognition of lease liabilities in other long-term liabilities of $4.2 million and a $0.4 million impact on retained earnings. When measuring the lease liabilities, the Company's incremental borrowing rate was used. At January 1, 2019 the average rates applied were between 5.6% and 9.1%.

At inception of a contract, we assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At inception of a contract that contains a lease component, we allocate the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. We recognize a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, and subsequently at cost less any accumulated depreciation and impairment losses, and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, our incremental borrowing rate. Generally, we use the Company's incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.

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 is in U.S. dollars or is 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 June 30, 2019, our outstanding balance under revolving credit facility was nil (December 31, 2018 - nil).

Further Information

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 further information regarding our derivative contracts, including the notional amounts and call and put prices by expected (contractual) maturity dates. Expected cash flows from the derivatives equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. We do not hold any of these derivative contracts for trading purposes.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as of June 30, 2019.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2019, 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 8 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 any material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2018, 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 2018 Annual Report on Form 10-K. Other than the risk factor set forth below, there have been no material changes to the risks set forth in Part I, Item 1A Risk Factors of our 2018 Annual Report on Form 10-K.

We have recently been awarded exploration rights on blocks in Ecuador.

We have recently been awarded exploration rights on blocks in Ecuador. We have not previously operated in Ecuador, and it is difficult to predict the results and to project the costs of implementing an exploratory drilling program in Ecuador due to the inherent uncertainties of drilling and the fact that exploration and production operations there are subject to legal, social, political and economic uncertainties that may be different from what we have experienced in Colombia. Ecuador has experienced and may in the future experience political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including but not limited to: the imposition of additional taxes; nationalization; changes in energy or environmental policies or the personnel administering them; and changes in oil and natural gas pricing policies. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets or renegotiation or nullification of existing concessions and contracts. Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Ecuador are beyond our control and may significantly hamper our ability to expand our operations or operate our business in this country at a profit. Wells that are drilled may not achieve the results expected.

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
April 1-30, 2019	3,518,025	2.42	3,518,025	13,993,151	⁽³⁾
May 1-31, 2019	3,668,300	2.17	3,668,300	10,324,851	⁽³⁾
June 1-30, 2019	670,100	1.98	670,100	9,654,751	⁽³⁾
	7,856,425	2.27	7,856,425	9,654,751

⁽¹⁾ Based on settlement date.

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

⁽³⁾On March 11, 2019, we announced that we intended to implement a share repurchase program (the “2019 Program”) through the facilities of the TSX and eligible alternative trading platforms in Canada. We received regulatory approval from the TSX to commence the 2019 Program on March 13, 2019. We are able to purchase at prevailing market prices up to 19,353,951 shares of Common Stock, representing approximately 5% of our issued and outstanding shares of Common Stock as of March 31, 2019.

The 2019 Program will expire on March 12, 2020, or earlier if the 5.00% share maximum is reached. The 2019 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 2019 Program. Of the shares repurchased, 4,338,400 shares have not been cancelled by the Company and are designated as treasury stock as at June 30, 2019.

Item 6. Exhibits



Exhibit No.	Description	Reference

3.1	Certificate of Incorporation.	Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

3.2	Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

3.3	Certificate of Retirement dated July 9, 2018	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed with the SEC on July 9, 2018 (SEC File No. 001-34018).

4.1	Indenture related to the 7.750% Senior Notes due 2027, dated as of May 23, 2019, among Gran Tierra Energy Inc., 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 May 23, 2019 (SEC File No. 001-34018).

4.2	Form of 7.750% Senior Notes due 2027 (included as Exhibit A to Exhibit 4.1).	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the SEC on May 23, 2019 (SEC File No. 001-34018).

10.1	Twelfth Amendment to Credit Agreement, dated and effective as of May 14, 2019, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on May 15, 2019 (SEC File No. 001-34018).

10.2	Purchase Agreement, dated May 20, 2019, by and among Gran Tierra Energy Inc., the guarantors named therein, and BofA Securities, Inc. and Credit Suisse Securities (USA) 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 May 23, 2019 (SEC File No. 001-34018).

10.3	First Supplemental Indenture related to 6.25% Senior Notes due 2025, dated as of July 23, 2019, among Gran Tierra Energy Inc., the guarantors named therein, and U.S. Bank National Association.	Filed herewith.

10.4	First Supplemental Indenture related to 7.750% Senior Notes due 2027, dated as of July 23, 2019, among Gran Tierra Energy Inc., the guarantors named therein, and U.S. Bank National Association.	Filed herewith.

31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.

31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith.

32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished herewith.

101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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 Document104 The cover page from Gran Tierra Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in Inline XBRL (included within the Exhibit 101 attachments).

SIGNATURES

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

GRAN TIERRA ENERGY INC.



Date: August 7, 2019		/s/ Gary S. Guidry
		By: Gary S. Guidry
		President and Chief Executive Officer
		(Principal Executive Officer)



Date: August 7, 2019		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)