Quarterly Report (10-q)

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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 September 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 October 30, 2019, 366,981,556 shares of the registrant’s Common Stock, $0.001 par value, were issued.

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended September 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	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	31

PART II	Other Information
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 6.	Exhibits	33
SIGNATURES		34

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; volatility or declines in the trading price of our common stock; and 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." 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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
OIL AND NATURAL GAS SALES (Note 6)	$	132,491		$	175,118		$	443,049		$	476,792

EXPENSES
Operating	35,603			29,511			104,119			78,019
Workover	10,979			13,106			30,025			25,922
Transportation	3,179			7,505			16,167			21,024
Depletion, depreciation and accretion	49,812			51,630			164,430			137,698
General and administrative	7,637			13,811			25,874			37,173
Severance	140			1,004			1,082			2,015
Foreign exchange loss (gain)	6,840			(888		)	5,581			386
Financial instruments loss (gain) (Note 9)	12,285			(4,874		)	(2,890		)	6,840
Loss on redemption of Convertible Notes (Note 4)	11,305			—			11,305			—
Interest expense (Note 4)	12,153			7,404			30,655			20,274
	149,933			118,209			386,348			329,351

INTEREST INCOME	130			725			660			2,121
(LOSS) INCOME BEFORE INCOME TAXES	(17,312		)	57,634			57,361			149,562

INCOME TAX EXPENSE (RECOVERY)
Current (Note 7)	3,049			19,108			13,923			36,224
Deferred (Note 7)	8,472			(36,769		)	31,752			(118		)
	11,521			(17,661		)	45,675			36,106
NET AND COMPREHENSIVE (LOSS) INCOME	$	(28,833	)	$	75,295		$	11,686		$	113,456

NET (LOSS) INCOME PER SHARE
- BASIC	$	(0.08	)	$	0.19		$	0.03		$	0.29
- DILUTED	$	(0.08	)	$	0.18		$	0.03		$	0.28
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)	372,195,176			391,209,589			379,701,405			391,185,636
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)	372,195,176			427,947,959			379,701,664			427,416,964

(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 September 30, 2019			As at December 31, 2018

ASSETS
Current Assets
Cash and cash equivalents (Note 10)	$	13,959		$	51,040
Restricted cash and cash equivalents (Note 10)	676			1,269
Accounts receivable	27,334			26,177
Investment (Note 9)	41,979			32,724
Taxes receivable	100,205			78,259
Other assets	16,824			13,056
Total Current Assets	200,977			202,525

Oil and Gas Properties
Proved	1,063,386			853,428
Unproved	504,779			456,598
Total Oil and Gas Properties	1,568,165			1,310,026
Other capital assets	5,139			2,751
Total Property, Plant and Equipment	1,573,304			1,312,777

Other Long-Term Assets
Deferred tax assets	44,886			45,437
Investment (Note 9)	4,868			8,711
Taxes receivable	29,036			—
Other	4,209			4,553
Goodwill	102,581			102,581
Total Other Long-Term Assets	185,580			161,282
Total Assets	$	1,959,861		$	1,676,584

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	201,569		$	154,670
Derivatives (Note 9)	747			1,017
Taxes payable	—			4,149
Equity compensation award liability (Note 5 and 9)	3,661			9,544
Total Current Liabilities	205,977			169,380

Long-Term Liabilities
Long-term debt (Notes 4 and 9)	637,601			399,415
Deferred tax liabilities	53,930			23,419
Asset retirement obligation	48,411			43,676
Equity compensation award liability (Note 5 and 9)	4,544			8,139
Other	4,346			2,805
Total Long-Term Liabilities	748,832			477,454

Contingencies (Note 8)

Shareholders’ Equity
Common Stock (Note 5) (366,981,556 and 387,079,027 shares issued and outstanding of Common Stock, par value $0.001 per share, as at September 30, 2019, and December 31, 2018, respectively)	10,270			10,290
Additional paid in capital	1,282,074			1,318,048
Deficit	(287,292		)	(298,588		)
Total Shareholders’ Equity	1,005,052			1,029,750
Total Liabilities and Shareholders’ Equity	$	1,959,861		$	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)



	Nine Months Ended September 30,
	2019			2018
Operating Activities
Net income	$	11,686		$	113,456
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion	164,430			137,698
Deferred tax expense (recovery)	31,752			(118		)
Stock-based compensation (Note 5)	1,092			20,477
Amortization of debt issuance costs (Note 4)	2,574			2,329
Unrealized foreign exchange loss	5,303			159
Financial instruments (gain) loss (Note 9)	(2,890		)	6,840
Cash settlement of financial instruments	(2,275		)	(26,169		)
Loss on redemption of Convertible Notes (Note 4)	11,305			—
Cash settlement of asset retirement obligation	(707		)	(456		)
Non-cash lease expenses	1,366			—
Lease payments	(1,603		)	—
Cash settlement of restricted share units	—			(360		)
Net change in assets and liabilities from operating activities (Note 10)	(83,606		)	(40,652		)
Net cash provided by operating activities	138,427			213,204

Investing Activities
Additions to property, plant and equipment	(310,579		)	(258,551		)
Property acquisitions, net of cash acquired (Note 3)	(77,772		)	(20,100		)
Changes in non-cash investing working capital	20,138			32,638
Net cash used in investing activities	(368,213		)	(246,013		)

Financing Activities
Proceeds from bank debt, net of issuance costs	246,000			4,988
Repayment of debt	(304,000		)	(153,000		)
Repurchase of shares of Common Stock (Note 5)	(37,560		)	(1,314		)
Proceeds from exercise of stock options	—			1,408
Proceeds from issuance of Senior Notes, net of issuance costs	289,298			288,087
Net cash provided by financing activities	193,738			140,169

Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(1,506		)	(402		)

Net (decrease) increase in cash, cash equivalents and restricted cash and cash equivalents	(37,554		)	106,958
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)	$	16,754		$	133,636

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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Share Capital
Balance, beginning of period	$	10,285		$	10,295		$	10,290		$	10,295
Issuance of Common Stock	—			1			—			1
Repurchase and cancellation of Common Stock (Note 5)	(15		)	(1		)	(20		)	(1		)
Balance, end of period	10,270			10,295			10,270			10,295

Additional Paid in Capital
Balance, beginning of period	1,295,106			1,328,037			1,318,048			1,327,244
Exercise of stock options	—			562			—			1,407
Stock-based compensation (Note 5)	563			489			1,566			1,645
Repurchase and cancellation of Common Stock (Note 5)	(13,595		)	(105		)	(37,540		)	(1,313		)
Balance, end of period	1,282,074			1,328,983			1,282,074			1,328,983

Deficit
Balance, beginning of period	(258,459		)	(363,043		)	(298,588		)	(401,204		)
Net (loss) income	(28,833		)	75,295			11,686			113,456
Cumulative adjustment for accounting change related to leases (Note 2)	—			—			(390		)	—
Balance, end of period	(287,292		)	(287,748		)	(287,292		)	(287,748		)

Total Shareholders’ Equity	$	1,005,052		$	1,051,530		$	1,005,052		$	1,051,530

(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 as part of the transition 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	$	52,960
Unproved	45,132
	98,092
Net working capital (including cash acquired of $5.3 million)	(17,492		)
	$	80,600

4. Debt and Debt Issuance Costs

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



(Thousands of U.S. Dollars)	As at September 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
Revolving credit facility	57,000			—
Unamortized debt issuance costs	(21,454		)	(15,585		)
Long-term debt	635,546			399,415
Long-term lease obligation⁽¹⁾	2,055			—
	$	637,601		$	399,415

⁽¹⁾The current portion of the lease obligation has been included in accounts payable and accrued liabilities on the Company's balance sheet and totaled $1.8 million as at September 30, 2019 (December 31, 2018 - nil).

Senior Notes

On May 20, 2019, the Company, issued $300.0 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 $289.1 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

During the quarter, the Company purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes, including 114,997,000 aggregate principal amount purchased and canceled pursuant to a previously announced offer to purchase for cash all outstanding 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. The Company recorded $11.3 million loss on redemption including premium paid, transaction costs and $2.3 million of deferred financing fees write-off.

Interest Expense

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019		2018		2019		2018
Contractual interest and other financing expenses	$	11,364	$	6,588	$	28,081	$	17,945
Amortization of debt issuance costs	789		816		2,574		2,329
	$	12,153	$	7,404	$	30,655	$	20,274

5. Share Capital



	Shares of Common Stock
Balance, December 31, 2018	387,079,027
Shares repurchased and canceled	(20,097,471	)
Balance, September 30, 2019	366,981,556

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 had an expiry date of March 12, 2020, or earlier if the 5.00% share maximum was reached. The 2019 Program expired when the 5.00% share maximum was reached in September 2019.

During the three and nine months ended September 30, 2019, the Company repurchased 9,654,751 and 20,097,471 shares at a weighted average prices of $1.41 and $1.87, respectively. Of the shares repurchased, 743,520 shares at a weighted average price of $2.34 were repurchased under 2018 share repurchase program with similar terms to that of the 2019 Program.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), and stock option activity for the nine months ended September 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	5,179,906		352,810	2,391,253		2.26
Exercised	(2,725,877	)	—	—		—
Forfeited	(574,010	)	—	(943,846	)	3.94
Expired	—		—	(129,730	)	5.41
Balance, September 30, 2019	10,884,680		1,037,703	10,352,089		2.87

For the three and nine months ended September 30, 2019, stock-based compensation expense was nil and $1.1 million, respectively (three and nine months ended September 30, 2018 - $10.3 million and $20.5 million, respectively).

At September 30, 2019, there was $8.8 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 1.8 years. During the nine months ended September 30, 2019, the Company paid out $10.2 million (nine months ended September 30, 2018 - nil) for PSUs 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 September 30,			Nine Months Ended September 30,
	2019	2018		2019		2018
Weighted average number of common and exchangeable shares outstanding	372,195,176	391,209,589		379,701,405		391,185,636
Shares issuable pursuant to stock options	—	6,509,385		14,315		4,295,964
Shares assumed to be purchased from proceeds of stock options	—	(5,585,408	)	(14,056	)	(3,879,029	)
Shares issuable pursuant to convertible notes	—	35,814,393		—		35,814,393
Weighted average number of diluted common and exchangeable shares outstanding	372,195,176	427,947,959		379,701,664		427,416,964
Common shares outstanding, as at period end	366,981,556	391,339,489		366,981,556		391,339,489

For the three and nine months ended September 30, 2019, 10,316,496 and 10,247,016 options, respectively (three and nine months ended September 30, 2018 - 3,198,865 and 5,436,667, respectively), on a weighted average basis, were excluded from the diluted income per share calculation as the options were anti-dilutive.

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 nine months ended September 30, 2019, 100%

(three and nine months ended September 30, 2018 - 100%) of the Company's revenue resulted from oil sales. During the three and nine months ended September 30, 2019, quality and transportation discounts were 16% and 15%, respectively, of the average ICE Brent price (three and nine months ended September 30, 2018 - 13% and 14%, respectively). During the three and nine months ended September 30, 2019, the Company's production was sold primarily to three major customers in Colombia (three and nine months ended September 30, 2018 - two).

As at September 30, 2019, accounts receivable included $0.1 million of accrued sales revenue related to September 2019 production (December 31, 2018 - $4.2 million related to December 31, 2018 production).

7. Taxes

The Company's effective tax rate was 79% for the nine months ended September 30, 2019, compared to 24% in the comparative period of 2018. Current income tax expense was lower in the nine months ended September 30, 2019, compared with the corresponding period of 2018, primarily as a result of lower income and higher tax depreciation in Colombia. The deferred income tax expense of $31.8 million was higher in the nine months ended September 30, 2019, compared to the corresponding period of 2018 primarily due to the impact of the release of a portion of the valuation allowance in Colombia during 2018 and excess tax depreciation compared with accounting depreciation in Colombia during 2019.

For the nine months ended September 30, 2019, the difference between the effective tax rate of 79% and the 33% Colombian tax rate was primarily due to foreign currency translation adjustments, an increase in the valuation allowance and the impact of foreign tax rates.

For the comparative period of 2018, the 24% effective tax rate differed from the Colombian tax rate of 37% primarily due to a decrease in the valuation allowance and other permanent differences, which was partially offset by the impact of foreign tax rates.

On October 16, 2019, the Colombian Constitutional Court overturned the 2018 tax reform effective January 1, 2020. If a new tax reform law is not approved by the Congress of Colombia by December 31, 2019, the tax regime in force before the 2018 tax reform will apply beginning January 1, 2020. On October 23, 2019, the Congress of Colombia filed a tax bill proposing the same amendments that were approved by the Congress of Colombia in 2018 and which would become effective on January 1, 2020. Based on the Company’s review and analysis of the impact of the court decision and the bill proposed by the Congress of Colombia, the Company believes that both should not have a material effect on its financial statements.

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 $56.2 million as at September 30, 2019 (December 31, 2018 - $56.3 million). At this time no amount has been accrued 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 September 30, 2019, the Company had provided letters of credit and other credit support totaling $123.9 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 September 30, 2019, the Company’s financial instruments recognized on 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 September 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 through a subsidiary 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 September 30, 2019, and December 31, 2018, was as follows:



(Thousands of U.S. Dollars)	As at September 30, 2019		As at December 31, 2018
Investment - current and long-term	$	46,847	$	41,435
Derivative asset¹	1,807		—
	48,654		41,435

Derivative liability	$	747	$	1,017
PSU and DSU liability	8,205		17,683
	$	8,952	$	18,700

¹Included in other current assets on the Company's balance sheet

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Commodity price derivative loss (gain)	$	(24	)	$	929		$	464		$	20,384
Foreign currency derivatives loss (gain)	337			525			392			(1,499		)
Investment loss (gain)	11,972			(6,328		)	(3,746		)	(12,045		)
Financial instruments loss (gain)	$	12,285		$	(4,874	)	$	(2,890	)	$	6,840

Investment loss (gain) for the three and nine months ended September 30, 2019, was related to the fair value loss (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 nine months ended September 30, 2019 and 2018, this investment loss (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 due 2027. At September 30, 2019, the carrying amounts of the 6.25% Senior Notes and the 7.75% Senior Notes were $290.3 million and $289.6 million, respectively, which represented the aggregate principal amount less unamortized debt issuance costs, and the fair values were $268.6 million and $285.0 million, respectively. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

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

At September 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:



	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 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	148			846
Unrealized foreign exchange gain (loss)	361			(760		)
Closing balance, investment - long-term	$	4,868		$	8,711

With all other variables held constant, a $0.01 change in the CAD price of PetroTal shares would result in a $1.8 million change in the total investment in PetroTal as at September 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 and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure in the paragraph above regarding the fair value of 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 September 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: October 1, to December 31, 2019	5,000	ICE Brent	60.00	n/a	2.39
Collars: October 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. At September 30, 2019, the Company had outstanding foreign currency derivative positions as follows:



Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)⁽¹⁾	Reference	Floor Price (COP, Weighted Average)	Cap Price (COP, Weighted Average)
Collars: October 1, to December 31, 2019	67,500	19,497	COP	3,019	3,446

⁽¹⁾At September 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 September 30,				As at December 31,
	2019		2018		2018		2017
Cash and cash equivalents	$	13,959	$	130,158	$	51,040	$	12,326
Restricted cash and cash equivalents - current	676		1,228		1,269		11,787
Restricted cash and cash equivalents - long-term (included in other long-term assets)	2,119		2,250		1,999		2,565
	$	16,754	$	133,636	$	54,308	$	26,678

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



	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018
Accounts receivable and other long-term assets	$	3,476		$	(35,934	)
Derivatives	(658		)	21,645
Inventory	(3,403		)	(3,375		)
Prepaids	353			489
Accounts payable and accrued and other long-term liabilities	(21,687		)	5,380
Taxes receivable and payable	(61,687		)	(28,857		)
Net changes in assets and liabilities from operating activities	$	(83,606	)	$	(40,652	)

The following table provides additional supplemental cash flow disclosures:



	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019		2018
Cash paid for income taxes	$	38,022	$	38,202
Cash paid for interest	$	25,850	$	14,137

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	105,342	$	100,790

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 third quarter of 2019


•	We purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes


•	Returned $13.6 million to shareholders through the repurchase of 9,654,751 common shares

•

Net after royalties production ("NAR") was 27,763 BOEPD, 3% lower than the third quarter of 2018. Production decreased as a result of unplanned downtime caused by electrical submersible pump ("ESP") failures at the Acordionero field, the shut-in of several wells in Acordionero due to high gas production and temporary suspension of Suroriente production due to community issues at the beginning of the quarter, partially offset by a decrease in royalties driven by lower oil prices


•	Oil and natural gas sales volumes⁽¹⁾ were 27,705 BOEPD, 3% lower than the third quarter of 2018. The quarter's decrease in oil and gas sales volumes was commensurate lower production


•	Net loss was $28.8 million compared with net income of $75.3 million in the third quarter of 2018 primarily due to non-cash items including loss on revaluation of investment and loss on the redemption of the Convertible Notes


•	Funds flow from operations⁽²⁾ decreased by 31% to $59.0 million compared with the third quarter of 2018, as a result of lower production and 18% decrease in the price of Brent


•	Adjusted EBITDA⁽²⁾ was $67.9 million compared with $110.3 million in the third quarter of 2018


•	Q3 2019 was an active quarter with capital expenditures of $116.5 million


•	Oil and gas sales per BOE were $51.98, 22% lower than the third quarter of 2018


•	Operating netback⁽²⁾ per BOE was $32.45 for the third quarter of 2019


•	Operating expenses per BOE were $13.97, 25% higher than the third quarter of 2018 as a result of higher power generation, field operations maintenance and freight and logistics costs and lower production volumes. A significant portion of the Company's operating costs are fixed costs


•	Workover expenses per BOE were $4.31 during the third quarter of 2019, 13% lower compared to the third quarter of 2018 as a result of lower frequency of ESP failures


•	Quality and transportation discount per BOE was $10.05 compared with $9.55 in the third quarter of 2018. The increase was due to higher sales at wellhead during the third quarter of 2019 which resulted in a higher transportation discount but lower transportation expenses


•	Transportation expenses per BOE were $1.25, compared to $2.85 per BOE for the third quarter of 2018



(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended September 30,								Three Months Ended June 30,			Nine Months Ended September 30,
	2019			2018			% Change		2019			2019			2018			% Change
Average Daily Volumes (BOEPD)
Consolidated
Working Interest Production Before Royalties	32,918			36,170			(9	)	35,340			35,454			35,553			—
Royalties	(5,155		)	(7,571		)	(32	)	(6,147		)	(5,929		)	(7,222		)	(18	)
Production NAR	27,763			28,599			(3	)	29,193			29,525			28,331			4
(Increase) Decrease in Inventory	(58		)	60			(197	)	84			65			(403		)	116
Sales⁽¹⁾	27,705			28,659			(3	)	29,277			29,590			27,928			6


Net (Loss) Income	$	(28,833	)	$	75,295		(138	)	$	38,540		$	11,686		$	113,456		(90	)

Operating Netback
Oil and Natural Gas Sales	$	132,491		$	175,118		(24	)	$	157,993		$	443,049		$	476,792		(7	)
Operating Expenses	(35,603		)	(29,511		)	21		(33,733		)	(104,119		)	(78,019		)	33
Workover Expenses	(10,979		)	(13,106		)	(16	)	(12,757		)	(30,025		)	(25,922		)	16
Transportation Expenses	(3,179		)	(7,505		)	(58	)	(4,885		)	(16,167		)	(21,024		)	(23	)
Operating Netback⁽²⁾	$	82,730		$	124,996		(34	)	$	106,618		$	292,738		$	351,827		(17	)

G&A Expenses Before Stock-Based Compensation	$	7,645		$	3,679		108		$	9,268		$	24,782		$	17,254		44
G&A Stock-Based Compensation (Recovery) Expense	(8		)	10,132			(100	)	(627		)	1,092			19,919			(95	)
G&A Expenses, Including Stock-Based Compensation	$	7,637		$	13,811		(45	)	$	8,641		$	25,874		$	37,173		(30	)

Adjusted EBITDA⁽²⁾	$	67,930		$	110,340		(38	)	$	97,580		$	260,005		$	295,489		(12	)

Funds Flow From Operations⁽²⁾	$	59,021		$	85,015		(31	)	$	88,269		$	222,740		$	254,312		(12	)

Capital Expenditures	$	116,495		$	101,463		15		$	99,595		$	310,579		$	258,551		20

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

⁽²⁾Non-GAAP measures

Operating netback, EBITDA, Adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net (loss) 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 (loss) income adjusted for depletion, depreciation and accretion ("DD&A") expenses, interest expense and income tax expense. Adjusted EBITDA is defined as EBITDA adjusted for loss on redemption of Convertible Notes and loss or gain on investment. Management uses these supplemental measures 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 and Adjusted EBITDA is as follows:



	Three Months Ended September 30,						Three Months Ended June 30,			Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2019			2018
Net (loss) income	$	(28,833	)	$	75,295		$	38,540		$	11,686		$	113,456
Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA
DD&A expenses	49,812			51,630			51,697			164,430			137,698
Interest expense	12,153			7,404			10,564			30,655			20,274
Income tax expense (recovery)	11,521			(17,661		)	14,468			45,675			36,106
EBITDA (non-GAAP)	44,653			116,668			115,269			252,446			307,534
Loss on redemption of Convertible Notes	11,305			—			—			11,305			—
Investment loss (gain)	11,972			(6,328		)	(17,689		)	(3,746		)	(12,045		)
Adjusted EBITDA (non-GAAP)	67,930			110,340			97,580			260,005			295,489

Funds flow from operations, as presented, is defined as net (loss) income adjusted for DD&A expenses, deferred tax expense (recovery), stock-based compensation (recovery) 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, loss on redemption of Convertible Notes 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 September 30,						Three Months Ended June 30,			Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2019			2018
Net (loss) income	$	(28,833	)	$	75,295		$	38,540		$	11,686		$	113,456
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses	49,812			51,630			51,697			164,430			137,698
Deferred tax expense (recovery)	8,472			(36,769		)	14,957			31,752			(118		)
Stock-based compensation (recovery) expense	(8		)	10,275			(627		)	1,092			20,477
Amortization of debt issuance costs	789			816			947			2,574			2,329
Cash settlement of RSUs	—			—			—			—			(360		)
Non-cash lease expense	472			—			894			1,366			—
Lease payments	(755		)	—			(848		)	(1,603		)	—
Unrealized foreign exchange loss (gain)	6,412			(672		)	2,174			5,303			159
Financial instruments loss (gain)	12,285			(4,874		)	(18,340		)	(2,890		)	6,840
Loss on redemption of Convertible Notes	11,305			—			—			11,305			—
Cash settlement of financial instruments	(930		)	(10,686		)	(1,125		)	(2,275		)	(26,169		)
Funds flow from operations (non-GAAP)	$	59,021		$	85,015		$	88,269		$	222,740		$	254,312

Additional Operational Results



	Three Months Ended September 30,								Three Months Ended June 30,			Nine Months Ended September 30,
	2019			2018			% Change		2019			2019			2018			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	132,491		$	175,118		(24	)	$	157,993		$	443,049		$	476,792		(7	)
Operating expenses	35,603			29,511			21		33,733			104,119			78,019			33
Workover expenses	10,979			13,106			(16	)	12,757			30,025			25,922			16
Transportation expenses	3,179			7,505			(58	)	4,885			16,167			21,024			(23	)
Operating netback⁽¹⁾	82,730			124,996			(34	)	106,618			292,738			351,827			(17	)

DD&A expenses	49,812			51,630			(4	)	51,697			164,430			137,698			19
G&A expenses before stock-based compensation	7,645			3,679			108		9,268			24,782			17,254			44
G&A stock-based compensation (recovery) expense	(8		)	10,132			(100	)	(627		)	1,092			19,919			(95	)
Severance expenses	140			1,004			(86	)	270			1,082			2,015			(46	)
Foreign exchange loss (gain)	6,840			(888		)	870		1,175			5,581			386			1,346
Financial instruments loss (gain)	12,285			(4,874		)	352		(18,340		)	(2,890		)	6,840			(142	)
Loss on redemption of Convertible Notes	11,305			—			100		—			11,305			—			100
Interest expense	12,153			7,404			64		10,564			30,655			20,274			51
	100,172			68,087			47		54,007			236,037			204,386			15

Interest income	130			725			(82	)	397			660			2,121			(69	)

(Loss) Income before income taxes	(17,312		)	57,634			(130	)	53,008			57,361			149,562			(62	)

Current income tax expense (recovery)	3,049			19,108			(84	)	(489		)	13,923			36,224			(62	)
Deferred income tax expense (recovery)	8,472			(36,769		)	123		14,957			31,752			(118		)	27,008
	11,521			(17,661		)	165		14,468			45,675			36,106			27
Net (loss) income	$	(28,833	)	$	75,295		(138	)	$	38,540		$	11,686		$	113,456		(90	)

Sales Volumes (NAR)

Total sales volumes, BOEPD	27,705			28,659			(3	)	29,277			29,590			27,928			6

Brent Price per bbl	$	62.03		$	75.97		(18	)	$	68.32		$	64.75		$	72.68		(11	)

Consolidated Results of Operations per BOE Sales Volumes NAR
Oil and natural gas sales	$	51.98		$	66.42		(22	)	$	59.30		$	54.85		$	62.54		(12	)
Operating expenses	13.97			11.19			25		12.66			12.89			10.23			26
Workover expenses	4.31			4.97			(13	)	4.79			3.72			3.40			9
Transportation expenses	1.25			2.85			(56	)	1.83			2.00			2.76			(28	)



Operating netback⁽¹⁾	32.45			47.41			(32	)	40.02			36.24			46.15			(21	)

DD&A expenses	19.54			19.58			—		19.40			20.35			18.06			13
G&A expenses before stock-based compensation	3.00			1.40			114		3.48			3.07			2.26			36
G&A stock-based compensation (recovery) expense	—			3.84			(100	)	(0.24		)	0.14			2.61			(95	)
Severance expenses	0.05			0.38			(87	)	0.10			0.13			0.26			(50	)
Foreign exchange loss (gain)	2.68			(0.34		)	888		0.44			0.69			0.05			1,280
Financial instruments loss (gain)	4.82			(1.85		)	361		(6.88		)	(0.36		)	0.90			(140	)
Loss on redemption of Convertible Notes	4.44			—			100		—			1.40			—			100
Interest expense	4.77			2.81			70		3.97			3.79			2.66			42
	39.30			25.82			52		20.27			29.21			26.80			9

Interest income	0.05			0.27			(81	)	0.15			0.08			0.28			(71	)

(Loss) Income before income taxes	(6.80		)	21.86			(131	)	19.90			7.11			19.63			(64	)

Current income tax expense (recovery)	1.20			7.25			(83	)	(0.18		)	1.72			4.75			(64	)
Deferred income tax expense (recovery)	3.32			(13.95		)	124		5.61			3.93			(0.02		)	19,750
	4.52			(6.70		)	167		5.43			5.65			4.73			19
Net (loss) income	$	(11.32	)	$	28.56		(140	)	$	14.47		$	1.46		$	14.90		(90	)

⁽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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Average Daily Volumes (BOEPD)
Working Interest Production Before Royalties	32,918		36,170		35,454		35,553
Royalties	(5,155	)	(7,571	)	(5,929	)	(7,222	)
Production NAR	27,763		28,599		29,525		28,331
(Increase) Decrease in Inventory	(58	)	60		65		(403	)
Sales	27,705		28,659		29,590		27,928

Royalties, % of Working Interest Production Before Royalties	16	%	21	%	17	%	20	%

Oil and gas production NAR for the three months ended September 30, 2019 decreased by 3%, compared with the corresponding period of 2018. The decrease in production was a result of unplanned downtime from ESP failures in the Acordionero field, the shut-in of several wells in Acordionero due to high gas production and temporary suspension of Suroriente production due to community issues at the beginning of the quarter. During the quarter we successfully commissioned water injection and gas-to-power facilities in the Acordionero field which is expected to increase production beginning in the fourth quarter of 2019. We have increased water injection to over 30,000 barrels of water per day and have recently restored production from the several wells previously shut-in.

For the nine months ended September 30, 2019 oil and gas production NAR increased by 4% , compared with the corresponding period of 2018 due to a successful drilling campaign in the Acordionero field and lower royalties in 2019.

Royalties as a percentage of production for the three and nine months ended September 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 September 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Oil and Natural Gas Sales	$	132,491		$	175,118		$	443,049		$	476,792
Transportation Expenses	(3,179		)	(7,505		)	(16,167		)	(21,024		)
	129,312			167,613			426,882			455,768
Operating Expenses	(35,603		)	(29,511		)	(104,119		)	(78,019		)
Workover Expenses	(10,979		)	(13,106		)	(30,025		)	(25,922		)
Operating Netback⁽¹⁾	$	82,730		$	124,996		$	292,738		$	351,827

U.S. Dollars Per BOE Sales Volumes NAR
Brent	$	62.03		$	75.97		$	64.75		$	72.68
Quality and Transportation Discounts	(10.05		)	(9.55		)	(9.90		)	(10.14		)
Average Realized Price	51.98			66.42			54.85			62.54
Transportation Expenses	(1.25		)	(2.85		)	(2.00		)	(2.76		)
Average Realized Price Net of Transportation Expenses	50.73			63.57			52.85			59.78
Operating Expenses	(13.97		)	(11.19		)	(12.89		)	(10.23		)
Workover Expenses	(4.31		)	(4.97		)	(3.72		)	(3.40		)
Operating Netback⁽¹⁾	$	32.45		$	47.41		$	36.24		$	46.15

Oil and gas sales for the three and nine months ended September 30, 2019 decreased 24% and 7% to $132.5 and $443.0 million, respectively. The decrease for the three months ended September 30, 2019 was a result of 18% decrease in Brent, 3 % lower sales volumes and higher quality and transportation discounts, compared with the corresponding period of 2018. The decrease for the nine months ended September 30, 2019 was a result of 11% decrease in Brent, partially offset by 6 % higher sales volumes and lower quality and transportation discounts, compared with the corresponding period of 2018. Compared with the prior quarter, oil and gas sales decreased 16% as a result of 9% decrease in Brent, 5% lower sales volumes and higher quality and transportation discount.

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



(Thousands of U.S. Dollars)	Third Quarter 2019 Compared with Second Quarter 2019			Third Quarter 2019 Compared with Third Quarter 2018			Nine Months Ended September 30, 2019 Compared with Nine Months Ended September 30, 2018
Oil and natural gas sales for the comparative period	$	157,993		$	175,118		$	476,792
Realized sales price decrease effect	(18,658		)	(36,801		)	(62,143		)
Sales volumes (decrease) increase effect	(6,844		)	(5,826		)	28,400
Oil and natural gas sales for the three and nine months ended September 30, 2019	$	132,491		$	132,491		$	443,049

Average realized price for the three and nine months ended September 30, 2019 decreased 22% and 12%, respectively, compared with the corresponding periods of 2018. The decrease was commensurate with the decrease in benchmark oil prices. Compared with the prior quarter, the average realized price decreased 12%.

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



	Three Months Ended September 30,				Three Months Ended June 30,		Nine Months Ended September 30,
	2019		2018		2019		2019		2018
Volume transported through pipeline	—	%	9	%	1	%	2	%	9	%
Volume sold at wellhead	54	%	37	%	51	%	48	%	39	%
Volume transported via truck to sales point	46	%	54	%	48	%	50	%	52	%
	100	%	100	%	100	%	100	%	100	%

Volumes transported through pipeline or via truck receive higher realized price, but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expenses.

Transportation expenses for the three and nine months ended September 30, 2019 decreased 58% and 23% to $3.2 and $16.2 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, transportation expenses decreased 56% and 28% to $1.25 and $2.00, respectively, compared with the corresponding periods of 2018. Lower transportation expenses were a result of higher volumes sold at the wellhead during the three and nine months ended September 30, 2019 and a change in sales point for a portion of the Acordionero production.

For the three months ended September 30, 2019, transportation expenses decreased 35% compared with $4.9 million in the prior quarter. On a per BOE basis, transportation expenses decreased 32% from $1.83 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 nine months ended September 30, 2019 increased 21% and 33% to $35.6 and $104.1 million, respectively, compared with the corresponding periods of 2018. On a per BOE basis, operating expenses increased by $2.78 and $2.66, respectively, compared to the corresponding periods of 2018, primarily as a result of higher power generation, field operations maintenance and freight and logistics costs and lower production volumes. The Acordionero expansion and gas-to-power facilities were fully commissioned during the third quarter of 2019. These projects will allow expanded water injection and delivery of enhanced power reliability, 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, we are expecting 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. The cost reductions are expected to begin November of this year with the full benefit being realized in 2020.

Operating expenses for the three months ended September 30, 2019 increased by 6% compared with the prior quarter. On a per BOE basis, operating expenses for the three months ended September 30, 2019 increased by 10%, or $1.31, primarily as a result of higher power generation costs during the current quarter.

Workover expenses on per BOE basis, decreased to $4.31 for the three months ended September 30, 2019 compared to $4.97 in the corresponding period of 2018 due to lower frequency of ESP failures during the current quarter. Workover expenses increased to $3.72 for the nine months ended September 30, 2019 compared to $3.40 in the corresponding period of 2018 due to more workover activities performed during the nine months ended September 30, 2019. Workover expenses decreased by $0.48 per BOE compared to the prior quarter as a result of lower frequency of ESP failures during the third quarter of 2019.

DD&A Expenses



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
DD&A Expenses, thousands of U.S. Dollars	$	49,812	$	51,630	$	164,430	$	137,698
DD&A Expenses, U.S. Dollars per BOE	19.54		19.58		20.35		18.06

DD&A expenses for the three months ended September 30, 2019 decreased 4% or $0.04 per BOE, compared to the corresponding period of 2018 due to allocation of proved reserves related to the Acordionero field. DD&A expenses for the nine months ended September 30, 2019 increased 19% or $2.29 per BOE, compared to the corresponding period of 2018. The increase in DD&A expenses was due to higher costs in the depletable base, partially offset by higher proved reserves related to Acordionero field and Suroriente Block, and lower production.

For the three months ended September 30, 2019 DD&A expenses decreased 4% from the prior quarter primarily due to higher proved reserves. On per BOE bases, DD&A expenses and increased $0.14 from the prior quarter due to lower sales volumes during the current quarter.

G&A Expenses



	Three Months Ended September 30,							Three Months Ended June 30,			Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018		% Change		2019			2019		2018		% Change
G&A Expenses Before Stock-Based Compensation	$	7,645		$	3,679	108		$	9,268		$	24,782	$	17,254	44
G&A Stock-Based Compensation (Recovery) Expense	(8		)	10,132		(100	)	(627		)	1,092		19,919		(95	)
G&A Expenses, Including Stock-Based Compensation	$	7,637		$	13,811	(45	)	$	8,641		$	25,874	$	37,173	(30	)
U.S. Dollars Per BOE Sales Volumes NAR
G&A Expenses Before Stock-Based Compensation	$	3.00		$	1.40	114		$	3.48		$	3.07	$	2.26	36
G&A Stock-Based Compensation (Recovery) Expense	—			3.84		(100	)	(0.24		)	0.14		2.61		(95	)
G&A Expenses, Including Stock-Based Compensation	$	3.00		$	5.24	(43	)	$	3.24		$	3.21	$	4.87	(34	)

For the three and nine months ended September 30, 2019, G&A expenses before stock-based compensation increased 108% and 44%, respectively, from the corresponding periods of 2018 due to lower recoveries and capitalization during 2019 periods. On a per BOE basis, G&A expenses before stock-based compensation increased 114% and 36%, from the corresponding periods of 2018. The increase was mainly a result of lower recoveries and capitalization. For the three months ended September 30, 2019,

G&A expenses before stock-based compensation decreased 18% (14% per BOE) from the prior quarter primarily due to higher recoveries and capitalization during the current quarter.

G&A expenses after stock-based compensation for the three and nine months ended September 30, 2019 decreased 45% and 30% (43% and 34% 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 September 30, 2019 decreased by 12% (7% 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.

Foreign Exchange Gains and Losses

For the three and nine months ended September 30, 2019, we had a $6.8 million and $5.6 million, respectively, loss on foreign exchange, compared with $0.9 million gain and $0.4 million loss, respectively, 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 nine months ended September 30, 2019 and 2018:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Change in the U.S. dollar against the Colombian peso	strengthened by	strengthened by	strengthened by	no change
Change in the U.S. dollar against the Colombian peso	8%	1%	7%	—%
Change in the U.S. dollar against the Canadian dollar	strengthened by	weakened by	weakened by	strengthened by
Change in the U.S. dollar against the Canadian dollar	1%	2%	3%	3%

Financial Instrument Gains and Losses

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Commodity price derivative loss (gain)	$	(24	)	$	929		$	464		$	20,384
Foreign currency derivatives loss (gain)	337			525			392			(1,499		)
Investment loss (gain)	11,972			(6,328		)	(3,746		)	(12,045		)
Financial instruments loss (gain)	$	12,285		$	(4,874	)	$	(2,890	)	$	6,840

Income Tax Expense



	Three Months Ended September 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018			2019			2018
Income (loss) before income tax	$	(17,312	)	$	57,634		$	57,361		$	149,562

Current income tax expense	$	3,049		$	19,108		$	13,923		$	36,224
Deferred income tax expense (recovery)	8,472			(36,769		)	31,752			(118		)
Total income tax expense (recovery)	$	11,521		$	(17,661	)	$	45,675		$	36,106

Effective tax rate	(67		)%	(31		)%	79		%	24		%

Current income tax expense was lower for the nine months ended September 30, 2019, compared with the corresponding period of 2018 primarily as a result of lower income and higher tax depreciation in Colombia. The deferred income tax expense of $31.8 million for the nine months ended September 30, 2019, was higher compared with the corresponding period of 2018 primarily due to the impact of the release of a portion of the valuation allowance in Colombia during 2018 and excess tax depreciation compared with accounting depreciation in Colombia during 2019.

For the nine months ended September 30, 2018, the difference between the effective tax rate of 24% and the 37% Colombian tax rate was primarily due to a decrease in the valuation allowance and other permanent differences, which was partially offset by the impact of foreign tax rates.

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



(Thousands of U.S. Dollars)	Third Quarter 2019 Compared with Second Quarter 2019			% change		Third Quarter 2019 Compared with Third Quarter 2018			% change		Nine Months Ended, September 30, 2019 Compared with Nine Months Ended September 30, 2018			% change
Net income for the comparative period	$	38,540				$	75,295				113,456
Increase (decrease) due to:
Prices	(18,658		)			(36,801		)			(62,143		)
Sales volumes	(6,844		)			(5,826		)			28,400
Expenses:
Operating	(1,870		)			(6,092		)			(26,100		)
Workover	1,778					2,127					(4,103		)
Transportation	1,706					4,326					4,857
Cash G&A, RSU settlements and lease payments	1,294					(4,392		)			(7,963		)
Severance	130					864					933
Interest, net of amortization of debt issuance costs	(1,747		)			(4,776		)			(10,136		)
Realized foreign exchange	(1,427		)			(644		)			(51		)
Settlement of financial instruments	195					9,756					23,894
Current taxes	(3,538		)			16,059					22,301
Interest Income	(267		)			(595		)			(1,461		)
Net change in funds flow from operations⁽¹⁾ from comparative period	(29,248		)			(25,994		)			(31,572		)
Expenses:
Depletion, depreciation and accretion	1,885					1,818					(26,732		)
Deferred tax	6,485					(45,241		)			(31,870		)
Amortization of debt issuance costs	158					27					(245		)
Non-cash lease expenses net of lease payments	329					283					237
Stock-based compensation, net of RSU settlement	(619		)			10,283					19,025
Financial instruments gain or loss, net of financial instruments settlements	(30,820		)			(26,915		)			(14,164		)
Unrealized foreign exchange	(4,238		)			(7,084		)			(5,144		)
Loss on redemption of convertible debt	(11,305		)			(11,305		)			(11,305		)
Net change in net income	(67,373		)			(104,128		)			(101,770		)
Net (loss) income for the current period	$	(28,833	)	(175	)%	$	(28,833	)	(138	)%	$	11,686		(90	)%

⁽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 September 30, 2019 were $116.5 million:



(Millions of U.S. Dollars)
Colombia:
Exploration	$	12.2
Development:
Drilling and Completions	60.0
Facilities	25.8
Other	17.3
	115.3
Corporate	1.2
	$	116.5

During the three months ended September 30, 2019, we commenced drilling the following wells in Colombia:



	Number of wells (Gross)	Number of wells (Net)
Development	8	8
Other	6	6
Total	14	14

We spud 8 development and 6 service wells, of which ten were in the Midas Block, three were in the VMM-2 Block and one was in the Chaza Block. Of the wells spud during the quarter, 12 wells were completed, and 2 were in-progress as of September 30, 2019.

We commissioned facilities in the Acordionero Field on the Midas Block and continued facilities work in the Moqueta Field on the Chaza Block.

On February 20, 2019, we 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.

Liquidity and Capital Resources



	As at
(Thousands of U.S. Dollars)	September 30, 2019			% Change		December 31, 2018
Cash and Cash Equivalents	$	13,959		(73	)	$	51,040

Current Restricted Cash and Cash Equivalents	$	676		(47	)	$	1,269

Working Capital (Deficiency), Including Cash and Cash Equivalents	$	(5,000	)	(115	)	$	33,145

Revolving Credit Facility	$	57,000		100		$	—

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

7.75% Senior Notes	$	300,000		100		$	—

Convertible Notes	$	—		(100	)	$	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 over the next 12 months given current oil price trends and production levels. We have no near term maturities and $243.0 million available under our credit facility.

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 September 30, 2019, we had $57.0 million drawn on the revolving credit facility with a syndicate of lenders with a borrowing base of $300.0 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 September 30, 2019, we had $300.0 million aggregate principal amount of 6.25% Senior Notes due 2025, and $300.0 million aggregate principal amount of 7.75% Senior Notes due 2027 outstanding.

During the quarter, we purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes, including $114,997,000 aggregate principal amount pursuant to a previously announced offer to purchase for cash all outstanding 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. We recorded $11.3 million loss on redemption including premium paid, transaction costs and $2.3 million of deferred financing fees write-off.

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 September 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.

Derivative Positions

At September 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: October 1, to December 31, 2019	5,000	ICE Brent	$	60.00	n/a		$	2.39
Collars: October 1, to December 31, 2019	5,000	ICE Brent	$	60.00	$	71.53	n/a

Foreign Currency Derivatives

At September 30, 2019, we had outstanding foreign currency derivative positions as follows:



Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)⁽¹⁾	Reference	Floor Price (COP, Weighted Average)	Cap Price (COP, Weighted Average)
Collars: October 1, to December 31, 2019	67,500	19,497	COP	3,019	3,446

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

At September 30, 2019, our balance sheet included $1.8 million of current assets and $0.7 million of current liabilities related to the above outstanding commodity price and foreign currency derivative positions.

Cash Flows

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



	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2019			2018
Sources of cash and cash equivalents:
Net income	$	11,686		$	113,456
Adjustments to reconcile net income to Adjusted EBITDA⁽¹⁾ and funds flow from operations⁽¹⁾
DD&A expenses	164,430			137,698
Interest expense	30,655			20,274
Income tax expense	45,675			36,106
Loss on redemption of convertible notes	11,305			—
Gain on investment	(3,746		)	(12,045		)
Adjusted EBITDA	260,005			295,489
Current income tax expense	(13,923		)	(36,224		)
Contractual interest and other financing expenses	(28,081		)	(17,945		)
Stock-based compensation expense	1,092			20,477
Cash settlement of RSUs	—			(360		)
Unrealized foreign exchange loss	5,303			159
Financial instruments loss excluding gain on investment	856			18,885
Non-cash lease expenses	1,366			—
Lease payments	(1,603		)	—
Cash settlement of financial instruments	(2,275		)	(26,169		)
Funds flow from operations	222,740			254,312
Proceeds from bank debt, net of issuance costs	246,000			4,988
Proceeds from issuance of Senior Notes, net of issuance costs	289,298			288,087
Proceeds from issuance of shares	—			1,408
Changes in non-cash investing working capital	20,138			32,638
	778,176			581,433

Uses of cash and cash equivalents:
Additions to property, plant and equipment	(310,579		)	(258,551		)
Additions to property, plant and equipment - property acquisitions	(77,772		)	(20,100		)
Repayment of bank debt	(304,000		)	(153,000		)
Repurchase of shares of Common Stock	(37,560		)	(1,314		)
Net changes in assets and liabilities from operating activities	(83,606		)	(40,652		)
Settlement of asset retirement obligations	(707		)	(456		)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(1,506		)	(402		)
	(815,730		)	(474,475		)
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents	$	(37,554	)	$	106,958

(1) Adjusted 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 September 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.

At September 30, 2019, we had $57 million drawn under our revolving credit facility.

Except for noted above, as at September 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 September 30, 2019, our outstanding balance under revolving credit facility was $57 million (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 September 30, 2019.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 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 and Part II, Item 1A Risk Factors of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019. Other than the risk factors set forth therein, there have been no material changes to our risk factors.

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
July 1-31, 2019	1,842,750	1.60	1,842,750	7,812,001	⁽³⁾
August 1-31, 2019	6,401,675	1.35	6,401,675	1,410,326	⁽³⁾
September 1-30, 2019	1,410,326	1.41	1,410,326	—	⁽³⁾
	9,654,751	1.41	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 were 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 was scheduled to expire on March 12, 2020, or earlier if the 5.00% share maximum is reached. During the three months ended September 30, 2019, we reached the maximum share repurchase limit of 19,353,951 shares and the 2019 Program expired.

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).

10.1*	Executive Employment Agreement, dated October 18, 2019, between Gran Tierra Energy Canada ULC and Gran Tierra Energy Inc. and Remi Anthony Berthelet.	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.

* Management contract or compensatory plan or arrangement.

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 Inline XBRL Taxonomy Extension Schema Document

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document

104.The cover page from Gran Tierra Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 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.