UNITED STATES SECURITIES AND EXCHANGE COMMISSION



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

Commission file number 001-34018

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~~

Calgary,

Alberta

Canada

T2P 0R3

(Address of principal executive offices, including zip 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 ý☒ No o☐

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

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

On October ~~31, 2017, the following number of~~29, 2021, 367,144,500 shares of the ~~registrant’s capital stock were outstanding: 388,415,513 shares of the registrant’s~~registrant's Common Stock, $0.001 par ~~value; one share of Special A Voting Stock, $0.001 par~~ value, ~~representing 1,688,889 shares of~~ were issued.

Gran Tierra ~~Goldstrike~~Energy Inc.~~, which are exchangeable~~ (the “Company”) is filing this Amendment No. 1 (“Amendment”) to its Form 10-Q for the quarter ended September 30, 2021, originally filed with the Securities and Exchange Commission (“SEC”) on ~~a 1-for-1 basis into~~November 2, 2021 (the “Original 10-Q”). This Amendment is being filed solely for the ~~registrant’s Common Stock;~~purpose of correcting an incorrect date in the certification by the Company's Chief Executive Officer and ~~one share~~Chief Financial Officer pursuant to Section 906 of ~~Special B Voting Stock, $0.001 par value, representing 4,666,792 shares~~the Sarbanes-Oxley Act of ~~Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into~~2002 filed as Exhibit 32.1 to the ~~registrant’s Common Stock.~~Original 10-Q. In accordance with Compliance and Disclosure Interpretations published by the SEC Staff, the entire periodic report for the quarter ended September 30, 2021 is included in this Amendment. Other than the correction described above, no other statement or amount has been changed from those presented in the Original 10-Q.



		Page
PART I	Financial Information
Item 1.	Financial Statements	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2117
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3937
Item 4.	Controls and Procedures	4037

PART II	Other Information
Item 1.	Legal Proceedings	4137
Item 1A.	Risk Factors	4137

Item 6.2.	~~Exhibits~~Unregistered Sales of Equity Securities and Use of Proceeds	4138
~~SIGNATURES~~Item 6.	Exhibits	4239
SIGNATURES		40

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 ~~impact~~and benefits of ~~proposed~~the changes in our capital program or ~~pending transactions,~~expenditures, our liquidity, the impacts of the coronavirus (COVID-19) pandemic 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, our ability to comply with covenants in our credit agreement and indentures and make borrowings under our credit agreement; our ability to obtain amendments to the covenants in our credit agreement so as to avoid an event of default under our credit agreement and senior notes; a reduction in our borrowing base and our ability to repay any excess borrowings; sustained or future declines in commodity ~~prices;~~prices and the demand for oil; sustained or future excess supply of oil and natural gas; potential future impairments and reductions in proved reserve quantities and value; continuation of the COVID-19 pandemic and responses thereto, including possible future restrictions against oil and gas activity in Colombia and Ecuador; our current operations are located in South America, and unexpected problems can arise due to guerilla ~~activity;~~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; ~~the risk that~~our ability to raise capital; our ability to identify and complete successful acquisitions, including in new countries and basins from our current ~~global economic and credit conditions may impact oil prices and oil consumption more than we currently predict;~~operations; our ability to execute ~~its~~ business ~~plan; the risk that~~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; ~~the risk that~~ current global economic and credit market conditions and the regulatory environment may impact oil prices and oil consumption ~~more~~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 the continued listing of our shares on a national stock exchange; and those factors set out in Part II, Item 1A "Risk Factors" in this Quarterly Report on Form 10-Q and Part I, Item 1A “Risk Factors” in our ~~2016~~2020 Annual Report on Form 10-K (the "2020 Annual Report on Form 10-K"), and in our other filings with the Securities and Exchange Commission (“SEC”). The unprecedented nature of the COVID-19 pandemic and volatility in the worldwide economy and oil and gas industry makes, including the unpredictable nature of the resurgence of cases, possible variants and governmental responses, it more difficult to predict the accuracy of forward-looking statements. 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, or to withdraw, 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.



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

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

PART I - Financial Information

Item 1. Financial Statements

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations (Unaudited)

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
OIL SALES (Note 8)	$	135,319	$	53,142	$	327,435	$	173,045

EXPENSES
Operating	37,567		20,721		92,623		84,673
Transportation	3,021		1,286		8,448		8,549
COVID-19 related costs (Note 9)	990		1,108		3,026		1,529
Depletion, depreciation and accretion	38,055		31,340		98,300		131,118
Goodwill impairment (Note 5)	—		—		—		102,581
Asset impairment (Note 5)	—		104,731		—		507,093
General and administrative	6,497		4,562		25,072		16,476
Severance	—		122		919		1,469
Foreign exchange loss	2,650		4,275		15,824		20,094
Derivative instruments loss (gain) (Note 12)	2,603		(2,173)		47,540		(9,417)
Other financial instruments (gain) loss (Note 12)	(13,634)		1,460		(12,425)		61,286
Other loss	—		67		—		67
Interest expense (Note 6)	13,608		14,029		41,355		40,204
	91,357		181,528		320,682		965,722

INTEREST INCOME	—		—		—		345
INCOME (LOSS) BEFORE INCOME TAXES	43,962		(128,386)		6,753		(792,332)

INCOME TAX EXPENSE (RECOVERY)
Current (Note 10)	—		637		(14)		560
Deferred (Note 10)	8,955		(21,202)		26,809		(62,796)
	8,955		(20,565)		26,795		(62,236)
NET AND COMPREHENSIVE INCOME (LOSS)	$	35,007	$	(107,821)	$	(20,042)	$	(730,096)

NET INCOME (LOSS) PER SHARE

BASIC AND DILUTED	$	0.10	$	(0.29)	$	(0.05)	$	(1.99)

WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 7)	366,992,802		366,981,556		366,985,646		366,981,556
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 7)	367,740,722		366,981,556		366,985,646		366,981,556

(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)

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
OIL AND NATURAL GAS SALES (NOTE 3) $ 103,768
$ 68,539
$ 294,555
$ 197,655

EXPENSES
Operating 27,321
25,638
78,466
62,453
Transportation 6,038
5,773
19,472
24,318
Depletion, depreciation and accretion (Note 3) 34,492
35,729
92,729
104,525
Asset impairment (Notes 3 and 4) 787
319,974
1,239
469,715
General and administrative (Note 3) 8,651
5,592
26,876
20,614
Severance 1,164
—
1,164
1,299
Transaction —
6,088
—
7,325
Equity tax —
—
1,224
3,053
Foreign exchange (gain) loss (1,271 ) (507 ) 779
1,059
Financial instruments loss (gain) (Note 10) 1,675
2,051
(5,211 ) 1,824
Interest expense (Note 5) 3,989
5,122
10,415
7,842
82,846
405,460
227,153
704,027

LOSS ON SALE OF BRAZIL BUSINESS UNIT (NOTE 4) —
—
(9,076 ) —
GAIN ON ACQUISITION —
—
—

11,712
INTEREST INCOME 301
730
954
1,928
INCOME (LOSS) BEFORE INCOME TAXES (NOTE 3) 21,223
(336,191 ) 59,280
(492,732 )

INCOME TAX EXPENSE (RECOVERY)
Current 4,333
3,879
13,522
11,680
Deferred 13,760
(110,451 ) 36,664
(166,202 )

18,093
(106,572 ) 50,186
(154,522 )
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) $ 3,130
$ (229,619 ) $ 9,094
$ (338,210 )

NET INCOME (LOSS) PER SHARE - BASIC AND DILUTED $ 0.01
$ (0.71 ) $ 0.02
$ (1.11 )
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6) 394,771,194
321,725,379
397,439,007
304,098,944
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6) 394,774,953
321,725,379
397,450,637
304,098,944


	As at September 30, 2021		As at December 31, 2020

ASSETS
Current Assets
Cash and cash equivalents (Note 13)	$	16,600	$	14,114

Accounts receivable	26,431		8,044
Investment (Note 12)	44,116		48,323



Taxes receivable (Note 3)	47,772		49,925
Other current assets	17,141		13,459
Total Current Assets	152,060		133,865

Oil and Gas Properties
Proved	833,069		797,355
Unproved	158,483		161,763
Total Oil and Gas Properties	991,552		959,118
Other capital assets	3,085		5,364
Total Property, Plant and Equipment (Note 4)	994,637		964,482

Other Long-Term Assets
Deferred tax assets	13,349		57,318
Taxes receivable (Note 3)	14,447		42,635
Restricted cash and cash equivalents (Note 13)	3,532		3,409
Other	3,233		16
Total Other Long-Term Assets	34,561		103,378
Total Assets	$	1,181,258	$	1,201,725

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	114,785	$	100,784
Derivatives (Note 12)	14,737		12,050
Taxes payable (Note 3)	5,938		—
Equity compensation award liability (Note 7 and 12)	2,132		805
Total Current Liabilities	137,592		113,639

Long-Term Liabilities
Long-term debt (Notes 6 and 12)	735,411		774,770

Asset retirement obligation	54,356		48,214
Equity compensation award liability (Note 7 and 12)	11,469		3,955
Other long-term liabilities	3,563		4,113
Total Long-Term Liabilities	804,799		831,052

Contingencies (Note 11)	0		0

Shareholders' Equity
Common Stock (Note 7) (367,038,454 and 366,981,556 shares issued and outstanding of Common Stock, par value $0.001 per share, as at September 30, 2021, and December 31, 2020, respectively)	10,270		10,270
Additional paid-in capital	1,286,893		1,285,018
Deficit	(1,058,296)		(1,038,254)
Total Shareholders' Equity	238,867		257,034
Total Liabilities and Shareholders’ Equity	$	1,181,258	$	1,201,725

(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)~~

September 30, December 31,
2017 2016
ASSETS
Current Assets
Cash and cash equivalents (Note 11) $ 15,125
$ 25,175
Restricted cash and cash equivalents (Notes 7 and 11) 3,920
8,322
Accounts receivable 38,279
45,698
Derivatives (Note 10) 512
578
Inventory (Note 4) 6,978
7,766
Taxes receivable 34,879
26,393
Prepaid taxes (Note 2) —
12,271
Other prepaids 2,194
5,482
Total Current Assets 101,887
131,685

Oil and Gas Properties (using the full cost method of accounting)

Proved 508,981
412,319
Unproved 613,419
647,774
Total Oil and Gas Properties 1,122,400
1,060,093
Other capital assets 5,224
6,516
Total Property, Plant and Equipment (Notes 3 and 4) 1,127,624
1,066,609

Other Long-Term Assets

Deferred tax assets (Note 2) 66,963
1,611
Prepaid taxes (Note 2) —
41,784
Restricted cash and cash equivalents (Notes 7 and 11) 10,332
9,770
Other long-term assets 13,789
13,856
Goodwill (Note 3) 102,581
102,581
Total Other Long-Term Assets 193,665
169,602
Total Assets (Note 3) $ 1,423,176
$ 1,367,896
LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities

Accounts payable and accrued liabilities $ 119,829
$ 107,051
Derivatives (Note 10) 65
3,824
Taxes payable (Note 2) 2,419
38,939
Asset retirement obligation (Note 7) 355
5,215
Total Current Liabilities 122,668
155,029

Long-Term Liabilities

Long-term debt (Notes 5 and 10) 229,215
197,083
Deferred tax liabilities (Note 2) 29,368
107,230
Asset retirement obligation (Note 7) 43,649
38,142
Other long-term liabilities 13,816
11,425
Total Long-Term Liabilities 316,048
353,880

Contingencies (Note 9)

Shareholders’ Equity

Common Stock (Note 6) (386,872,530 and 390,807,194 shares of Common Stock and 7,898,664 and 8,199,894 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2017, and December 31, 2016, respectively) 10,299
10,303
Additional paid in capital 1,334,563
1,342,656
Deficit (360,402 ) (493,972 )
Total Shareholders’ Equity 984,460
858,987
Total Liabilities and Shareholders’ Equity $ 1,423,176
$ 1,367,896

~~(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,
2017 2016
Operating Activities
Net income (loss) $ 9,094
$ (338,210 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 3) 92,729
104,525
Asset impairment (Notes 3 and 4) 1,239
469,715
Deferred tax expense (recovery) 36,664
(166,202 )
Stock-based compensation (Note 6) 4,935
4,380
Amortization of debt issuance costs (Note 5) 1,868
2,813
Cash settlement of restricted share units (534 ) (1,210 )
Unrealized foreign exchange (gain) loss (304 ) 2,437
Financial instruments (gain) loss (Note 10) (5,211 ) 1,824
Cash settlement of financial instruments (Note 10) 1,518
438
Cash settlement of asset retirement obligation (Note 7) (462 ) (496 )
Loss on sale of Brazil business unit (Note 4) 9,076
—
Gain on acquisition —
(11,712 )
Net change in assets and liabilities from operating activities (Note 11) (28,105 ) 18,097
Net cash provided by operating activities 122,507
86,399

Investing Activities

Additions to property, plant and equipment (Note 3) (175,719 ) (69,667 )
Additions to property, plant and equipment - property acquisitions (Note 4) (30,410 ) (19,388 )
Net proceeds from sale of Brazil business unit (Note 4) 34,481
—
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit (Note 4) 4,700
—
Cash paid for business combinations, net of cash acquired —
(457,183 )
Proceeds from sale of marketable securities —
788
Changes in non-cash investing working capital 11,347
(8,036 )
Net cash used in investing activities (155,601 ) (553,486 )

Financing Activities

Proceeds from bank debt, net of issuance costs (Note 5) 115,264
220,169
Repayment of bank debt (Note 5) (85,000 ) (110,181 )
Proceeds from issuance of shares of Common Stock, net of issuance costs —
5,169
Repurchase of shares of Common Stock (Note 6) (10,000 ) —
Proceeds from issuance of subscription receipts, net of issuance costs —
165,805
Proceeds from issuance of Convertible Senior Notes, net of issuance costs (Note 5) —
109,090
Net cash provided by financing activities 20,264
390,052

Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents (1,060 ) (452 )

Net decrease in cash, cash equivalents and restricted cash and cash equivalents (13,890 ) (77,487 )
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 11) 43,267
148,751
Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 11) $ 29,377
$ 71,264

Supplemental cash flow disclosures (Note 11)

~~(See notes to the condensed consolidated financial statements)~~

~~Gran Tierra Energy Inc.~~

~~Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)~~

~~(Thousands of U.S. Dollars)~~

Nine Months Ended September 30, Year Ended December 31,
2017 2016
Share Capital
Balance, beginning of period $ 10,303
$ 10,186
Issuance of Common Stock —
117
Repurchase of Common Stock (Note 6) (4 ) —
Balance, end of period 10,299
10,303

Additional Paid in Capital

Balance, beginning of period 1,342,656
1,019,863
Issuance of Common Stock, net of share issuance costs —
314,425
Exercise of stock options —
5,347
Stock-based compensation (Note 6) 1,903
3,021
Repurchase of Common Stock (Note 6) (9,996 ) —
Balance, end of period 1,334,563
1,342,656

Deficit

Balance, beginning of period (493,972 ) (28,407 )
Net income (loss) 9,094
(465,565 )
Cumulative adjustment for accounting change related to tax reorganizations
(Note 2)
124,476
—
Balance, end of period (360,402 ) (493,972 )

Total Shareholders’ Equity $ 984,460
$ 858,987


	Nine Months Ended September 30,
	2021		2020
Operating Activities
Net loss	$	(20,042)	$	(730,096)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion	98,300		131,118
Goodwill impairment (Note 5)	—		102,581
Asset impairment (Note 5)	—		507,093
Deferred tax expense (recovery)	26,809		(62,796)
Stock-based compensation expense (recovery) (Note 7)	6,597		(707)
Amortization of debt issuance costs (Note 6)	2,682		2,774
Unrealized foreign exchange loss	16,945		22,335
Derivative instruments loss (gain) (Note 12)	47,540		(9,417)
Cash settlements on derivatives instruments	(45,041)		9,970
Other financial instruments (gain) loss (Note 12)	(12,425)		61,286
Other non-cash loss	—		2,026
Cash settlement of asset retirement obligation	(483)		(199)
Non-cash lease expenses	1,222		1,494
Lease payments	(1,239)		(1,404)
Net change in assets and liabilities from operating activities (Note 13)	17,956		23,288
Net cash provided by operating activities	138,821		59,346

Investing Activities
Additions to property, plant and equipment	(109,650)		(56,378)
Proceeds on disposition of investment, net of transaction costs (Note 12)	14,632		—
Changes in non-cash investing working capital (Note 13)	709		(69,549)
Net cash used in investing activities	(94,309)		(125,927)

Financing Activities
Proceeds from debt, net of issuance costs (Note 6)	(125)		88,382
Repayment of debt (Note 6)	(40,000)		(7,000)

Proceeds from exercise of stock options	19		—
Lease payments	(1,269)		(307)
Net cash (used in) provided by financing activities	(41,375)		81,075

Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(528)		(754)

Net increase in cash, cash equivalents and restricted cash and cash equivalents	2,609		13,740
Cash, cash equivalents and restricted cash and cash equivalents, beginning of period (Note 13)	17,523		11,075
Cash, cash equivalents and restricted cash and cash equivalents, end of period (Note 13)	$	20,132	$	24,815

Supplemental cash flow disclosures (Note 13)

(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,
	2021		2020		2021		2020
Share Capital
Balance, beginning of period	$	10,270	$	10,270	$	10,270	$	10,270

Balance, end of period	10,270		10,270		10,270		10,270

Additional Paid-in Capital
Balance, beginning of period	1,286,235		1,283,798		1,285,018		1,282,627

Exercise of stock options	10		—		18		—

Stock-based compensation (Note 7)	648		607		1,857		1,778
Balance, end of period	1,286,893		1,284,405		1,286,893		1,284,405

Deficit
Balance, beginning of period	(1,093,303)		(882,562)		(1,038,254)		(260,287)
Net income (loss)	35,007		(107,821)		(20,042)		(730,096)
Balance, end of period	(1,058,296)		(990,383)		(1,058,296)		(990,383)

Total Shareholders' Equity	$	238,867	$	304,292	$	238,867	$	304,292

(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”~~"Company" or ~~“Gran Tierra”~~"Gran Tierra"), is a publicly traded company focused on international oil and natural gas exploration and production with assets currently in ~~Colombia. The Company also has business activities in Peru~~Colombia and ~~until June 30, 2017, had business activities in Brazil.~~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”~~("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~~Company's consolidated financial statements as at and for the year ended December 31, ~~2016,~~2020, included in the ~~Company’s 2016~~Company's 2020 Annual Report on Form ~~10-K, filed with the SEC on March 1, 2017.~~10-K.

The ~~Company’s~~Company's significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the ~~Company’s 2016~~Company's 2020 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial ~~statements, except as noted below.~~statements. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

~~Recently Adopted Accounting Pronouncements~~

3. Taxes Receivable and Payable

~~Simplifying the Measurement of Inventory~~

In July 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-11, “Simplifying the Measurement of Inventory". The ASU provides guidance for the subsequent measurement of inventory and requires that inventory that is measured using average cost be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

~~Employee Share-Based Payment Accounting~~

~~In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting~~". This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company elected to continue to estimate the total number of awards for which the requisite service period will not be rendered. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

~~Income Taxes - Intra-Entity Transfers of Assets Other than Inventory~~

At December 31, 2016, GAAP prohibited the recognition of current and deferred income taxes for intra-entity transfers until an asset leaves the consolidated group, therefore, the current income tax effect of tax reorganizations completed in 2016 was deferred and recognized as prepaid income taxes. At December 31, 2016, the Company's balance sheet included $54.1 million of prepaid income taxes, $12.3 million in current prepaid taxes and $41.8 million in long-term prepaid taxes, and $37.5 million of current income taxes payable relating to tax reorganizations completed in 2016.

In October 2016, the FASB issued ASU 2016-16, "Intra-Entity Transfers of Assets Other than Inventory." This ASU requires companies to recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the income statement as income tax expense or benefit in the period the sale or transfer occurs. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption was permitted as of the beginning of an annual reporting period. The ASU is required to be applied on a modified retrospective basis with a cumulative-effect adjustment directly to retained earnings in the period of adoption. The Company early adopted this ASU on January 1, 2017, and in the three months ending March 31, 2017, wrote off the income tax effects that had been deferred from past intercompany transactions to opening deficit. Prepaid tax of $54.1 million and deferred tax assets of $178.6 million were recorded directly to opening deficit at January 1, 2017. Deferred tax assets recorded upon adoption were assessed for realizability under Accounting Standards Codification ("ASC") 740 "Income Taxes", and, valuation allowances were recognized on those deferred tax assets as necessary on the date of adoption. The adoption of ASU 2016-16 did not have any effect on the Company’s cash flows.

~~Restricted Cash and Cash Equivalents~~

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash". ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted. The Company early adopted this ASU on January 1, 2017, on a retrospective basis to each period presented. The implementation of this ASU did not impact the Company's consolidated financial position or results of operations. For the nine months ended September 30, 2016, the net decrease in cash, cash equivalents and restricted cash and cash equivalents currently disclosed was $77.5 million, compared with the net decrease in cash and cash equivalents of $97.3 million as previously disclosed in the consolidated statement of cash flows prior to the adoption of ASU 2016-18.

~~Clarifying the Definition of a Business~~

In January 2017, the FASB issued ASU 2017-01, "Clarifying the Definition of a Business". ASU 2017-01 narrows the definition of a business and provides a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. ASU 2017-01 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted and the Company adopted this ASU on January 1, 2017. The Company now applies an initial screen for determining whether a transaction involves an asset or a business. When substantially all of the fair value of the gross assets acquired is concentrated in a single identified asset, or group of similar identifiable assets, the set will not be a business and no goodwill or gain on acquisition will be recognized. If the screen is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create an output. The Company’s acquisition of the Santana and Nancy Burdine-Maxine oil and gas properties in the nine months ended September 30, 2017 was not considered a business under this ASU and therefore not allocated goodwill or gain on acquisition (Note 4).

~~Simplifying the Test for Goodwill Impairment~~

In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment". ASU 2017-04 eliminates step 2 of the goodwill impairment test. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2019. Early adoption is permitted. At September 30, 2017, the Company performed a qualitative assessment of goodwill and, based on this assessment, no impairment of goodwill was identified. The Company did not have to perform step 2 of the goodwill impairment test.

~~Recently Issued Accounting Pronouncements~~

~~Revenue from Contracts with Customers~~

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers - Deferral of the Effective Date". The ASU deferred the effective date of the new revenue recognition model by one year. As a result, the guidance will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. In March 2016, the FASB issued ASU 2016-08,

“Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" which clarifies implementation guidance on principal versus agent considerations. In April, May and December 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing", ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients" and ASU 2016-20 "Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers", respectively, which addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings.

The ~~Company is continuing to evaluate~~table below shows the ~~impact~~break-down of ~~the ASU~~taxes receivable and currently expects that the standard will not have a material impact on the Company’s consolidated financial statements other than enhanced disclosures related to revenues from contracts with customers. The Company intends to adopt the new standard using the modified retrospective method at the datepayable, which are comprised of ~~adoption, which is expected to be January 1, 2018.~~value added tax ("VAT") and income tax:


(Thousands of U.S. Dollars)	As at September 30, 2021		As at December 31, 2020
Taxes Receivable
Current
VAT Receivable	$	31,890	$	35,977
Income Tax Receivable	15,882		13,948
	$	47,772	$	49,925
Long-Term
VAT Receivable	$	—	$	28,485
Income Tax Receivable	14,447		14,150
	$	14,447	$	42,635

Taxes Payable
Current
VAT Payable	$	5,938	$	—

Total Taxes Receivable net of Taxes Payable	$	56,281	$	92,560

~~3. Segment and Geographic Reporting~~

The Company is primarily engaged in the exploration and production of oil and natural gas. The Company’s reportable segments are Colombia and Peru, based on geographic organization. Prior to the sale of the Company’s Brazil business unit effective June 30, 2017, (Note 4), Brazil was a reportable segment. The All Other category represents the Company’s corporate and Mexico activities. The Company evaluates reportable segment performance based on income or loss before income taxes.

The following ~~tables present information~~table shows the movement of VAT and income tax receivables for the period identified below:


(Thousands of U.S. Dollars)	Net VAT Receivable		Income Tax Receivable		Total Net Taxes Receivable
Balance, as at December 31, 2020	$	64,462	$	28,098	$	92,560
Collected through direct government refunds	(518)		(14,228)		(14,746)
Collected through sales contracts	(70,881)		—		(70,881)
Taxes paid (1)	38,278		19,923		58,201

Foreign exchange loss	(5,389)		(3,464)		(8,853)
Balance, as at September 30, 2021	$	25,952	$	30,329	$	56,281

(1)VAT is paid on ~~the Company’s reportable segments~~certain goods and ~~other activities:~~services in Colombia at a rate of 19%

Three Months Ended September 30, 2017
(Thousands of U.S. Dollars) Colombia Peru Brazil All Other Total
Oil and natural gas sales $ 103,768
$ —
$ —
$ —
$ 103,768
Depletion, depreciation and accretion 33,388
881
—
223
34,492
Asset impairment —
176
—
611
787
General and administrative expenses 5,500
301
—
2,850
8,651
Income (loss) before income taxes 31,276
(1,405 ) —
(8,648 ) 21,223
Segment capital expenditures 70,606
998
—
90
71,694

Three Months Ended September 30, 2016
(Thousands of U.S. Dollars) Colombia Peru Brazil All Other Total
Oil and natural gas sales $ 65,944
$ —
$ 2,595
$ —
$ 68,539
Depletion, depreciation and accretion 34,156
206
1,022
345
35,729
Asset impairment 298,370
—
21,604
—
319,974
General and administrative expenses 1,921
218
218
3,235
5,592
Loss before income taxes (299,306 ) (768 ) (20,977 ) (15,140 ) (336,191 )
Segment capital expenditures
20,476
1,360
3,102
142
25,080

Nine Months Ended September 30, 2017
(Thousands of U.S. Dollars) Colombia Peru Brazil All Other Total
Oil and natural gas sales $ 286,137
$ —
$ 8,418
$ —
$ 294,555
Depletion, depreciation and accretion 88,453
1,350
2,263
663
92,729
Asset impairment —
628
—
611
1,239
General and administrative expenses 15,561
974
743
9,598
26,876
Income (loss) before income taxes 90,018
(2,685 ) 3,369
(31,422 ) 59,280
Segment capital expenditures 168,881
3,207
2,811
820
175,719

Nine Months Ended September 30, 2016
(Thousands of U.S. Dollars) Colombia Peru Brazil All Other Total
Oil and natural gas sales $ 191,515
$ —
$ 6,140
$ —
$ 197,655
Depletion, depreciation and accretion 100,350
418
2,764
993
104,525
Asset impairment 431,810
899
37,006
—
469,715
General and administrative expenses 9,614
1,014
751
9,235
20,614
Loss before income taxes (436,863 ) (2,224 ) (36,523 ) (17,122 ) (492,732 )
Segment capital expenditures 56,997
3,730
7,982
958
69,667

As at September 30, 2017
(Thousands of U.S. Dollars) Colombia Peru Brazil All Other Total
Property, plant and equipment $ 1,054,136
$ 70,903
$ —
$ 2,585
$ 1,127,624
Goodwill 102,581
—
—
—
102,581
All other assets 176,672
11,103
—
5,196
192,971
Total Assets $ 1,333,389
$ 82,006
$ —
$ 7,781
$ 1,423,176

As at December 31, 2016
(Thousands of U.S. Dollars) Colombia Peru Brazil All Other Total
Property, plant and equipment $ 939,947
$ 68,428
$ 55,196
$ 3,038
$ 1,066,609
Goodwill 102,581
—
—
—
102,581
All other assets 177,393
10,848
1,619
8,846
198,706
Total Assets $ 1,219,921
$ 79,276
$ 56,815
$ 11,884
$ 1,367,896

4. Property, Plant and Equipment


(Thousands of U.S. Dollars)	As at September 30, 2021		As at December 31, 2020
Oil and natural gas properties
Proved	$	4,236,548	$	4,106,768
Unproved	158,483		161,763
	4,395,031		4,268,531
Other(1)	32,779		32,135
	4,427,810		4,300,666
Accumulated depletion and depreciation and impairment	(3,433,173)		(3,336,184)
	$	994,637	$	964,482

(1) The "other" category includes right-of-use assets for operating and ~~Inventory~~finance leases of $11.7 million, which had a net book value of $2.5 million as at September 30, 2021 (December 31, 2020 - $11.4 million which had a net book value of $4.4 million).

~~Property, Plant and Equipment~~

5. Impairment

(Thousands of U.S. Dollars) As at September 30, 2017 As at December 31, 2016
Oil and natural gas properties
Proved $ 2,836,263
$ 2,652,171
Unproved 613,419
647,774
3,449,682
3,299,945
Other 27,236
29,445
3,476,918
3,329,390
Accumulated depletion, depreciation and impairment (2,349,294 ) (2,262,781 )
$ 1,127,624
$ 1,066,609

Asset impairment ~~for~~

(i) Oil and gas property impairment

For the three and nine months ended September 30, ~~2017, and 2016 was as follows:~~

Three Months Ended September 30, Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2016 2017 2016
Impairment of oil and gas properties $ 787
$ 319,974
$ 1,239
$ 469,051
Impairment of inventory —
—
—
664
$ 787
$ 319,974
$ 1,239
$ 469,715

The Company follows the full cost method of accounting for its oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, adjusted for related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that this estimate of future net revenues represent the fair market value of the Company's reserves. In accordance with GAAP, Gran Tierra used an average Brent price of $52.70 per bbl for the purposes of the September 30, 2017 ceiling test calculations (June 30, 2017 - $51.35; March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48; March 31, 2016 - $48.79; December 31, 2015 - $54.08).

~~Acquisition of Santana and Nancy Burdine-Maxine Blocks~~

On April 27, 2017, the Company acquired the Santana and Nancy-Burdine-Maxine Blocks in the Putumayo Basin for cash consideration of $30.4 million. The acquisition was accounted for as an asset acquisition with the consideration paid allocated on a relative fair value basis to the net assets acquired.

~~The following table shows the allocation of the cost of the acquisition based on the relative fair values of the assets and~~

~~liabilities acquired:~~

(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash $ 30,410

Allocation of Consideration Paid:
Oil and gas properties
Proved $ 24,405
Unproved 8,649
33,054
Inventory 869
Asset retirement obligation - long-term (3,513 )
$ 30,410

~~Disposition of Brazil Business Unit~~

On June 30, 2017, the Company, through two of its indirect subsidiaries (the “Selling Subsidiaries”), completed the previously announced disposition of its assets in Brazil. Gran Tierra completed the disposition of its Brazil business unit for a purchase price of $35.0 million which, after certain interim closing adjustments, resulted in cash consideration paid to the Selling Subsidiaries of approximately $38.0 million.

~~At December 31, 2016, assets and liabilities of the Brazil business unit were as follows:~~

(Thousands of U.S. Dollars) As at December 31, 2016
Current assets $ 1,634
Property, plant and equipment 55,376
$ 57,010

Current liabilities $ (11,590 )
Long-term liabilities (2,297 )
$ (13,887 )

~~At June 30, 2017, the net book value of the Brazil business unit was greater than the proceeds received resulting in a $9.1 million loss on sale.~~

Gran Tierra also received a $4.7 million cash payment from the purchaser reflecting the covenant by the purchaser to finalize the documentation and other arrangements to assume liabilities associated with letter of credit arrangements and the release of Gran Tierra from any liabilities in connection with the same, which payment will be reimbursable to the purchaser once such covenant is discharged.

~~Inventory~~

~~At September 30, 2017, oil and supplies inventories were $4.5 million and $2.5 million, respectively (December 31, 2016 - $6.0 million and $1.8 million, respectively). At September 30, 2017,~~2021, the Company had ~~168 Mbbl of oil inventory (December 31, 2016 - 208 Mbbl). In~~no ceiling test impairment losses. For each of the three and nine months ended September 30, ~~2017,~~2020, Gran Tierra had $104.7 million and $502.9 million of ceiling test impairment losses. The Company used an average Brent price of $60.12 and $47.95 per bbl for the ~~Company recorded oil inventory~~September 30, 2021 and 2020, ceiling test calculations, respectively.

(ii) Inventory impairment ~~of $nil (three~~

For the three and nine months ended September 30, ~~2016 - $nil and $0.7 million, respectively) related to lower oil prices.~~

~~5. Debt and Interest Expense~~

~~At September 30, 2017,~~2021, the Company had ~~a revolving credit facility with a syndicate~~no inventory impairment. For the three and nine months ended September 30, 2020, the Company recorded $0.1 million and $4.2 million, respectively, of ~~lenders with a borrowing base~~inventory impairment.

Goodwill impairment

The entire goodwill balance of ~~$300 million. Availability under~~$102.6 million was impaired during the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. As a result of the semi-annual redetermination, the committed borrowing base was increased from $250 million to $300 million effective June 1, 2017. The next re-determination of the borrowing base isnine months ended September 30, 2020, due to ~~occur no later than November 2017. On September 18, 2017,~~ the ~~Company entered into the Eighth Amendment~~reporting unit's carrying value exceeding its fair value due to the ~~credit agreement with the other parties thereto, which, among other things, extended the maturity date~~impact of ~~the borrowings under the revolving credit facility from September 18, 2018, to October 1, 2018.~~lower forecasted commodity prices.

6. Debt and Debt Issuance Costs

The Company's debt at September 30, ~~2017,~~2021, and December 31, ~~2016,~~2020, was as follows:


(Thousands of U.S. Dollars)	As at September 30, 2017			As at December 31, 2016			(Thousands of U.S. Dollars)	As at September 30, 2021		As at December 31, 2020
Convertible senior notes	$	115,000		$	115,000
6.25% Senior Notes, due February 2025							6.25% Senior Notes, due February 2025	$	300,000	$	300,000
7.75% Senior Notes, due May 2027							7.75% Senior Notes, due May 2027	300,000		300,000
Revolving credit facility	120,000			90,000			Revolving credit facility	150,000		190,000
Unamortized debt issuance costs	(5,785		)	(7,917		)	Unamortized debt issuance costs	(15,566)		(18,124)
Long-term debt	$	229,215		$	197,083		Long-term debt	734,434		771,876
Long-term lease obligation(1)							Long-term lease obligation(1)	977		2,894
								$	735,411	$	774,770

(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 $2.9 million as at September 30, 2021 (December 31, 2020 - $3.3 million).

As at September 30, 2021, the borrowing base of the Company's Senior Secured Credit Facility (the "revolving credit facility") was $215 million. The maturity date of the revolving credit facility is October 2022 and the next re-determination to occur no later than November 2021.

The Company is required to comply with various covenants, which were modified in response to market conditions including the COVID-19 pandemic until October 1, 2021 ("the covenant relief period"). During the covenant relief period, the Company's ratio of total debt to Covenant EBITDAX ("EBITDAX") was permitted to be greater than 4.0 to 1.0, Senior Secured Debt to EBITDAX ratio could not exceed 2.5 to 1.0, and EBITDAX to interest expense ratio for the trailing four-quarter periods measured as of the last day of the fiscal quarter ended September 30, 2021, was required to be 2.0 to 1.0. As of September 30, 2021, the Company was in compliance with all applicable covenants in the revolving credit facility.

Commencing on October 1, 2021, the Company must maintain compliance with the following financial covenants: limitations on Company's ratio of debt to EBITDAX to a maximum of 4.0 to 1.0; limitations on Company's ratio of Senior Secured Debt to EBITDAX to a maximum of 3.0 to 1.0; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. If the Company fails to comply with these financial covenants, it would result in a default under the terms of the credit agreement, which could result in an acceleration of repayment of all indebtedness under the Company's revolving credit facility.

Amounts drawn down under the revolving credit facility bear interest, at the Company's option, at the USD LIBOR rate plus a

margin ranging from 2.90% to 4.90%, or an alternate base rate plus a margin ranging from 1.90% to 3.90%, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. We pay a commitment fee on undrawn amounts under the revolving credit facility, which ranges from 0.73% to 1.23% per annum, based on the average daily amount of unused commitments.

The Company's revolving credit facility is guaranteed by and secured against the assets of certain of the Company's subsidiaries (the "Credit Facility Group"). Under the terms of the revolving credit facility, the Company is subject to certain restrictions on its ability to distribute funds to entities outside of the Credit Facility Group, including restrictions on the ability to pay dividends to shareholders of the Company.

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)	2021		2020		2021		2020
Contractual interest and other financing expenses	$	12,701	$	13,191	$	38,673	$	37,430
Amortization of debt issuance costs	907		838		2,682		2,774
	$	13,608	$	14,029	$	41,355	$	40,204

Three Months Ended September 30, Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2016 2017 2016
Contractual interest and other financing expenses $ 3,346
$ 2,938
$ 8,547
$ 5,029
Amortization of debt issuance costs 643
2,184
1,868
2,813
$ 3,989
$ 5,122
$ 10,415
$ 7,842

6.7. Share Capital


			Shares of Common Stock
Balance, December 31, 2020			366,981,556
Shares issued on option exercise			56,898
Balance, September 30, 2021			367,038,454

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

Shares of Common Stock Exchangeable Shares of Gran Tierra Exchangeco Inc. Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2016 390,807,194
4,812,592
3,387,302
Shares repurchased and canceled (4,235,890 ) —
—
Exchange of exchangeable shares 301,230
(142,500 ) (158,730 )
Shares canceled (4 ) —
—
Balance, September 30, 2017 386,872,530
4,670,092
3,228,572

On February 6, 2017, the Company announced that it had implemented a new share repurchase program (the “2017 Program”) through the facilities of the Toronto Stock Exchange ("TSX"), the NYSE American and eligible alternative trading platforms in Canada and the United States. Under the 2017 Program, the Company is able to purchase at prevailing market prices up to 19,540,359 shares of Common Stock, representing 5.0% of the issued and outstanding shares of Common Stock as of January 27, 2017. Shares purchased pursuant to the 2017 Program will be canceled. The 2017 Program will expire on February 7, 2018, or earlier if the 5.0% share maximum is reached.

Equity Compensation Awards

The following table provides information about performance stock units (“PSUs”), deferred share units (“DSUs”), ~~restricted stock units (“RSUs”)~~ and stock option activity for the nine months ended September 30, ~~2017~~:2021:


	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, 2020	23,273,404	4,067,897	15,444,949	1.50
Granted	13,428,840	1,310,122	5,834,014	0.80
Exercised	(2,733,209)	—	(56,898)	0.33
Forfeited	(3,492,165)	—	(1,628,591)	0.90
Expired	—	—	(1,279,641)	3.17
Balance, September 30, 2021	30,476,870	5,378,019	18,313,833	1.22

PSUs DSUs RSUs Stock Options
Number of Outstanding Share Units Number of Outstanding Share Units Number of Outstanding Share Units Number of Outstanding Stock Options Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2016 3,362,717
208,698
359,145
9,239,478
4.16
Granted 3,229,620
171,388
—
1,964,156
2.54
Exercised —
—
(211,022 ) —
—
Forfeited (641,159 ) —
(9,402 ) (903,910 ) (4.81 )
Expired —
—
—
(1,396,667 ) (4.65 )
Balance, September 30, 2017 5,951,178
380,086
138,721
8,903,057
3.66

~~Stock-based compensation expense for~~For the three and nine months ended September 30, ~~2017,~~2021, stock-based compensation expense was ~~$1.8~~$1.1 million and ~~$4.9~~$6.6 million, respectively ~~and was primarily recorded in general and administrative ("G&A") expenses~~ (three and nine months ended September 30, ~~2016 - $0.9~~2020, expense of $0.1 million and ~~$4.4~~recovery of $0.7 million, respectively).

At September 30, ~~2017~~,2021, there was ~~$11.5~~$14.2 million (~~December~~ (December 31, ~~2016~~2020 - ~~$10.0~~$5.9 million) of unrecognized compensation ~~cost~~costs related to unvested PSUs ~~RSUs~~ and stock options, which is expected to be recognized over a ~~weighted average~~weighted-average period of ~~1.7~~1.8 years. During the nine months ended September 30, 2021, the Company paid out $0.6 million for PSUs vested on December 31, 2020 (nine months ended September 30, 2020 - $3.2 million for PSUs vested on December 31, 2019).

Net Income (Loss) per Share

Basic net income (loss) per share is calculated by dividing net income (loss) attributable to common shareholders by the weighted average number of shares of ~~Common Stock and exchangeable shares~~common stock issued and outstanding during each period.

Diluted net income (loss) per share is calculated ~~by adjusting~~using the treasury stock method for share-based compensation arrangements. The treasury stock method assumes that any proceeds obtained on the exercise of share-based compensation arrangements would be used to purchase common shares at the average market price during the period. The weighted average number of shares ~~of Common Stock and exchangeable shares outstanding for~~is then adjusted by the ~~dilutive effect, if any, of share equivalents. The Company uses~~difference between the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume weighted average trading pricenumber of shares issued from the exercise of ~~Common Stock during~~share-based compensation arrangements and shares repurchased from the ~~period.~~related proceeds. Anti-dilutive shares represent potentially dilutive securities 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,
	2021	2020	2021	2020
Weighted average number of common shares outstanding	366,992,802	366,981,556	366,985,646	366,981,556
Shares issuable pursuant to stock options	1,574,305	—	—	—
Shares assumed to be purchased from proceeds of stock options	(826,385)	—	—	—
Weighted average number of diluted common shares outstanding	367,740,722	366,981,556	366,985,646	366,981,556

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Weighted average number of common and exchangeable shares outstanding 394,771,194
321,725,379
397,439,007
304,098,944
Shares issuable pursuant to stock options 61,325
—
187,150
—
Shares assumed to be purchased from proceeds of stock options (57,566 ) —
(175,520 ) —
Weighted average number of diluted common and exchangeable shares outstanding 394,774,953
321,725,379
397,450,637
304,098,944

For the three months ended September 30, ~~2017, 9,259,811~~2021, 16,362,882 options, on a weighted average basis (three months ended September 30, ~~2016~~2020 - ~~9,084,162~~all options), were excluded from the diluted income (loss) per share calculation as the options were anti-dilutive. For the nine months ended September 30, ~~2017, 9,744,747~~2021 and 2020, all options on a weighted average basis ~~(nine months ended September 30, 2016 - 11,155,962 options)~~ were excluded from the diluted ~~income (loss)~~loss per share calculation as the options were anti-dilutive. ~~Shares issuable~~

8. Revenue

The Company's revenues are generated from oil sales at prices that reflect the blended prices received upon ~~conversion~~shipment by the purchaser at defined sales points or 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, 2021, 100% (three and nine months ended September 30, 2020 - 100%) of the ~~5.00% Convertible Senior Notes due~~Company's revenue resulted from oil sales. During the three and nine months ended September 30, 2021, ~~("Notes")~~quality and transportation discounts were ~~anti-dilutive~~16% and ~~excluded from~~15%, respectively, of the ~~diluted income (loss) per share calculation.~~average ICE Brent price (three and nine months ended September 30, 2020 - 22% and 27%, respectively). During the three and nine months ended September 30, 2021, the Company's production was sold primarily to two major customers in Colombia (three and nine months ended September 30, 2020 - two).

~~7. Asset Retirement Obligation~~As at September 30, 2021, accounts receivable included NaN of accrued sales revenue related to September 2021 production (December 31, 2020 - $0.1 million related to December 2020 production).

~~Changes~~

9. COVID-19 Costs

The COVID-19 pandemic has resulted in additional ongoing operating and transportation costs related to COVID-19 health and safety preventative measures, including incremental sanitation requirements and enhanced procedures for trucking barrels and crew changes in the ~~carrying amounts~~field. Below is a break-down of the ~~asset retirement obligation associated with~~costs:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021		2020		2021		2020
Operating expenses	$	881	$	1,012	$	2,743	$	1,433
Transportation costs	109		96		283		96
Total COVID-19 costs	$	990	$	1,108	$	3,026	$	1,529

10. Taxes

The Company's effective tax rate was 397% for the ~~Company’s oil~~nine months ended September 30, 2021, compared to 8% in the comparative period of 2020. Current income tax was in a recovery position for the nine months ended September 30, 2021, versus an expense position for the comparative period in 2020, primarily as a result of changes in the previous estimation of presumptive minimum tax. The deferred income tax expense for the nine months ended September 30, 2021, resulted from excess tax depreciation compared to accounting depreciation and ~~natural gas properties were as follows:~~the use of tax losses to offset taxable income in Colombia. The deferred income tax recovery in the comparative period of 2020 was mainly the result of a ceiling test impairment loss in Colombia, partially offset by losses incurred in Colombia that are now fully offset by a valuation allowance.

Nine Months Ended Year Ended
(Thousands of U.S. Dollars) September 30, 2017 December 31, 2016
Balance, beginning of period $ 43,357
$ 33,224
Liability incurred 2,942
2,606
Liabilities assumed in acquisition 3,513
15,723
Accretion 3,101
2,789
Settlements (1,039 ) (872 )
Liabilities associated with assets sold (2,200 ) (3,257 )
Revisions in estimated liability (5,670 ) (6,856 )
Balance, end of period $ 44,004
$ 43,357

Asset retirement obligation - current $ 355
$ 5,215
Asset retirement obligation - long-term 43,649
38,142
$ 44,004
$ 43,357

For the nine months ended September 30, ~~2017, settlements included $0.5 million cash payments with~~2021, the balance in accounts payable and accrued liabilities at September 30, 2017. Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives anddifference between the expected timing of settling asset retirement obligations. At September 30, 2017, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $12.6 million (December 31, 2016 - $12.0 million). These assets are accounted for as restricted cash and cash equivalents on the Company's interim unaudited condensed consolidated balance sheets.

~~8. Taxes~~

~~The Company's~~ effective tax rate of 397% and the 31% Colombian tax rate was ~~85%~~primarily due to the non-deductibility of derivative instrument losses and financing costs; foreign currency translation adjustments, and stock based compensation. These were partially offset by a decrease in the valuation allowance and the non-taxable portion (50%) of the unrealized gain on PetroTal Corp. ("PetroTal") shares.

In the third quarter of 2021, Congressional authorities in Colombia enacted a new tax legislation, which includes an increase to the corporate income tax rate to 35% from 31%, effective January 1, 2022. Accordingly, the tax rates applied to the calculation of deferred income taxes, before valuation allowance, have been adjusted to reflect this change.

For the nine months ended September 30, ~~2017, compared with 31% in~~2020, the ~~corresponding period in 2016. The Company's~~difference between the effective tax rate ~~differed from~~of 8% and the ~~U.S. statutory~~32% Colombian tax rate ~~of 35%~~was primarily due to

~~impact of foreign taxes,~~ an increase in the valuation allowance, the non-deductibility of goodwill impairment for tax purposes, foreign translation adjustments and the non-deductible ~~third-party royalty in Colombia, stock-based compensation and other local taxes. These items were partially offset by foreign currency translation adjustments.~~ portion (50%) of the unrealized loss on PetroTal Corp. ("PetroTal") shares.

9.11. Contingencies

~~The~~Legal Proceedings

Gran Tierra has a number of lawsuits and claims pending, including a dispute with 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~~relating 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 $49.8 million as at ~~September 30, 2017. At this time no amount has been accrued in the interim unaudited condensed consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.~~

~~In addition to the above, the Company has a number of other lawsuits and claims pending.~~high price share royalties. Although the outcome of these ~~other~~ lawsuits and disputes cannot be predicted with certainty, ~~the Company~~Gran Tierra believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Gran Tierra records costs ~~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, ~~2017~~,2021, the Company had provided letters of credit and other credit support totaling ~~$74.5~~$102.4 million (December 31, ~~2016~~2020 - ~~$96.8~~$100.6 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts and other capital or operating requirements.

~~10.~~12. Financial Instruments and Fair Value Measurement

Financial Instruments

At September 30, ~~2017~~,2021, the Company’s financial instruments recognized inon the balance sheet ~~consist of:~~consisted of cash and cash ~~equivalents;~~equivalents, restricted cash and cash ~~equivalents;~~equivalents, accounts ~~receivable; derivatives,~~receivable, investment, other long-term assets, accounts payable and accrued liabilities, derivatives, equity compensation award liability, long-term debt, ~~PSU liability included in other long-term liabilities, and RSU liability included in accounts payable and accrued liabilities~~ and other long-term liabilities.

Fair Value Measurement

The fair value of investment, derivatives, and ~~RSU and PSU liabilities are being~~equity compensation award liability is remeasured atto the estimated fair value at the end of each reporting period.

Investment in PetroTal

The estimated fair value of the Company's investment in PetroTal was $44.1 million at September 30, 2021 ($48.3 million at December 31, 2020), based on the closing stock price of PetroTal of $0.41 CAD ($0.25 CAD at December 31, 2020) and the foreign exchange rate at that date. During the nine months ended September 30, 2021, the Company sold 44% (109 million common shares) of its interest in PetroTal for cash proceeds net of transaction costs of $14.6 million, resulting in a loss on sale of $5.1 million. 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. PetroTal's shares are listed on the Toronto Stock Exchange Venture under the trading symbol 'TAL' and on the London Stock Exchange Alternative Investment Market under the trading symbol 'PTAL'. As at September 30, 2021, Gran Tierra holds approximately 137 million common shares representing approximately 17% of PetroTal's issued and outstanding common shares.

Commodity and Foreign Currency Derivatives

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.

PSUs and DSUs

The estimated fair value of the ~~RSU~~PSUs liability ~~was estimated~~is based on ~~quoted market prices in an active market. The fair value of the PSU liability was estimated based on~~a pricing model using inputs such as quoted market prices in an active market and ~~an option pricing model such as the Monte Carlo simulation option-pricing models.~~

PSUs performance factor. The fair value of DSUs liability is measured using quoted market prices in an active market.

The fair value of investment, derivatives, and ~~RSU, PSU~~PSUs and ~~DSU liabilities~~DSUs liability at September 30, ~~2017~~,2021, and December 31, ~~2016, were~~2020, was as follows:


(Thousands of U.S. Dollars)	As at September 30, 2021		As at December 31, 2020
Investment	$	44,116	$	48,323



Derivative liability	$	14,737	$	12,050
PSUs and DSUs liability	13,601		4,760
	$	28,338	$	16,810

(Thousands of U.S. Dollars) As at September 30, 2017 As at December 31, 2016
Foreign currency derivative asset $ 512
$ 578

Commodity price derivative liability $ 65
$ 3,824
RSU, PSU and DSU liability 6,851
3,907
$ 6,916
$ 7,731

The following table presents gains or losses on derivatives and other 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)	2021		2020		2021		2020
Commodity price derivatives loss (gain)	$	2,586	$	(2,206)	$	47,435	$	(12,983)
Foreign currency derivatives loss	17		33		105		3,566
Derivative instruments loss (gain)	$	2,603	$	(2,173)	$	47,540	$	(9,417)

Unrealized PetroTal investment (gain) loss	$	(13,616)	$	1,055	$	(17,477)	$	60,124
Loss on sale of PetroTal shares	—		—		5,070		—
Financial instruments (gain) loss	(18)		405		(18)		1,162
Other financial instruments (gain) loss	$	(13,634)	$	1,460	$	(12,425)	$	61,286

Three Months Ended September 30, Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2016 2017 2016
Commodity price derivative loss (gain) $ 2,489
$ 2,190
$ (3,759 ) $ 856
Foreign currency derivatives gain (814 ) (840 ) (1,452 ) (1,958 )
Trading securities loss —
701
—
2,926
Financial instruments loss (gain) $ 1,675
$ 2,051
$ (5,211 ) $ 1,824

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

Financial instruments not recorded at fair value include the ~~Notes.~~Company's 6.25% Senior Notes due 2025 (the "6.25% Senior Notes") and 7.75% Senior Notes due 2027 (the "7.75% Senior Notes"). At September 30, ~~2017,~~2021, the carrying ~~amount~~amounts of the 6.25% Senior Notes ~~was $110.7~~and the 7.75% Senior Notes were $293.5 million and $291.7 million, respectively, which ~~represents~~represented the aggregate principal amount less unamortized debt issuance costs, and the fair ~~value was $121.9 million.~~values were $262.6 million and $260.1 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, ~~2017,~~2021, the fair value of the ~~derivatives~~investment and DSUs liability was determined using Level 1 inputs. The fair value of the derivative and PSUs liability was determined using Level 2 ~~inputs and the fair value of the PSU liability was determined using Level 3~~ inputs.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the ~~period end~~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 above regarding the fair value of the Company’s revolving credit facility was determined using an income approach using Level 3 inputs. The disclosure above regarding the fair value of the Notes was determined using Level 2 inputs based on the indicative pricing published by certain investment banks or trading levels of the Notes, which are not listed on any securities exchange or quoted on an inter-dealer automated quotation system. The disclosure in the paragraph above regarding the fair value of cash and ~~cash equivalents and~~ restricted cash and cash equivalents and Senior Notes was based on Level 1 inputs, and the fair value of credit facility was based on Level 2 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~~flows to assure it can execute at least a portion of its planned capital spending.

At September 30, ~~2017,~~2021, the Company had outstanding commodity price derivative positions as follows:

Period and type of instrument

Volume,
bopd

Reference

Sold Put ($/bbl, Weighted Average)

Purchased Put ($/bbl, Weighted Average)

Sold Call ($/bbl, Weighted Average)

Swap Price ($/bbl, Weighted Average)

Three-way Collars:
October 1, to December 31, 2021

7,000

ICE Brent

47.14

57.14

68.95

n/a

Swaps: October 1, to December 31, 2021

3,000

ICE Brent

n/a

56.75

Period and type of instrument Volume,
bopd Reference Sold Put ($/bbl) Purchased Put
($/bbl) Sold Call ($/bbl)
Collar: October 1, 2016 to December 31, 2017 5,000
ICE Brent $ 35
$ 45
$ 65
Collar: June 1, 2017 to December 31, 2017 10,000
ICE Brent $ 35
$ 45
$ 65

~~Subsequent to September 30, 2017, the Company entered into the following commodity price contracts:~~

Period and type of instrument Volume,
bopd Reference Purchased Swap
($/bbl) Purchased Call ($/bbl)
Swap: January 1, to December 31, 2018 2,500
ICE Brent $ 55.75

Swap: January 1, to December 31, 2018 2,500
ICE Brent $ 56.05

Participating Swap: January 1, to December 31, 2018 2,500
ICE Brent $ 50.00
$ 54.10

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, ~~2017,~~2021, the Company had outstanding foreign currency derivative positions as follows:

Period and type of instrument

Amount Hedged
(Millions of 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, 2021

3,000

782

COP

3,500

3,630

Period and type of instrument Amount Hedged
(Millions COP)
U.S. Dollar Equivalent of Amount Hedged ⁽¹⁾ (Thousands of U.S. Dollars)
Reference Purchased Call
(COP) Sold Put
(COP, Weighted Average Rate)
Collar: October 1, 2017 to October 31, 2017 23,000
7,832
COP 3,000
3,117
Collar: November 1, 2017 to November 30, 2017 25,000
8,513
COP 3,000
3,139
Collar: December 1, 2017 to December 28, 2017 25,000
8,513
COP 3,000
3,142
73,000
24,858

⁽¹⁾At September 30, ~~2017~~2021 foreign exchange rate.

~~Subsequent to September 30, 2017, the Company entered into the following foreign currency contracts:~~

⁽¹⁾~~At September 30, 2017 foreign exchange rate.~~

~~11.~~13. Supplemental Cash Flow Information

The following table provides a reconciliation of cash and cash equivalents and restricted cash and cash equivalents ~~with the Company's interim unaudited condensed consolidated balance sheet that~~shown as a sum ~~to the total~~ of ~~the same such~~these 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,
	2021		2020		2020		2019
Cash and cash equivalents	$	16,600	$	21,808	$	14,114	$	8,817

Restricted cash and cash equivalents - long-term	3,532		3,007		3,409		2,258
	$	20,132	$	24,815	$	17,523	$	11,075

(Thousands of U.S. Dollars) As at September 30, As at December 31,
2017 2016 2016 2015
Cash and cash equivalents $ 15,125
$ 48,073
$ 25,175
$ 145,342
Restricted cash and cash equivalents - current 3,920
13,198
8,322
92
Restricted cash and cash equivalents -
long-term
10,332
9,993
9,770
3,317
$ 29,377
$ 71,264
$ 43,267
$ 148,751

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


	Nine Months Ended September 30,							Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2017			2016			(Thousands of U.S. Dollars)	2021		2020
Accounts receivable and other long-term assets	$	8,356		$	15,233		Accounts receivable and other long-term assets	$	(18,582)	$	31,108
Derivatives	—			(4,563		)	Derivatives	(2,427)		694
Inventory	(28		)	3,630			Inventory	(2,920)		(2,377)
Prepaids	3,080			1,864			Prepaids	42		(183)
Accounts payable and accrued and other long-term liabilities	5,951			(11,297		)	Accounts payable and accrued and other long-term liabilities	14,417		(57,621)
Taxes receivable and payable	(45,464		)	13,230			Taxes receivable and payable	27,426		51,667
Net changes in assets and liabilities from operating activities	$	(28,105	)	$	18,097		Net changes in assets and liabilities from operating activities	$	17,956	$	23,288

Changes in non-cash investing working capital for the nine months ended September 30, 2021, are comprised of an increase in accounts payable and accrued liabilities of $0.6 million and a decrease in accounts receivable of $0.1 million (nine months ended September 30, 2020, a decrease in accounts payable and accrued liabilities of $69.9 million and a decrease in accounts receivable of $0.3 million).

The following table provides additional supplemental cash flow disclosures:


	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021		2020
Cash paid for income taxes	$	20,433	$	11,603
Cash paid for interest	$	37,259	$	35,408

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	29,420	$	7,805

Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2016
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period $ 68,018
$ 27,520

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 87 and 7,8, respectively, of our 2020 Annual Report on Form ~~10-K, filed with the SEC on March 1, 2017.~~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 and the risk factors described in Part II, Item 1A "Risk Factors" of this Quarterly Report on Form 10-Q, as well as Part I, Item 1A “Risk Factors” in our ~~2016~~2020 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the third quarter of 2021

•Net income in the third quarter of 2021 was $35.0 million or $0.10 per share basic and diluted, compared with a net loss of $107.8 million or $(0.29) per share basic and diluted in the third quarter of 2020

•Income before income taxes in the third quarter of 2021 was $44.0 million compared to loss before income taxes of $128.4 million in the third quarter of 2020

•During the third quarter of 2021, we repaid $25.0 million of the amount drawn under the revolving credit facility

•Funds flow from operations(2) increased by 758% to $69.1 million compared to the third quarter of 2020 and increased 197% from the second quarter of 2021

•During the third quarter the Company generated $34.3 million of free cash flow(2) which was used for debt reduction

•Our third quarter of 2021 average production NAR was 23,372 BOPD (sales volumes - 23,833 BOPD), a 37% increase (sales volumes - 40% increase) from 17,051 BOPD (sales volumes - 17,066 BOPD) in the third quarter of 2020, and 23% increase (sales volumes - 29% increase) from the second quarter of 2021 which was impacted by national blockades in Colombia affecting production from major fields

•Oil sales were $135.3 million, 155% higher compared to $53.1 million in the third quarter of 2020 as a result of an increase in Brent price, offset by higher quality and transportation discounts. Oil sales increased by 40% compared with $96.6 million in the second quarter of 2021 as a result of a 6% increase in Brent price and a 29% increase in sales volumes

•Operating expenses increased 30% on a per bbl basis ($3.93 per bbl) compared to the third quarter of 2020 due to higher power generation costs in Acordionero and increased by 13% on a per bbl basis ($1.99 per bbl) compared to the second quarter of 2021 due to power generation and chemical costs

•Transportation expenses increased by 135% compared to the third quarter of 2020 as a result of the national blockades resulting in utilization of more expensive transportation routes and increased 3% compared to the second quarter of 2021

•Operating netback(2) increased by 204% and 39%, respectively, to $94.7 million compared to $31.1 million in the third quarter of 2020 and $68.3 million in the second quarter of 2021

•Adjusted EBITDA(2) increased by 274% and 125%, respectively, to $81.8 million compared to $21.9 million in the third quarter of 2020 and $36.3 million in the second quarter of 2021

•Quality and transportation discounts for the third quarter of 2021 increased to $11.51 per bbl compared to $9.49 per bbl in the third quarter of 2020 as a result of higher differentials and remained consistent when compared to $11.54 per bbl in the second quarter of 2021

•General and administrative expenses ("G&A") before stock-based compensation increased by 21% compared to the third quarter of 2020, consistent with the increase of operating activities in the current period. When compared to the second quarter of 2021, G&A before stock-based compensation decreased by 24% due to the timing of certain costs incurred and expensed in the prior quarter

•Capital additions for the third quarter of 2021 were $34.8 million, an increase of $27.5 million compared to the third quarter of 2020 and decreased slightly from the $37.4 million incurred in the second quarter of 2021


(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended June 30,			Three Months Ended September 30,								Nine Months Ended September 30,								(Thousands of U.S. Dollars, unless otherwise indicated)	Three Months Ended September 30,					Three Months Ended June 30,		Nine Months Ended September 30,
	2017			2017			2016			% Change		2017			2016			% Change			2021		2020		% Change	2021		2021		2020		% Change
Average Daily Volumes (BOEPD)

Average Daily Volumes (BOPD)																				Average Daily Volumes (BOPD)
Consolidated																				Consolidated
Working Interest Production Before Royalties	31,437			32,570			25,835			26		31,305			25,730			22
Working Interest ("WI") Production Before Royalties																				Working Interest ("WI") Production Before Royalties	28,957		18,944		53	23,035		25,501		22,864		12
Royalties	(5,014		)	(5,055		)	(3,855		)	31		(5,052		)	(3,576		)	41		Royalties	(5,585)		(1,893)		195	(4,059)		(4,531)		(2,600)		74
Production NAR	26,423			27,515			21,980			25		26,253			22,154			19		Production NAR	23,372		17,051		37	18,976		20,970		20,264		3
(Increase) Decrease in Inventory	(140		)	(68		)	(495		)	(86	)	(64		)	951			(107	)
Sales⁽¹⁾	26,283			27,447			21,485			28		26,189			23,105			13

Colombia
Working Interest Production Before Royalties	30,098			32,570			24,874			31		30,398			24,859			22
Royalties	(4,819		)	(5,055		)	(3,717		)	36		(4,914		)	(3,439		)	43
Production NAR	25,279			27,515			21,157			30		25,484			21,420			19
(Increase) Decrease in Inventory	(147		)	(68		)	(497		)	(86	)	(70		)	949			(107	)
Decrease (Increase) in Inventory																				Decrease (Increase) in Inventory	461		15		2,973	(522)		(105)		117		(190)
Sales⁽¹⁾	25,132			27,447			20,660			33		25,414			22,369			14		Sales(1)	23,833		17,066		40	18,454		20,865		20,381		2

Net Income (Loss)	$	(6,807	)	$	3,130		$	(229,619	)	101		$	9,094		$	(338,210	)	103		Net Income (Loss)	$	35,007	$	(107,821)	132	$	(17,627)	$	(20,042)	$	(730,096)	97

Operating Netback																				Operating Netback
Oil and Natural Gas Sales	$	96,128		$	103,768		$	68,539		51		$	294,555		$	197,655		49
Oil Sales																				Oil Sales	$	135,319	$	53,142	155	$	96,623	$	327,435	$	173,045	89
Operating Expenses	(27,208		)	(27,321		)	(25,638		)	7		(78,466		)	(62,453		)	26		Operating Expenses	(37,567)		(20,721)		81	(25,431)		(92,623)		(84,673)		9

Transportation Expenses	(6,492		)	(6,038		)	(5,773		)	5		(19,472		)	(24,318		)	(20	)	Transportation Expenses	(3,021)		(1,286)		135	(2,921)		(8,448)		(8,549)		(1)
Operating Netback⁽²⁾	$	62,428		$	70,409		$	37,128		90		$	196,617		$	110,884		77		Operating Netback(2)	$	94,731	$	31,135	204	$	68,271	$	226,364	$	79,823	184

General and Administrative ("G&A") Expenses, Including Stock-Based Compensation	$	9,513		$	8,651		$	5,592		55		$	26,876		$	20,614		30
G&A Expenses Before Stock-Based Compensation																				G&A Expenses Before Stock-Based Compensation	$	5,444	$	4,506	21	$	7,133	$	18,475	$	17,183	8
G&A Stock-Based Compensation Expense (Recovery)																				G&A Stock-Based Compensation Expense (Recovery)	1,053		56		1,780	1,873		6,597		(707)		1,033
G&A Expenses, Including Stock-Based Compensation																				G&A Expenses, Including Stock-Based Compensation	$	6,497	$	4,562	42	$	9,006	$	25,072	$	16,476	52

Adjusted EBITDA⁽²⁾	$	41,634		$	60,491		$	24,634		146		$	163,663		$	89,350		83		Adjusted EBITDA(2)	$	81,804	$	21,884	274	$	36,299	$	160,007	$	74,247	116

Funds Flow From Operations⁽²⁾	$	50,920		$	55,128		$	23,527		134		$	151,074		$	68,798		120		Funds Flow From Operations(2)	$	69,103	$	8,056	758	$	23,272	$	121,348	$	36,257	235

Capital Expenditures	$	57,865		$	71,694		$	25,080		186		$	175,719		$	69,667		152		Capital Expenditures	$	34,839	$	7,354	374	$	37,384	$	109,650	$	56,378	94

As at
(Thousands of U.S. Dollars) September 30, 2017 December 31, 2016 % Change
Cash, Cash Equivalents and Current Restricted Cash and Cash Equivalents $ 19,045
$ 33,497
(43 )

Revolving Credit Facility $ 120,000
$ 90,000
33

Convertible Senior Notes $ 115,000
$ 115,000
—

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

⁽²⁾Non-GAAP measures

Operating netback, EBITDA, adjusted EBITDA, ~~and~~ funds flow from operations and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as

alternatives to net income ~~or loss~~(loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. ~~Each~~Disclosure of each non-GAAP financial measure is ~~presented along with~~preceded by 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 ~~net of royalties and~~less operating and transportation expenses. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil ~~and natural gas~~ sales to operating netback is provided in the table above.

~~Adjusted~~ EBITDA, as presented, is defined as net income or loss adjusted for depletion, depreciation and accretion (“("DD~~&A”~~&A") expenses, ~~asset impairment,~~ interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for goodwill impairment, asset impairment, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, stock-based compensation expense or recovery, other-non cash gain or ~~expense.~~loss, unrealized derivative instruments gain or loss and other financial instruments gain or loss. Management uses ~~these financial measures~~this supplemental measure to analyze performance and income ~~or loss~~ generated by our principal business activities prior to the consideration of how non-cash items affect that income, ~~or loss,~~ and believes that ~~these~~this financial ~~measures are also~~ measure is

useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net ~~income or~~ loss to EBITDA and adjusted EBITDA is as follows:


	Three Months Ended June 30,			Three Months Ended September 30,					Nine Months Ended September 30,						Three Months Ended September 30,				Three Months Ended June 30,		Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2017			2017		2016			2017		2016			(Thousands of U.S. Dollars)	2021		2020		2021		2021		2020
Net income (loss)	$	(6,807	)	$	3,130	$	(229,619	)	$	9,094	$	(338,210	)	Net income (loss)	$	35,007	$	(107,821)	$	(17,627)	$	(20,042)	$	(730,096)
Adjustments to reconcile net income (loss) to adjusted EBITDA
Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA														Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA
DD&A expenses	31,644			34,492		35,729			92,729		104,525			DD&A expenses	38,055		31,340		28,927		98,300		131,118
Asset impairment	169			787		319,974			1,239		469,715
Interest expense	3,331			3,989		5,122			10,415		7,842			Interest expense	13,608		14,029		13,935		41,355		40,204
Income tax expense (recovery)	13,297			18,093		(106,572		)	50,186		(154,522		)	Income tax expense (recovery)	8,955		(20,565)		9,189		26,795		(62,236)
EBITDA (non-GAAP)														EBITDA (non-GAAP)	$	95,625	$	(83,017)	$	34,424	$	146,408	$	(621,010)
Goodwill impairment														Goodwill impairment	—		—		—		—		102,581
Asset impairment														Asset impairment	—		104,731		—		—		507,093
Non-cash lease expense														Non-cash lease expense	408		523		370		1,222		1,494
Lease payments														Lease payments	(384)		(429)		(393)		(1,239)		(1,404)
Unrealized foreign exchange loss														Unrealized foreign exchange loss	3,465		3,080		477		16,945		22,335
Stock-based compensation expense (recovery)														Stock-based compensation expense (recovery)	1,053		56		1,873		6,597		(707)
Other non-cash loss														Other non-cash loss	—		2,026		—		—		2,026
Unrealized derivative instruments (gain) loss														Unrealized derivative instruments (gain) loss	(4,729)		(6,546)		(3,066)		2,499		553
Other financial instruments (gain) loss														Other financial instruments (gain) loss	(13,634)		1,460		2,614		(12,425)		61,286
Adjusted EBITDA (non-GAAP)	$	41,634		$	60,491	$	24,634		$	163,663	$	89,350		Adjusted EBITDA (non-GAAP)	$	81,804	$	21,884	$	36,299	$	160,007	$	74,247

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, goodwill and asset impairment, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, ~~cash settlement of RSUs,~~non-cash lease expense, lease payments, unrealized foreign exchange ~~gains~~gain or loss, derivative instruments gain or loss, cash settlement on derivative instruments, other non-cash gain or loss and ~~losses,~~other financial instruments ~~gains~~gain or ~~losses, cash settlement of financial instruments, loss on sale of Brazil business unit and gain on acquisition.~~loss. Management uses this financial measure to analyze performance and income ~~or loss~~ generated by our principal business activities prior to the consideration of how non-cash items affect that income, ~~or loss,~~and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net ~~income or~~ loss to funds flow from operations and free cash flow is as follows:


	Three Months Ended September 30,				Three Months Ended June 30,		Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021		2020		2021		2021		2020
Net income (loss)	$	35,007	$	(107,821)	$	(17,627)	$	(20,042)	$	(730,096)
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses	38,055		31,340		28,927		98,300		131,118
Goodwill impairment	—		—		—		—		102,581
Asset impairment	—		104,731		—		—		507,093
Deferred tax expense (recovery)	8,955		(21,202)		9,203		26,809		(62,796)
Stock-based compensation expense (recovery)	1,053		56		1,873		6,597		(707)
Amortization of debt issuance costs	907		838		894		2,682		2,774
Non-cash lease expense	408		523		370		1,222		1,494
Lease payments	(384)		(429)		(393)		(1,239)		(1,404)
Unrealized foreign exchange loss	3,465		3,080		477		16,945		22,335
Derivative instruments loss (gain)	2,603		(2,173)		21,239		47,540		(9,417)
Cash settlements on derivative instruments	(7,332)		(4,373)		(24,305)		(45,041)		9,970
Other non-cash loss	—		2,026		—		—		2,026
Other financial instruments (gain) loss	(13,634)		1,460		2,614		(12,425)		61,286
Funds flow from operations (non-GAAP)	$	69,103	$	8,056	$	23,272	$	121,348	$	36,257
Capital expenditures	$	34,839	$	7,354	$	37,384	$	109,650	$	56,378
Free cash flow (non-GAAP)	$	34,264	$	702	$	(14,112)	$	11,698	$	(20,121)

Three Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2017 2016 2017 2016
Net income (loss) $ (6,807 ) $ 3,130
$ (229,619 ) 9,094
$ (338,210 )
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses 31,644
34,492
35,729
92,729
104,525
Asset impairment 169
787
319,974
1,239
469,715
Deferred tax expense (recovery) 11,525
13,760
(110,451 ) 36,664
(166,202 )
Stock-based compensation expense 1,980
1,752
858
4,935
4,380
Amortization of debt issuance costs 620
643
2,184
1,868
2,813
Cash settlement of RSUs (183 ) (33 ) (24 ) (534 ) (1,210 )
Unrealized foreign exchange loss (gain) 3,895
(1,380 ) 2,387
(304 ) 2,437
Financial instruments (gain) loss (1,447 ) 1,675
2,051
(5,211 ) 1,824
Cash settlement of financial instruments 448
302
438
1,518
438
Loss on sale of Brazil business unit 9,076
—
—
9,076
—
Gain on acquisition —
—
—
—
(11,712 )
Funds flow from operations (non-GAAP) $ 50,920
$ 55,128
$ 23,527
$ 151,074
$ 68,798

Additional Operational Results


	Three Months Ended September 30,					Three Months Ended June 30,		Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021		2020		% Change	2021		2021		2020		% Change
Oil sales	$	135,319	$	53,142	155	$	96,623	$	327,435	$	173,045	89
Operating expenses	37,567		20,721		81	25,431		92,623		84,673		9

Transportation expenses	3,021		1,286		135	2,921		8,448		8,549		(1)
Operating netback(1)	94,731		31,135		204	68,271		226,364		79,823		184

COVID-19 related costs	990		1,108		(11)	897		3,026		1,529		98
DD&A expenses	38,055		31,340		21	28,927		98,300		131,118		(25)
Goodwill impairment	—		—		—	—		—		102,581		(100)
Asset impairment	—		104,731		(100)	—		—		507,093		(100)
G&A expenses before stock-based compensation	5,444		4,506		21	7,133		18,475		17,183		8
G&A stock-based compensation expense (recovery)	1,053		56		1,780	1,873		6,597		(707)		1,033
Severance expenses	—		122		(100)	—		919		1,469		(37)
Foreign exchange loss	2,650		4,275		(38)	91		15,824		20,094		(21)
Derivative instruments loss (gain)	2,603		(2,173)		220	21,239		47,540		(9,417)		605
Other financial instruments (gain) loss	(13,634)		1,460		(1,034)	2,614		(12,425)		61,286		(120)
Other loss	—		67		(100)	—		—		67		(100)
Interest expense	13,608		14,029		(3)	13,935		41,355		40,204		3
	50,769		159,521		(68)	76,709		219,611		872,500		(75)

Interest income	—		—		—	—		—		345		(100)

Income (loss) before income taxes	43,962		(128,386)		134	(8,438)		6,753		(792,332)		101

Current income tax expense (recovery)	—		637		(100)	(14)		(14)		560		(103)
Deferred income tax expense (recovery)	8,955		(21,202)		142	9,203		26,809		(62,796)		143
	8,955		(20,565)		144	9,189		26,795		(62,236)		143
Net income (loss)	$	35,007	$	(107,821)	132	$	(17,627)	$	(20,042)	$	(730,096)	97

Sales Volumes (NAR)


Total sales volumes, BOPD	23,833		17,066		40	18,454		20,865		20,381		2

Brent Price per bbl	$	73.23	$	43.34	69	$	69.08	$	67.97	$	42.53	60

Three Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
2017 2017 2016 % Change 2017 2016 % Change
(Thousands of U.S. Dollars)
Oil and natural gas sales $ 96,128
$ 103,768
$ 68,539
51
$ 294,555
$ 197,655
49
Operating expenses 27,208
27,321
25,638
7
78,466
62,453
26
Transportation expenses 6,492
6,038
5,773
5
19,472
24,318
(20 )
Operating netback⁽¹⁾
62,428
70,409
37,128
90
196,617
110,884
77

DD&A expenses 31,644
34,492
35,729
(3 ) 92,729
104,525
(11 )
Asset impairment 169
787
319,974
(100 ) 1,239
469,715
(100 )
G&A expenses before stock-based compensation 7,610
6,965
4,778
46
22,138
16,414
35
G&A stock-based compensation expense 1,903
1,686
814
107
4,738
4,200
13
Severance expenses —
1,164
—
—
1,164
1,299
(10 )
Transaction expenses —
—
6,088
(100 ) —
7,325
(100 )
Equity tax —
—
—
—
1,224
3,053
(60 )
Foreign exchange loss (gain) 3,897
(1,271 ) (507 ) (151 ) 779
1,059
(26 )
Financial instruments (gain) loss (1,447 ) 1,675
2,051
(18 ) (5,211 ) 1,824
(386 )
Interest expense 3,331
3,989
5,122
(22 ) 10,415
7,842
33
47,107
49,487
374,049
(87 ) 129,215
617,256
(79 )

Loss on sale of Brazil business unit (9,076 ) —
—
—
(9,076 ) —
—
Gain on acquisition —
—
—
—
—
11,712
(100 )
Interest income 245
301
730
(59 ) 954
1,928
(51 )

Income (loss) before income taxes 6,490
21,223
(336,191 ) 106
59,280
(492,732 ) 112

Current income tax expense 1,772
4,333
3,879
12
13,522
11,680
16
Deferred income tax expense (recovery) 11,525
13,760
(110,451 ) 112
36,664
(166,202 ) 122
13,297
18,093
(106,572 ) 117
50,186
(154,522 ) 132
Net income (loss) $ (6,807 ) $ 3,130
$ (229,619 ) 101

$ 9,094
$ (338,210 ) 103

Sales Volumes (NAR)
Total sales volumes, BOEPD 26,283
27,447
21,485
28
26,189
23,105
13

Average Prices
Oil and NGL's per bbl $ 40.44
$ 41.44
$ 34.79
19
$ 41.58
$ 31.34
33
Natural gas per Mcf $ 2.52
$ 1.89
$ 3.40
(44 ) $ 1.90
$ 3.07
(38 )

Brent Price per bbl $ 50.92
$ 52.18
$ 46.98
11
$ 52.59
$ 42.07
25


Consolidated Results of Operations per BOE Sales Volumes NAR
Oil and natural gas sales	$	40.19		$	41.09		$	34.68		18		$	41.20		$	31.22		32
Consolidated Results of Operations per bbl Sales Volumes NAR																				Consolidated Results of Operations per bbl Sales Volumes NAR
Oil sales																				Oil sales	$	61.72	$	33.85	82	$	57.54	$	57.48	$	30.99	85
Operating expenses	11.38			10.82			12.97			(17	)	10.97			9.86			11		Operating expenses	17.13		13.20		30	15.14		16.26		15.16		7
Transportation expenses	2.71			2.39			2.92			(18	)	2.72			3.84			(29	)	Transportation expenses	1.38		0.82		68	1.74		1.48		1.53		(3)
Operating netback⁽¹⁾	26.10			27.88			18.79			48		27.51			17.52			57		Operating netback(1)	43.21		19.83		118	40.66		39.74		14.30		178

COVID-19 related costs																				COVID-19 related costs	0.45		0.70		(36)	0.53		0.53		0.27		96
DD&A expenses	13.23			13.66			18.08			(24	)	12.97			16.51			(21	)	DD&A expenses	17.36		19.96		(13)	17.23		17.26		23.48		(26)
Goodwill impairment																				Goodwill impairment	—		—		—	—		—		18.37		(100)
Asset impairment	0.07			0.31			161.88			(100	)	0.17			74.20			(100	)	Asset impairment	—		66.71		(100)	—		—		90.80		(100)
G&A expenses before stock-based compensation	3.18			2.76			2.42			14		3.10			2.60			19		G&A expenses before stock-based compensation	2.48		2.87		(14)	4.25		3.24		3.08		5
G&A stock-based compensation expense	0.80			0.67			0.41			63		0.66			0.66			—
G&A stock-based compensation expense (recovery)																				G&A stock-based compensation expense (recovery)	0.48		0.04		1,100	1.12		1.16		(0.13)		992
Severance expenses	—			0.46			—			—		0.16			0.21			(24	)	Severance expenses	—		0.08		(100)	—		0.16		0.26		(38)
Transaction expenses	—			—			3.08			(100	)	—			1.16			(100	)
Equity tax	—			—			—			—		0.17			0.48			(65	)
Foreign exchange loss (gain)	1.63			(0.50		)	(0.26		)	(92	)	0.11			0.17			(35	)
Financial instruments (gain) loss	(0.60		)	0.66			1.04			(37	)	(0.73		)	0.29			(352	)
Foreign exchange loss																				Foreign exchange loss	1.21		2.72		(56)	0.05		2.78		3.60		(23)
Derivative instruments loss (gain)																				Derivative instruments loss (gain)	1.19		(1.38)		186	12.65		8.35		(1.69)		594
Other financial instruments (gain) loss																				Other financial instruments (gain) loss	(6.22)		0.93		(769)	1.56		(2.18)		10.97		(120)
Other loss																				Other loss	—		0.04		(100)	—		—		0.01		(100)
Interest expense	1.39			1.58			2.59			(39	)	1.46			1.24			18		Interest expense	6.21		8.94		(31)	8.30		7.26		7.20		1
	19.70			19.60			189.24			(90	)	18.07			97.52			(81	)		23.16		101.61		(77)	45.69		38.56		156.22		(75)

Loss on sale of Brazil business unit	(3.79		)	—			—			—		(1.27		)	—			—
Gain on acquisition	—			—			—			—		—			1.85			(100	)

Interest income	0.10			0.12			0.37			(68	)	0.13			0.30			(57	)	Interest income	—		—		—	—		—		0.06		(100)

Income (loss) before income taxes	2.71			8.40			(170.08		)	105		8.30			(77.85		)	111		Income (loss) before income taxes	20.05		(81.78)		125	(5.03)		1.18		(141.86)		101
Current income tax expense	0.74			1.72			1.96			(12	)	1.89			1.84			3

Current income tax expense (recovery)																				Current income tax expense (recovery)	—		0.41		(100)	(0.01)		—		0.10		(100)
Deferred income tax expense (recovery)	4.82			5.45			(55.88		)	110		5.13			(26.25		)	120		Deferred income tax expense (recovery)	4.08		(13.50)		130	5.48		4.71		(11.24)		142
	5.56			7.17			(53.92		)	113		7.02			(24.41		)	129			4.08		(13.09)		131	5.47		4.71		(11.14)		142
Net income (loss)	$	(2.85	)	$	1.23		$	(116.16	)	101		$	1.28		$	(53.44	)	102		Net income (loss)	$	15.97	$	(68.69)	123	$	(10.50)	$	(3.53)	$	(130.72)	97

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

As previously announced, we continue to evaluate strategic disposition alternatives for our assets in Peru, which may not be core to our ongoing plans. Any such disposition may involve a contribution of such assets to a separate entity in which we would retain a non-controlling equity interest. The new company may engage in external capital raising activities to fund the ongoing development of the Peruvian assets. We have not entered into any definitive agreement and cannot provide assurances that any disposition will be completed.

Oil ~~and Gas~~ Production and Sales Volumes, ~~BOEPD~~BOPD


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Average Daily Volumes (BOPD)
WI Production Before Royalties	28,957		18,944		25,501		22,864
Royalties	(5,585)		(1,893)		(4,531)		(2,600)
Production NAR	23,372		17,051		20,970		20,264
Decrease (Increase) in Inventory	461		15		(105)		117
Sales	23,833		17,066		20,865		20,381

Royalties, % of WI Production Before Royalties	19	%	10	%	18	%	11	%

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
Average Daily Volumes (BOEPD) Colombia Brazil Total Colombia Brazil Total
Working Interest Production Before Royalties 32,570
—
32,570
24,874
961
25,835
Royalties (5,055 ) —
(5,055 ) (3,717 ) (138 ) (3,855 )
Production NAR 27,515
—
27,515

21,157
823
21,980
(Increase) Decrease in Inventory (68 ) —
(68 ) (497 ) 2
(495 )
Sales 27,447
—
27,447

20,660
825
21,485

Royalties, % of Working Interest Production Before Royalties 16 % — % 16 % 15 % 14 % 15 %

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
Average Daily Volumes (BOEPD) Colombia Brazil Total Colombia Brazil Total
Working Interest Production Before Royalties 30,398
907
31,305
24,859
871
25,730
Royalties (4,914 ) (138 ) (5,052 ) (3,439 ) (137 ) (3,576 )
Production NAR 25,484
769
26,253
21,420
734
22,154
(Increase) Decrease in Inventory (70 ) 6
(64 ) 949
2
951
Sales 25,414
775
26,189
22,369
736
23,105

Royalties, % of Working Interest Production Before Royalties 16 % 15 % 16 % 14 % 16 % 14 %

Royalties as a percentage of production for the three and nine months ended September 30, ~~2017,~~2021, increased compared with the ~~comparable period in~~corresponding periods of 2020 and the prior ~~year~~quarter commensurate with the increase in benchmark oil ~~prices.~~prices and the price sensitive royalty regime in Colombia.

Despite the sale of our Brazil assets effective June 30, 2017, oil and gas production NAR for the three months ended September 30, 2017, increased 4% compared with the prior quarter as a result of a successful drilling and workover campaign in

~~Oil and gas sales volumes~~ for the three months ended September 30, 2017, increased by 28% to 27,447 BOEPD compared with 21,485 BOEPD in the corresponding period in 2016. Higher working interest production (6,735 BOEPD) and lower inventory increases (427 BOEPD) more than offset higher royalty volumes (1,200 BOEPD).

Operating Netback(1)

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
(Thousands of U.S. Dollars) Colombia Brazil Total Colombia Brazil Total
Oil and Natural Gas Sales $ 103,768
$ —
$ 103,768
$ 65,944
$ 2,595
$ 68,539
Transportation Expenses (6,038 ) —
(6,038 ) (5,644 ) (129 ) (5,773 )
97,730
—
97,730
60,300
2,466
62,766
Operating Expenses (27,321 ) —
(27,321 ) (24,899 ) (739 ) (25,638 )
Operating Netback⁽¹⁾
$ 70,409
$ —
$ 70,409
$ 35,401
$ 1,727
$ 37,128

U.S. Dollars Per BOE Sales Volumes NAR
Brent $ 52.18
$ —
$ 52.18
$ 46.98
$ 46.98
$ 46.98
Quality and Transportation Discounts (11.09 ) —
(11.09 ) (12.29 ) (12.77 ) (12.30 )
Average Realized Price 41.09
—
41.09
34.69
34.21
34.68
Transportation Expenses (2.39 ) —
(2.39 ) (2.97 ) (1.70 ) (2.92 )
Average Realized Price Net of Transportation Expenses 38.70
—
38.70
31.72
32.51
31.76
Operating Expenses (10.82 ) —
(10.82 ) (13.10 ) (9.74 ) (12.97 )
Operating Netback⁽¹⁾
$ 27.88
$ —
$ 27.88
$ 18.62
$ 22.77
$ 18.79

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
(Thousands of U.S. Dollars) Colombia Brazil Total Colombia Brazil Total
Oil and Natural Gas Sales $ 286,137
$ 8,418
$ 294,555
$ 191,515
$ 6,140
$ 197,655
Transportation Expenses (19,122 ) (350 ) (19,472 ) (24,005 ) (313 ) (24,318 )
267,015
8,068
275,083
167,510
5,827
173,337
Operating Expenses (76,669 ) (1,797 ) (78,466 ) (61,057 ) (1,396 ) (62,453 )
Operating Netback⁽¹⁾
$ 190,346
$ 6,271
$ 196,617
$ 106,453
$ 4,431
$ 110,884

U.S. Dollars Per BOE Sales Volumes NAR
Brent $ 52.59
$ 52.59
$ 52.59
$ 42.07
$ 42.07
$ 42.07
Quality and Transportation Discounts (11.35 ) (12.83 ) (11.39 ) (10.82 ) (11.61 ) (10.85 )
Average Realized Price 41.24
39.76
41.20
31.25
30.46
31.22
Transportation Expenses (2.76 ) (1.65 ) (2.72 ) (3.92 ) (1.55 ) (3.84 )
Average Realized Price Net of Transportation Expenses 38.48
38.11
38.48
27.33
28.91
27.38
Operating Expenses (11.05 ) (8.49 ) (10.97 ) (9.96 ) (6.92 ) (9.86 )
Operating Netback⁽¹⁾
$ 27.43
$ 29.62
$ 27.51
$ 17.37
$ 21.99
$ 17.52

⁽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 disclosure above regarding~~measures" for a definition of this measure.

Oil ~~and gas~~ sales for the three months ended September 30, 2021, increased by 155% to $135.3 million due to a 69% increase in Brent price and 40% higher sales volumes partially offset by a 21% increase in the quality and transportation discounts as a result of the widening of the Castilla and Vasconia differentials compared to the corresponding period of 2020. Both the Castilla and Vasconia differentials have widened from $4.65 and $3.01 in the third quarter of 2020 to $6.51 and $4.02 in the third quarter of 2021, respectively. For the nine months ended September 30, ~~2017,~~2021, oil sales increased by ~~51%~~89% to ~~$103.8~~$327.4 million ~~and by 49%~~compared to ~~$294.6 million, respectively, from $68.5 million and $197.7 million, respectively, in~~ the ~~comparable periods in 2016~~corresponding period of 2020 due to ~~increased~~a 60% increase in Brent price, higher sales volumes, and ~~realized~~lower quality and transportation discounts. Compared with the prior quarter, oil ~~prices.~~sales increased 40% primarily as a result of a 6% increase in Brent price and a 29% increase in sales volumes.

The following table shows the effect of changes in realized ~~prices~~price and sales volumes on our oil ~~and gas~~ sales for the three and nine months ended September 30, ~~2017:~~2021, compared to the prior quarter and the corresponding periods of 2020:


(Thousands of U.S. Dollars)	Third Quarter 2021 Compared with Second Quarter 2021		Third Quarter 2021 Compared with Third Quarter 2020		Nine Months Ended September 30, 2021 Compared with Nine Months Ended September 30, 2020
Oil sales for the comparative period	$	96,623	$	53,142	$	173,045
Realized sales price increase effect	9,162		61,106		150,930
Sales volumes increase effect	29,534		21,071		3,460
Oil sales for the three and nine months ended September 30, 2021	$	135,319	$	135,319	$	327,435

Third Quarter 2017 Compared with Second Quarter 2017 Third Quarter 2017 Compared with Third Quarter 2016 Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016
Oil and natural gas sales for the comparative period $ 96,128
$ 68,539
$ 197,655
Realized sales price increase effect 2,285
16,206
71,333
Sales volume increase effect 5,355
19,023
25,567
Oil and natural gas sales for period ended September 30, 2017 $ 103,768
$ 103,768
$ 294,555

Operating expenses for the three and nine months ended September 30, ~~2017,~~2021, increased ~~by 11%~~$3.93 and ~~25% respectively.~~

~~Oil~~$1.10 per bbl to $37.6 million and ~~gas sales for~~$92.6 million or $17.13 and $16.26 per bbl primarily due to increased operating activities and higher power generation costs in Acordionero when compared to the ~~three months ended September 30, 2017, increased by 8%~~corresponding periods of 2020. Lower operating activities during most of 2020 were attributed to ~~$103.8 million from $96.1 million compared with~~the shut-in of higher-cost wells in response to the COVID-19 pandemic. Compared to the prior quarter, operating expenses increased $1.99 per bbl from $25.4 million or $15.14 per bbl due to higher ~~sales volumes~~costs associated with power generation and chemical costs in Acordionero and increased realized oil prices. Average realized prices increased by 2% to $41.09 per BOE for the three months ended September 30, 2017, compared with $40.19 per BOE in the prior quarter. Average Brent oil prices for the three months ended September 30, 2017, increased by 2% to $52.18 per bbl, compared with $50.92 per bbl in the prior quarter.workover activity.

We have options to sell our oil ~~though~~through multiple pipelines and trucking routes. Each ~~transportation route~~option has varying effects on realized ~~prices~~sales price and transportation expenses. The following table shows the percentage of oil volumes we sold in Colombia using each ~~transportation method~~option for the three and nine months ended September 30, ~~2017 and 2016~~2021, 2020, and the prior quarter:


	Three Months Ended September 30,				Three Months Ended June 30,		Nine Months Ended September 30,
	2021		2020		2021		2021		2020
Volume transported through pipeline	9	%	—	%	9	%	6	%	5	%
Volume sold at wellhead	42	%	48	%	24	%	55	%	45	%
Volume transported via truck to sales point	49	%	52	%	67	%	39	%	50	%
	100	%	100	%	100	%	100	%	100	%

Three Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
2017 2017 2016 2017 2016
Volume transported through pipeline 20 % 10 % 36 % 18 % 50 %
Volume sold at wellhead, trucking 52 % 57 % 56 % 54 % 40 %
Volume sold not at wellhead, trucking 28 % 33 % 8 % 28 % 10 %
100 % 100 % 100 % 100 % 100 %

Volumes ~~not sold at the wellhead~~transported through pipeline or via truck receive a higher realized price but incur higher transportation expenses. ~~Volumes~~Conversely, volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation ~~expense.~~expenses.

Transportation expenses for the three months ended September 30, ~~2017,~~2021, increased by 5%135% to ~~$6.0~~$3.0 million and on a per bbl basis increased by 68% to $1.38 compared ~~with~~to the corresponding period in ~~2016. On a per BOE basis, transportation expenses decreased by 18% to $2.39 per BOE from $2.92 per BOE in the corresponding period in 2016. The decrease in transportation expenses per BOE was~~of 2020 due to maintenance on the ~~use~~Impala terminal resulting in utilization of alternative transportation routes which had ~~lower~~higher costs per ~~BOE than the routes used in 2016.~~

~~Transportation expenses for~~

For the three months ended September 30, ~~2017, decreased 7%~~2021, transportation expenses increased by 3% compared to ~~$6.0 million compared with $6.5~~$2.9 million in the prior ~~quarter.~~quarter due to increased sales volumes. On a per ~~BOE~~bbl basis, transportation expenses decreased by ~~12% to $2.39~~21% from ~~$2.71~~$1.74 in the ~~prior quarter. The decrease was primarily~~previous quarter due to the ~~use of~~Company utilizing more favorable transportation routes ~~which had lower~~as all blockades were lifted.

The COVID-19 pandemic has resulted in extra ongoing operating and transportation costs ~~per BOE.~~

U.S. Dollars Per BOE Sales Volumes NAR Third Quarter 2017 Compared with Second Quarter 2017 Third Quarter 2017 Compared with Third Quarter 2016 Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016
Average realized price net of transportation expenses for the comparative period $ 37.42
$ 31.72
$ 27.33
Increase in benchmark prices 1.26
$ 5.20
10.52
(Increase) decrease in quality and transportation discounts (0.35 ) 1.20
(0.53 )
Lower transportation expenses 0.37
0.58
1.16
Average realized price net of transportation expenses for period ended September 30, 2017 $ 38.70
$ 38.70
$ 38.48


	Three Months Ended September 30,				Three Months Ended June 30,		Nine Months Ended September 30,
	2021		2020		2021		2021		2020
DD&A Expenses, thousands of U.S. Dollars	$	38,055	$	31,340	$	28,927	$	98,300	$	131,118
DD&A Expenses, U.S. Dollars per bbl	17.36		19.96		17.23		17.26		23.48

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per BOE DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per BOE
Colombia $ 33,388
$ 13.22
$ 34,156
$ 17.97
Brazil —
—
1,022
13.47
Peru 881
—
206
—
Corporate 223
—
345
—
$ 34,492
$ 13.66
$ 35,729
$ 18.08

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per BOE DD&A expenses, thousands of U.S. Dollars DD&A expenses, U.S. Dollars Per BOE
Colombia $ 88,453
$ 12.75
$ 100,350
$ 16.37
Brazil 2,263
10.69
2,764
13.71
Peru 1,350
—
418
—
Corporate 663
—
993
—
$ 92,729
$ 12.97
$ 104,525
$ 16.51

DD&A expenses for the three and nine months ended September 30, ~~2017, decreased~~2021, increased 21% and 25%, respectively, due to ~~$34.5 million ($13.66 per BOE) and $92.7 million ($12.97 per BOE) from $35.7 million ($18.08 per BOE) and $104.5 million ($16.51 per BOE) in~~increased production compared to the ~~comparable~~corresponding periods ~~in 2016.~~of 2020. On a per ~~BOE~~bbl basis, ~~the decrease was~~DD&A expenses decreased by $2.60 and $6.22 per bbl, respectively, due to lower costs in the depletable base ~~and increased proved reserves.~~as a result of ceiling test impairment losses recorded over the last three quarters of 2020.

~~On a per BOE basis, DD&A expenses increased by 3% to $13.66 per BOE for~~For the three months ended September 30, ~~2017, from $13.23 per BOE in~~2021, DD&A expenses increased 32% compared to the prior quarter due to ~~higher costs in the depletable base from capital expenditures~~increased production during the ~~quarter ended September 30, 2017.~~current quarter. On a per bbl basis DD&A expenses were comparable to the previous quarter.

Asset ~~Impairment~~impairment

Three Months Ended September 30, Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2016 2017 2016
Impairment of oil and gas properties
Colombia $ —
$ 298,370
$ —
$ 431,146
Brazil —
21,604
—
37,006
Peru 176
—
628
899
Mexico 611
—
611
—
787
319,974

1,239
469,051
Impairment of inventory —
—
—
664
$ 787
$ 319,974
$ 1,239
$ 469,715

Three Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2017 2016 % Change 2017 2016 % Change
G&A Expenses Before Stock-Based Compensation $ 7,610
$ 6,965
$ 4,778
46 $ 22,138
$ 16,414
35
G&A Stock-Based Compensation 1,903
1,686
814
107 4,738
4,200
13
G&A Expenses, Including Stock-Based Compensation $ 9,513
$ 8,651
$ 5,592
55 $ 26,876
$ 20,614
30

U.S. Dollars Per BOE Sales Volumes NAR

G&A Expenses Before Stock-Based Compensation $ 3.18
$ 2.76
$ 2.42
14 $ 3.10
$ 2.60
19
G&A Stock-Based Compensation 0.80
0.67
0.41
63 0.66
0.66
—
G&A Expenses, Including Stock-Based Compensation $ 3.98
$ 3.43
$ 2.83
21 $ 3.76
$ 3.26
15

(ii) Inventory impairment

For the three and nine months ended September 30, 2021, we had no inventory impairment. For the three and nine months ended September 30, 2020, we recorded $0.1 million and $4.2 million, respectively, of inventory impairment.

The entire goodwill balance of $102.6 million was impaired during the nine months ended September 30, 2020, due to the unit's carrying value exceeding its fair value as a result of the impact of lower forecasted commodity prices.


	Three Months Ended September 30,				Three Months Ended June 30,			Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021		2020			2021			2021		2020
G&A Expenses Before Stock-Based Compensation	$	5,444	$	4,506		$	7,133		$	18,475	$	17,183
G&A Stock-Based Compensation Expense (Recovery)	1,053		56			1,873			6,597		(707)
G&A Expenses, Including Stock-Based Compensation	$	6,497	$	4,562		$	9,006		$	25,072	$	16,476
(U.S. Dollars Per bbl Sales Volumes NAR)
G&A Expenses Before Stock-Based Compensation	$	2.48	$	2.87		$	4.25		$	3.24	$	3.08
G&A Stock-Based Compensation Expense (Recovery)	0.48		0.04			1.12			1.16		(0.13)
G&A Expenses, Including Stock-Based Compensation	$	2.96	$	2.91		$	5.37		$	4.40	$	2.95

For the three and nine months ended September 30, 2021, G&A expenses before stock-based compensation increased by ~~46%~~21% and ~~35%~~8%, respectively, ~~from~~consistent with an increase of operating activities in 2021 compared to the corresponding periods ~~in 2016. The increase was commensurate with our growth. Since June~~of 2020. On a per bbl basis, for the three months ended September 30, ~~2016, we have completed two acquisitions, drilled~~ 25 ~~wells,~~2021, G&A expenses before stock-based compensation decreased by 14% to $2.48 as a result of higher sales volumes and ~~grown production NAR 25% from 21,980 BOEPD~~increased by 5% to $3.24 for the nine months ended September 30, 2021, as a result of increased operating activities when compared to the corresponding periods of 2020. For the three months ended September 30, 2021, G&A expenses before stock-based compensation decreased by 24% to $5.4 million or 42% to $2.48 on a per bbl basis compared to the prior quarter due to the timing of certain costs incurred and expensed in the ~~third quarter of 2016 to 27,515 BOEPD in 2017.~~prior quarter.

~~After~~G&A expenses after stock-based compensation ~~G&A expenses~~ for the three and nine months ended September 30, ~~2017,~~2021, increased by ~~55% to $8.7 million ($3.43~~42% and 52% (2% and 49% per ~~BOE) and by 30% to $26.9 million ($3.76 per BOE)~~bbl), respectively, ~~from $5.6 million ($2.83 per BOE) and $20.6 million ($3.26 per BOE), respectively, in~~compared to the corresponding periods ~~in 2016. The increase was~~of 2020, mainly due to ~~the increased head count.~~

higher stock-based compensation resulting from a higher share price. G&A expenses after stock-based compensation for the three months ended September 30, ~~2017,~~2021, decreased by ~~9% to $8.7 million ($3.43~~28% or 45% on a per ~~BOE)~~bbl basis, compared with ~~$9.5 million ($3.98 per BOE)~~the prior quarter, due to the timing of certain costs incurred and expensed in the prior quarter.

~~Equity Tax Expense~~

Foreign Exchange Gains and Losses

For the three and nine months ended September 30, ~~2017~~,2021, we had a $2.7 million and $15.8 million, respectively, loss on foreign exchange ~~gains of $1.3~~compared to a $4.3 million and ~~losses of $0.8~~a $20.1 million ~~respectively, compared with foreign exchange gains of $0.5 million and losses of $1.1 million, respectively, in~~loss for the corresponding periods ~~in 2016. Under U.S. GAAP,~~of 2020. Accounts receivable, taxes receivable, deferred income taxes, accounts payable, and investment are considered a monetary ~~liability~~items and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation was the ~~main~~primary source of the foreign exchange ~~gains and losses.~~ losses in the periods.

The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and nine months ended September 30, ~~2017,~~2021, and ~~2016:~~2020:

The following table presents the nature of our derivative and other financial instruments gains and losses for the three and nine months ended September 30, ~~2017,~~2021, and ~~2016:~~


	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021		2020		2021		2020
Commodity price derivatives loss (gain)	$	2,586	$	(2,206)	$	47,435	$	(12,983)
Foreign currency derivatives loss	17		33		105		3,566
Derivative instruments loss (gain)	$	2,603	$	(2,173)	$	47,540	$	(9,417)

Unrealized PetroTal investment (gain) loss	$	(13,616)	$	1,055	$	(17,477)	$	60,124
Loss on sale of PetroTal shares	—		—		5,070		—
Financial instruments (gain) loss	(18)		405		(18)		1,162
Other financial instruments (gain) loss	$	(13,634)	$	1,460	$	(12,425)	$	61,286


	Three Months Ended September 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021			2020			2021			2020
Income (loss) before income tax	$	43,962		$	(128,386)		$	6,753		$	(792,332)

Current income tax expense (recovery)	$	—		$	637		$	(14)		$	560
Deferred income tax expense (recovery)	8,955			(21,202)			26,809			(62,796)
Total income tax expense (recovery)	$	8,955		$	(20,565)		$	26,795		$	(62,236)

Effective tax rate	20		%	16		%	397		%	8		%

Three Months Ended September 30, Nine Months Ended September 30,
(Thousands of U.S. Dollars) 2017 2016 2017 2016
Income (loss) before income tax $ 21,223
$ (336,191 ) $ 59,280
$ (492,732 )

Current income tax expense $ 4,333
$ 3,879
$ 13,522
$ 11,680
Deferred income tax expense (recovery) 13,760
(110,451 ) 36,664
(166,202 )
Total income tax expense (recovery) $ 18,093
$ (106,572 ) $ 50,186

$ (154,522 )

Effective tax rate

85 % 31 %

Deferred income tax recovery related to Colombia ceiling test impairment $ —
$ 119,348
$ —
$ 172,458

For the nine months ended September 30, ~~2017,~~2021, the difference between the effective tax rate of ~~85%~~397% and the ~~35% U.S. statutory~~31% Colombian tax rate was primarily due to the ~~effect~~non-deductibility of ~~foreign taxes, valuation allowances, non-deductible third party royalty in Colombia, stock-based compensation~~derivative instrument losses and ~~other local taxes. These items were partially offset by~~financing costs; foreign currency translation adjustments, and ~~other permanent differences.~~ stock based compensation. These were partially offset by a decrease in valuation allowance and the non-taxable portion (50%) of the unrealized gain on PetroTal Corp. ("PetroTal") shares.

For the nine months ended September 30, ~~2016,~~2020, the difference between the effective tax rate of ~~31%~~8% and the ~~35% U.S. statutory~~32% Colombian tax rate was primarily due to an increase toin the valuation allowance, ~~which was largely attributable to~~the non-deductibility of goodwill impairment ~~losses in Brazil and Colombia, as well as non-deductible local taxes, stock based compensation~~for tax purposes, foreign translation adjustments and the non-deductible ~~third-party royalty in Colombia. These items were partially offset by~~portion (50%) of the ~~impact of foreign taxes, foreign currency translation adjustments and other permanent differences. Other permanent differences mainly related to a non-taxable gain arising~~unrealized loss on ~~the acquisition of Petroamerica, partially offset by prior periods' true-up adjustments, uncertain tax position adjustments and other expenses deductible for tax.~~PetroTal shares.


(Thousands of U.S. Dollars)	Third Quarter 2021 Compared with Second Quarter 2021		% change	Third Quarter 2021 Compared with Third Quarter 2020		% change	Nine Months Ended September 30, 2021 Compared with Nine Months Ended September 30, 2020		% change
Net loss for the comparative period	$	(17,627)		$	(107,821)		$	(730,096)
Increase (decrease) due to:
Sales price	9,162			61,106			150,930
Sales volumes	29,534			21,071			3,460
Expenses:
Operating	(12,136)			(16,846)			(7,950)
Transportation	(100)			(1,735)			101
Cash G&A	1,689			(938)			(1,292)
Net lease payments	47			(70)			(107)
Severance	—			122			550
Interest, net of amortization of debt issuance costs	340			490			(1,243)
Realized foreign exchange	429			2,010			(1,120)
Cash settlements on derivative instruments	16,973			(2,959)			(55,011)
Current taxes	(14)			637			574
Other loss	—			(1,959)			(1,959)
COVID-19 related costs	(93)			118			(1,497)
Interest income	—			—			(345)
Net change in funds flow from operations(1) from comparative period	45,831			61,047			85,091
Expenses:
Depletion, depreciation and accretion	(9,128)			(6,715)			32,818
Goodwill impairment	—			—			102,581
Asset impairment	—			104,731			507,093
Deferred tax	248			(30,157)			(89,605)
Amortization of debt issuance costs	(13)			(69)			92
Stock-based compensation	820			(997)			(7,304)
Derivative instruments gain or loss, net of settlements on derivative instruments	1,663			(1,817)			(1,946)
Other financial instruments gain or loss	16,248			15,094			73,711
Unrealized foreign exchange	(2,988)			(385)			5,390
Other Loss	—			2,026			2,026
Net lease payments	(47)			70			107
Net change in net loss	52,634			142,828			710,054
Net income (loss) for the current period	$	35,007	299%	$	35,007	132%	$	(20,042)	97%

(Thousands of U.S. Dollars) Third Quarter 2017 Compared with Second Quarter 2017 % change Third Quarter 2017 Compared with Third Quarter 2016 % change Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016 % change
Net loss for the comparative period $ (6,807 ) $ (229,619 ) $ (338,210 )
Increase (decrease) due to:
Prices 2,285
16,206
71,333

Sales volumes 5,355
19,023
25,567

Expenses:
   Operating (113 ) (1,683 ) (16,013 )
   Transportation 454
(265 ) 4,846

   Cash G&A and RSU settlements, excluding stock-based compensation expense 784
(2,174 ) (5,031 )
   Transaction —
6,088
7,325

   Severance (1,164 ) (1,164 ) 135

   Interest, net of amortization of debt issuance costs (635 ) (408 ) (3,518 )
   Realized foreign exchange (107 ) (3,004 ) (2,461 )
   Settlement of financial instruments (146 ) (136 ) 1,080

   Current taxes (2,561 ) (454 ) (1,842 )
   Equity tax —
—
1,829

   Other 56
(428 ) (974 )
Net change in funds flow from operations⁽¹⁾ from comparative period
4,208
31,601
82,276

Expenses:

   Depletion, depreciation and accretion (2,848 ) 1,237
11,796

   Asset impairment (618 ) 319,187
468,476

   Deferred tax (2,235 ) (124,211 ) (202,866 )
   Amortization of debt issuance costs (23 ) 1,541
945

   Stock-based compensation, net of RSU settlement 78
(885 ) (1,231 )
   Financial instruments gain or loss, net of financial instruments settlements (2,976 ) 512
5,955

   Unrealized foreign exchange 5,275
3,767
2,741

   Loss on sale of Brazil business unit 9,076
—
(9,076 )
   Gain on acquisition —
—
(11,712 )
Net change in net income or loss 9,937
232,749
347,304

Net income for the current period $ 3,130
146 % $ 3,130
101 % $ 9,094
103 %

⁽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 disclosure above regarding~~measures" for a definition and reconciliation of this measure.

~~2017 Capital Program~~

We expect the range of our projected 2017 capital program to be $225 million to $250 million. We expect to finance our 2017 capital program through cash flows from operations and available capacity under our credit facility, while retaining financial flexibility to undertake further development opportunities and opportunistically pursue acquisitions.

Capital expenditures during the three months ended September 30, ~~2017,~~2021 were ~~$71.7~~$34.8 million:


(Millions of U.S. Dollars)
Colombia:
Exploration	$	6.6
Development:
Drilling and Completions	9.6
Facilities	6.3
Other	11.8
	34.3
Corporate & Ecuador	0.5
	$	34.8

(Thousands of U.S. Dollars)
Colombia $ 70,606
Peru 998
Corporate 90
$ 71,694

During the ~~nine~~three months ended September 30, ~~2017,~~2021, we ~~drilled~~commenced drilling the following wells in Colombia:

Number of wells (Gross) Number of wells (Net)
Development 15
11.6
Exploration 4
2.6
Total Colombia 19
14.2


			Number of wells (Gross and Net)
Development			2.0

~~The significant elements of our third quarter 2017 capital program~~We spud two development wells in ~~Colombia were:~~

On the Chaza Block (100% working interest ("WI"), operated), we successfully drilled Costayaco-30, a directional well targeting the Caballos formation, the U-Sand and A-Limestone in the northern portion of Costayaco field. Costayaco-30 completion work is underway.

~~On the Putumayo-7 Block (100% WI, operated), we completed the Cumplidor and Northwest 3-D seismic programs targeting the A-Limestone.~~

On the Midas Block, ~~(100% WI, operated), we drilled, completed and brought on production~~both of which were producing as oil producers five development wells: Acordionero-12, Acordionero-13, Acordionero-15, Acordionero-17 and Mochuelo-1ST. We successfully completed a workover on the Mochuelo well targeting oil in the Lisama formation and source water for use in Acordionero waterflood. We also commenced drilling the Acordionero-18 and Acordionero-14i wells and completed water injection tests on Acordionero-8i.of September 30, 2021.

~~On the Putumayo-1 Block (55% WI, operated), we completed a production test at the Vonu-1 exploration well with successful production results.~~

~~On the Putumayo-4 Block (100% WI, operated), we started drilling the Siriri-1 exploration well.~~

~~On the Suroriente Block (15.8% WI, non-operated), we completed drilling the Cohembi-21 development well and commenced drilling the Cohembi-22 development well.~~

~~We continued facilities work at the Moqueta and Acordionero Fields.~~

Liquidity and Capital Resources


	As at
(Thousands of U.S. Dollars)	September 30, 2021		% Change	December 31, 2020
Cash and Cash Equivalents	$	16,600	18	$	14,114



Revolving Credit Facility	$	150,000	(21)	$	190,000

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

7.75% Senior Notes	$	300,000	—	$	300,000

The outbreak of the COVID-19 virus, which was declared a pandemic by the World Health Organization in March 2020, spread across the globe and impacted worldwide economic activity. In 2020, global commodity prices declined significantly during the first half of 2020 due to disputes between major oil producing countries combined with the impact of the COVID-19 pandemic and associated reductions in global demand for oil. Governments worldwide, including those in Colombia and Ecuador, the countries where we operate, enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods and social distancing, have caused, and may continue to cause, material disruption to businesses globally resulting in an economic slowdown. While global commodity prices have improved since historic lows during the first half of 2020, the current challenging economic climate had and may continue to have significant adverse impacts on our Company including, but not exclusively:

•material declines in revenue and cash flows as a result of the decline in commodity prices;

•declines in revenue and operating activities due to reduced capital programs and the shut-in of production;

•impairment charges;

•inability to comply with covenants and restrictions in debt agreements;

•inability to access financing sources;

•increased risk of non-performance by our customers and suppliers;

•interruptions in operations as we adjust personnel to the dynamic environment; and

As at
(Thousands of U.S. Dollars) September 30, 2017 % Change December 31, 2016
Cash and Cash Equivalents $ 15,125
(40 ) $ 25,175

Current Restricted Cash and Cash Equivalents $ 3,920
(53 ) $ 8,322

Revolving Credit Facility $ 120,000
33
$ 90,000

Convertible Senior Notes $ 115,000
—
$ 115,000
•inability to operate or delay in operations as a result COVID-19 restrictions in the countries in which we operate

Based on current forecasted Brent pricing and production levels, which can change materially in very short time frames, we forecasted to comply with the financial covenants contained in the revolving credit facility for at least the next year from the date of these financial statements. The amount available under our senior secured credit facility is based on the lender's borrowing base determination. The borrowing base is determined, by the lenders, based on our reserves and commodity prices. The next renewal of the borrowing base is in November 2021, and there is a risk that the lenders may reduce the borrowing base. In addition, our ability to borrow under the credit facility may be limited by the terms of the indentures for the 6.25% Senior Notes and 7.75% Senior Notes.

The risk of non-compliance with the covenants in the lending agreements and the risk associated with maintaining the borrowing base is heightened in the current period of volatility coupled with the unprecedented disruption caused by the COVID-19 pandemic. We ~~believe~~currently expect to continue to meet the terms of the credit facility or obtain further amendments or waivers if and when required. We also expect to maintain the borrowing base at a level in excess of the amount borrowed. However, there can be no assurances that our ~~capital resources, including cash~~liquidity can be maintained at or above current levels during this period of volatility and global economic uncertainty.

The situation is dynamic, and the ultimate duration and magnitude of the impact on ~~hand, cash generated from operations~~the economy and ~~available capacity~~the financial effect on our Company is not known at this time.

As at September 30, 2021, the borrowing base of our Senior Secured Credit Facility (the "revolving credit facility") was $215 million, with the next re-determination to occur no later than November 2021. We are required to comply with various covenants, which have been modified in response to the recent market conditions and the COVID-19 pandemic. We have obtained relief from compliance with certain financial covenants, which expired on October 1, 2021 ("the covenant relief period"). During the covenant relief period, our ratio of total debt to EBITDAX was permitted to be greater than 4.0 to 1.0, our Senior Secured Debt to EBITDAX ratio could not exceed 2.5 to 1.0, and our EBITDAX to interest expense ratio for the trailing four-quarter periods measured as of the last day of the fiscal quarters ending as of the last day of the fiscal quarters ended September 30, 2021, was required to be at least 2.0 to 1.0. We are required to comply with various covenants, which as disclosed above, have been modified in response to the current market conditions and the COVID-19 pandemic. As of September 30, 2021, we were in compliance with all applicable covenants in the revolving credit facility.

After the expiration of the covenant relief period on October 1, 2021, we must maintain compliance with the following financial covenants: limitations on our ratio of debt to EBITDAX to a maximum of 4.0 to 1.0; limitations on our ratio of Senior Secured Debt to EBITDAX to a maximum of 3.0 to 1.0; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. If we fail to comply with these financial covenants, it would result in a default under the terms of the credit agreement, which could result in an acceleration of repayment of all indebtedness under the Company's revolving credit facility.

Amounts drawn under the revolving credit facility ~~will provide~~bear interest, at the borrower's option, USD LIBOR plus a margin ranging from 2.90% to 4.90%, or base rate plus a margin ranging from 1.90% to 3.90%, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. We pay a commitment fee on undrawn amounts under the revolving credit facility, which ranges from 0.73% to 1.23% per annum, based on the average daily amount of unused commitments.

At September 30, 2021, we had $150.0 million drawn under the revolving credit facility. During the third quarter of 2021, we repaid $25.0 million of the amount drawn under the revolving credit facility. Accordingly, we had $65.0 million of availability under the revolving credit facility as of September 30, 2021. As of October 29, 2021, outstanding borrowings under our revolving credit facility were further reduced to $130.0 million.

At September 30, 2021, we had a $300.0 million aggregate principal amount of 6.25% Senior Notes due 2025 and a $300.0 million aggregate principal amount of 7.75% Senior Notes due 2027 outstanding. An event of default under the revolving credit facility would result in a default under the indentures governing the senior notes, which could allow the noteholders to require us ~~with sufficient liquidity~~ to ~~meet our strategic objectives and planned capital program for 2017, given current oil price trends and production levels.~~ repurchase all of the outstanding Senior Notes.

In accordance with our investment policy, available cash balances are held in our primary cash management banks ~~in interest earning current accounts~~ 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.~~

Derivative Positions

At September 30, 2017, we had a revolving credit facility with a syndicate of lenders with a borrowing base of $300 million. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. As a result of the semi-annual redetermination of the committed borrowing base under our revolving credit facility, the committed borrowing base was increased from $250 million to $300 million effective June 1, 2017. The next re-determination of the borrowing base is due to occur no later than November 2017. On September 18, 2017, we entered into the Eighth Amendment to our credit agreement with the other parties thereto, which, among other things, extended the maturity date of the borrowings under the revolving credit facility from September 18, 2018 to October 1, 2018. Subject to documentation, the maturity date of the borrowings under the revolving credit facility is expected to be further extended to November 2020 and the borrowing base is expected to be confirmed at $300 million until May 2018.

Under the terms of our credit facility, we are required to maintain compliance with certain financial and operating covenants which include: the maintenance of a ratio of debt, including letters of credit, to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income (as defined in our credit agreement, "EBITDAX") not to exceed 4.00 to 1.0; the maintenance of a ratio of senior secured obligations to EBITDAX not to exceed 3.00 to 1.00; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. As at September 30, 2017, we were in compliance with all financial and operating covenants in our credit agreement. Under the terms of the credit facility, we are limited in our ability to pay any dividends to our shareholders without bank approval.

~~The 5.00% Convertible Senior Notes due~~ 2021, ~~will mature on April 1, 2021, unless earlier redeemed, repurchased or converted.~~

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

At September 30, 2017, 97% of our cash and cash equivalents were held by subsidiaries and partnerships outside of Canada and the United States. This cash was generally not available to fund domestic or head office operations unless funds were repatriated. At this time, we do not intend to repatriate further funds other than to pay head office charges, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the distribution of accumulated earnings. Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.

In Colombia, we participate in a special exchange regime, and we receive revenue in U.S. dollars offshore. We may also pay invoices denominated in U.S. dollars for our Colombian business from these U.S. dollars received offshore. I~~n Peru, expenditures may be paid in local currency or U.S. dollars.~~

~~Derivative Positions~~

~~At September 30, 2017,~~ we had outstanding commodity price derivative positions as follows:

Period and type of instrument

Volume,
bopd

Reference

Sold Put ($/bbl, Weighted Average)

Purchased Put ($/bbl, Weighted Average)

Sold Call ($/bbl, Weighted Average)

Swap Price ($/bbl, Weighted Average)

Three-way Collars:
October 1, to December 31, 2021

7,000

ICE Brent

47.14

57.14

68.95

n/a

Swaps: October 1, to December 31, 2021

3,000

ICE Brent

n/a

56.75

~~Subsequent to September 30, 2017, we entered into the following commodity price contracts:~~Foreign Currency Derivatives

At September 30, ~~2017,~~2021, we had ~~the following~~ outstanding foreign currency derivative ~~positions:~~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, 2021

3,000

782

COP

3,500

3,630

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,
2017 2016
Sources of cash and cash equivalents:
Net income (loss) $ 9,094
$ (338,210 )
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses 92,729
104,525
Asset impairment 1,239
469,715
Deferred tax expense (recovery) 36,664
(166,202 )
Stock-based compensation expense 4,935
4,380
Amortization of debt issuance costs 1,868
2,813
Cash settlement of RSUs (534 ) (1,210 )
Unrealized foreign exchange (gain) loss (304 ) 2,437
Financial instruments (gain) loss (5,211 ) 1,824
Cash settlement of financial instruments 1,518
438
Loss on sale of Brazil business unit 9,076
—
Gain on acquisition —
(11,712 )
Funds flow from operations 151,074
68,798
Proceeds from bank debt, net of issuance costs 115,264
220,169
Proceeds from sale of Brazil business unit, net of cash sold 34,481
—
Cash deposit received for letter of credit arrangements upon sale of Brazil business unit 4,700
—
Changes in non-cash investing working capital 11,347
—
Net changes in assets and liabilities from operating activities —
18,097
Proceeds from sale of marketable securities —
788
Proceeds from issuance of subscription receipts, net of issuance costs —
165,805
Proceeds from issuance of Notes, net of issuance costs —
109,090
Proceeds from issuance of shares —
5,169
316,866
587,916

Uses of cash and cash equivalents:
Additions to property, plant and equipment (175,719 ) (69,667 )
Additions to property, plant and equipment - property acquisitions (30,410 ) (19,388 )
Repayment of bank debt (85,000 ) (110,181 )
Repurchase of shares of Common Stock (10,000 ) —
Net changes in assets and liabilities from operating activities (28,105 ) —
Changes in non-cash investing working capital —
(8,036 )
Settlement of asset retirement obligations (462 ) (496 )
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents (1,060 ) (452 )
Acquisition of Petroamerica, net of cash acquired —
(457,183 )
(330,756 ) (665,403 )
Net decrease in cash and cash equivalents and restricted cash and cash equivalents $ (13,890 ) $ (77,487 )


	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2021		2020
Sources of cash and cash equivalents:
Net loss	$	(20,042)	$	(730,096)
Adjustments to reconcile net loss to Adjusted EBITDA(1) and funds flow from operations(1)
DD&A expenses	98,300		131,118
Interest expense	41,355		40,204
Income tax expense (recovery)	26,795		(62,236)
Goodwill impairment	—		102,581
Asset impairment	—		507,093
Other loss	—		2,026
Non-cash lease expenses	1,222		1,494
Lease payments	(1,239)		(1,404)
Unrealized foreign exchange loss	16,945		22,335
Stock-based compensation expense (recovery)	6,597		(707)
Unrealized derivative instruments loss	2,499		553
Other financial instruments (gain) loss	(12,425)		61,286
Adjusted EBITDA(1)	160,007		74,247
Current income tax recovery (expense)	14		(560)
Contractual interest and other financing expenses	(38,673)		(37,430)
Funds flow from operations(1)	121,348		36,257
Proceeds from debt, net of issuance costs	—		88,382
Proceeds from issuance of Senior Notes, net of issuance costs	—		—
Proceeds from issuance of exercise of stock options	19		—
Proceeds from disposition of investment, net of transaction costs	14,632		—
Net changes in assets and liabilities from operating activities	17,956		23,288
Changes in non-cash investing working capital	709		—
	154,664		147,927

Uses of cash and cash equivalents:
Additions to property, plant and equipment	(109,650)		(56,378)

Repayment of debt	(40,000)		(7,000)


Debt issuance costs	(125)		—

Changes in non-cash investing working capital	—		(69,549)
Settlement of asset retirement obligations	(483)		(199)
Lease payments	(1,269)		(307)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(528)		(754)
	(152,055)		(134,187)
Net increase in cash and cash equivalents and restricted cash and cash equivalents	$	2,609	$	13,740

~~Cash provided by operating activities in the~~ ~~nine months ended September 30, 2017, was primarily affected by higher~~(1) Adjusted EBITDA and funds flow from operations ~~(see~~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 ~~net income (loss) to funds flow from operations under the heading 'Financial and Operational Highlights' above) and a $28.1 million change in assets and liabilities from operating activities.~~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 price derivatives. Sales volume changes and costs related to operations and debt service also impact cash ~~flow.~~flows. 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. During the nine months ended September 30, 2021, funds flow from operations increased by 235% compared to the corresponding period of 2020 primarily due to a significant increase in Brent price and increase in production, which were offset by an increase in operating expenses and cash settlements on derivative instruments.

Off-Balance Sheet Arrangements

As at September 30, ~~2017,~~2021, we had no off-balance sheet arrangements.

Contractual Obligations

~~During the nine months ended~~At September 30, ~~2017,~~2021, we ~~borrowed a net amount of $30.3~~had $150.0 million ondrawn under our revolving credit facility. ~~Additionally, at June 30, 2017, we sold our Brazil business unit and its related obligations.~~

Except asfor noted above, as at September 30, ~~2017,~~2021, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at December 31, ~~2016.~~2020.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our ~~2016~~2020 Annual Report on Form 10-K ~~filed with the SEC on March 1, 2017,~~ and have not changed materially since the filing of that ~~document, other than as follows:~~document.

~~Full Cost Method of Accounting and Impairments of Oil and Gas Properties~~

In the nine months ended September 30, 2017, we had no ceiling test impairment losses in our Colombia and Brazil cost centers. We used an average Brent price of $52.70 per bbl for the purposes of the September 30, 2017 ceiling test calculations (June 30, 2017 - $51.35, March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48, March 31, 2016 - $48.79; December 31, 2015 - $54.08).

Holding all factors constant other than benchmark oil prices, it is reasonably likely that we will not experience ceiling test impairment losses in our Colombia cost center in the fourth quarter of 2017. It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed U.S. GAAP ceiling test calculation. These factors include, but are not limited to, future commodity pricing, royalty rates in different pricing environments, operating costs and negotiated savings, foreign exchange rates, capital expenditures timing and negotiated savings, production and its impact on depletion and cost base, upward or downward reserve revisions as a result of ongoing exploration and development activity, and tax attributes.

Subject to these factors and inherent limitations, we do not believe that ceiling test impairment losses will be experienced in the fourth quarter of 2017. The calculation of the impact of higher commodity prices on our estimated ceiling test calculation was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of benchmark oil prices. Therefore, this calculation strictly isolates the impact of commodity prices on the prescribed GAAP ceiling test. This calculation was based on a pro forma Brent oil price of $54.16 per bbl for the year ended December 31, 2017. This pro forma oil price was calculated using a 12-month unweighted arithmetic average of oil prices, and included the oil prices on the first day of the month for the ten months ended October 31, 2017, and, for the two months ended December 31, 2017, estimated oil prices for the fourth quarter of 2017 using the forward price curve forecast from Bloomberg dated September 30, 2017.

As noted above, actual cash flows may be materially affected by other factors. For example, in Colombia, cash royalties are levied at lower rates in low oil price environments and foreign exchange rates can materially impact the deferred tax component of the asset base, operating costs, and the income tax calculation.

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 West Texas Intermediate ("WTI") or 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. In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. In Peru, capital expenditures are based on U.S. dollar prices and may be paid in local currency or U.S. dollars. The majority of income and value added taxes and G&A expenses in Colombia and Peru 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.

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~~Smaller Reporting Company, we are not required to ~~the U.S. dollar functional currency.~~provide information under this Item 3.

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

~~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, 2017, our outstanding revolving credit facility was $120.0 million (December 31, 2016 - $90.0 million), which had a weighted-average interest rate of approximately 3.5%. A 10% change in LIBOR would not materially impact our interest expense on debt outstanding at September 30, 2017.

~~Further information~~

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

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, ~~including~~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 ~~their~~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, ~~2017.~~2021.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, ~~2017~~,2021, 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 911 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, ~~2016,~~2020, and any material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

~~See~~There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this quarterly report on Form 10-Q, including in Part I, Item ~~1A Risk Factors~~2 "Management's Discussion and Analysis of ~~our 2016 Annual Report on Form 10-K. The risks facing our company have not changed materially from those~~Financial Condition and Results of Operations", you should carefully read and consider the factors set ~~forth~~out in Part I, Item 1A ~~Risk Factors of~~"Risk Factors" in our ~~2016~~ Annual Report on Form ~~10-K.~~10-K for the year ended December 31, 2020. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of the current pandemic and downturn in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks.

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

None.

Item 6. Exhibits


Exhibit No.		Description		Reference

~~Exhibit No.~~		~~Description~~	~~Reference~~
~~2.1+~~3.1	~~Arrangement Agreement, dated November 12, 2015, between Gran Tierra Energy Inc. and Petroamerica Oil Corp.~~		~~Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 18, 2015 (SEC File No. 001-34018).~~

~~2.2~~	~~Plan of Conversion, dated October 31, 2016.~~	~~Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).~~

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

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

~~4.1~~3.3		~~Reference is made to~~ ~~Exhibit 3.1~~Certificate of Retirement dated July 9, 2018 to ~~Exhibit 3.2~~.

~~4.2~~	~~Details of the Goldstrike Special Voting Share.~~	Incorporated by reference to Exhibit ~~10.14 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005, and filed with the SEC on April 21, 2006 (SEC File No. 333-111656).~~

~~4.3~~	~~Goldstrike Exchangeable Share Provisions.~~	~~Incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the SEC on April 21, 2006 (SEC File No. 333-111656).~~

~~4.4~~	~~Provisions Attaching to the GTE–Solana Exchangeable Shares.~~	~~Incorporated by reference to Annex E to the Proxy Statement on Schedule 14A filed with the SEC on October 14, 2008 (SEC File No. 001-34018).~~

~~4.5~~	~~Indenture related to the 5.00% Convertible Senior Notes due 2021, dated as of April 6, 2016, between Gran Tierra Energy Inc. and U.S. Bank National Association~~	~~Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).~~

~~4.6~~	~~Form of 5.00% Convertible Senior Notes due 2021~~	~~Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).~~

~~4.7~~	~~Subscription Receipt Agreement, dated July 8, 2016, by and between Gran Tierra Energy Inc. and Computershare Trust Company of Canada.~~	~~Incorporated by reference to Exhibit 4.1~~3.1 to the Current Report on Form 8-K filed with the SEC on July ~~14, 2016~~9, 2018 (SEC File No. 001-34018).

~~4.8~~3.4		~~Form~~Amendment No.1 to Bylaws of ~~Registration Rights Agreement.~~Gran Tierra Energy Inc.		Incorporated by reference to Exhibit ~~4.2~~3.1 to the Current Report on Form 8-K filed with the SEC on ~~July 14, 2016~~August 4, 2021 (SEC File No. 001-34018).



~~10.1~~31.1		Eighth Amendment to Credit Agreement, dated as of September 18, 2017, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., the Bank of Nova Scotia and the lenders party thereto.		~~Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2017 (SEC File No. 001-34018).~~

~~10.2~~	Amendment #4, dated August 31, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.A.R.L. and Maha Energy AB.	~~Filed herewith.~~

~~12.1~~	~~Statement re: Computation of Ratio of Earnings to Fixed Charges~~	~~Filed herewith.~~

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

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

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

101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH 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

+ ~~Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K.~~104.The cover page from Gran Tierra ~~undertakes to furnish supplemental copies of any of~~Energy Inc.'s Quarterly Report on Form 10-Q for the ~~omitted schedules upon request by~~quarter ended September 30, 2021, formatted in Inline XBRL (included within the ~~SEC.~~Exhibit 101 attachments).

*Management contract or compensatory plan or arrangement

SIGNATURES

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

GRAN TIERRA ENERGY INC.



Date: November ~~2, 2017~~3, 2021						/s/ Gary S. Guidry
						By: Gary S. Guidry
						President and Chief Executive Officer
						(Principal Executive Officer)



Date: November ~~2, 2017~~3, 2021						/s/ Ryan Ellson
						By: Ryan Ellson
						Executive Vice President and Chief Financial Officer
						(Principal Financial and Accounting Officer)


Large accelerated filer			☐	Accelerated filer	☒
Non-accelerated filer			☐	Smaller reporting company	☒

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



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



	September 30,			December 31,
	2017			2016
ASSETS
Current Assets
Cash and cash equivalents (Note 11)	$	15,125		$	25,175
Restricted cash and cash equivalents (Notes 7 and 11)	3,920			8,322
Accounts receivable	38,279			45,698
Derivatives (Note 10)	512			578
Inventory (Note 4)	6,978			7,766
Taxes receivable	34,879			26,393
Prepaid taxes (Note 2)	—			12,271
Other prepaids	2,194			5,482
Total Current Assets	101,887			131,685

Oil and Gas Properties (using the full cost method of accounting)
Proved	508,981			412,319
Unproved	613,419			647,774
Total Oil and Gas Properties	1,122,400			1,060,093
Other capital assets	5,224			6,516
Total Property, Plant and Equipment (Notes 3 and 4)	1,127,624			1,066,609

Other Long-Term Assets
Deferred tax assets (Note 2)	66,963			1,611
Prepaid taxes (Note 2)	—			41,784
Restricted cash and cash equivalents (Notes 7 and 11)	10,332			9,770
Other long-term assets	13,789			13,856
Goodwill (Note 3)	102,581			102,581
Total Other Long-Term Assets	193,665			169,602
Total Assets (Note 3)	$	1,423,176		$	1,367,896
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	119,829		$	107,051
Derivatives (Note 10)	65			3,824
Taxes payable (Note 2)	2,419			38,939
Asset retirement obligation (Note 7)	355			5,215
Total Current Liabilities	122,668			155,029

Long-Term Liabilities
Long-term debt (Notes 5 and 10)	229,215			197,083
Deferred tax liabilities (Note 2)	29,368			107,230
Asset retirement obligation (Note 7)	43,649			38,142
Other long-term liabilities	13,816			11,425
Total Long-Term Liabilities	316,048			353,880

Contingencies (Note 9)

Shareholders’ Equity
Common Stock (Note 6) (386,872,530 and 390,807,194 shares of Common Stock and 7,898,664 and 8,199,894 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2017, and December 31, 2016, respectively)	10,299			10,303
Additional paid in capital	1,334,563			1,342,656
Deficit	(360,402		)	(493,972		)
Total Shareholders’ Equity	984,460			858,987
Total Liabilities and Shareholders’ Equity	$	1,423,176		$	1,367,896



	Nine Months Ended September 30,			Year Ended December 31,
	2017			2016
Share Capital
Balance, beginning of period	$	10,303		$	10,186
Issuance of Common Stock	—			117
Repurchase of Common Stock (Note 6)	(4		)	—
Balance, end of period	10,299			10,303

Additional Paid in Capital
Balance, beginning of period	1,342,656			1,019,863
Issuance of Common Stock, net of share issuance costs	—			314,425
Exercise of stock options	—			5,347
Stock-based compensation (Note 6)	1,903			3,021
Repurchase of Common Stock (Note 6)	(9,996		)	—
Balance, end of period	1,334,563			1,342,656

Deficit
Balance, beginning of period	(493,972		)	(28,407		)
Net income (loss)	9,094			(465,565		)
Cumulative adjustment for accounting change related to tax reorganizations (Note 2)	124,476			—
Balance, end of period	(360,402		)	(493,972		)

Total Shareholders’ Equity	$	984,460		$	858,987



	Three Months Ended September 30, 2017
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	103,768		$	—		$	—		$	—		$	103,768
Depletion, depreciation and accretion	33,388			881			—			223			34,492
Asset impairment	—			176			—			611			787
General and administrative expenses	5,500			301			—			2,850			8,651
Income (loss) before income taxes	31,276			(1,405		)	—			(8,648		)	21,223
Segment capital expenditures	70,606			998			—			90			71,694

	Three Months Ended September 30, 2016
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	65,944		$	—		$	2,595		$	—		$	68,539
Depletion, depreciation and accretion	34,156			206			1,022			345			35,729
Asset impairment	298,370			—			21,604			—			319,974
General and administrative expenses	1,921			218			218			3,235			5,592
Loss before income taxes	(299,306		)	(768		)	(20,977		)	(15,140		)	(336,191		)
Segment capital expenditures	20,476			1,360			3,102			142			25,080

	Nine Months Ended September 30, 2017
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	286,137		$	—		$	8,418		$	—		$	294,555
Depletion, depreciation and accretion	88,453			1,350			2,263			663			92,729
Asset impairment	—			628			—			611			1,239
General and administrative expenses	15,561			974			743			9,598			26,876
Income (loss) before income taxes	90,018			(2,685		)	3,369			(31,422		)	59,280
Segment capital expenditures	168,881			3,207			2,811			820			175,719

	Nine Months Ended September 30, 2016
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	191,515		$	—		$	6,140		$	—		$	197,655
Depletion, depreciation and accretion	100,350			418			2,764			993			104,525
Asset impairment	431,810			899			37,006			—			469,715
General and administrative expenses	9,614			1,014			751			9,235			20,614
Loss before income taxes	(436,863		)	(2,224		)	(36,523		)	(17,122		)	(492,732		)
Segment capital expenditures	56,997			3,730			7,982			958			69,667



(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash	$	30,410

Allocation of Consideration Paid:
Oil and gas properties
Proved	$	24,405
Unproved	8,649
	33,054
Inventory	869
Asset retirement obligation - long-term	(3,513		)
	$	30,410



	Shares of Common Stock		Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2016	390,807,194		4,812,592		3,387,302
Shares repurchased and canceled	(4,235,890	)	—		—
Exchange of exchangeable shares	301,230		(142,500	)	(158,730	)
Shares canceled	(4	)	—		—
Balance, September 30, 2017	386,872,530		4,670,092		3,228,572



	PSUs		DSUs	RSUs		Stock Options
	Number of Outstanding Share Units		Number of Outstanding Share Units	Number of Outstanding Share Units		Number of Outstanding Stock Options		Weighted Average Exercise Price/Stock Option ($)
Balance, December 31, 2016	3,362,717		208,698	359,145		9,239,478		4.16
Granted	3,229,620		171,388	—		1,964,156		2.54
Exercised	—		—	(211,022	)	—		—
Forfeited	(641,159	)	—	(9,402	)	(903,910	)	(4.81	)
Expired	—		—	—		(1,396,667	)	(4.65	)
Balance, September 30, 2017	5,951,178		380,086	138,721		8,903,057		3.66



	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 30, 2017			December 31, 2016
Balance, beginning of period	$	43,357		$	33,224
Liability incurred	2,942			2,606
Liabilities assumed in acquisition	3,513			15,723
Accretion	3,101			2,789
Settlements	(1,039		)	(872		)
Liabilities associated with assets sold	(2,200		)	(3,257		)
Revisions in estimated liability	(5,670		)	(6,856		)
Balance, end of period	$	44,004		$	43,357

Asset retirement obligation - current	$	355		$	5,215
Asset retirement obligation - long-term	43,649			38,142
	$	44,004		$	43,357



	Third Quarter 2017 Compared with Second Quarter 2017		Third Quarter 2017 Compared with Third Quarter 2016		Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016
Oil and natural gas sales for the comparative period	$	96,128	$	68,539	$	197,655
Realized sales price increase effect	2,285		16,206		71,333
Sales volume increase effect	5,355		19,023		25,567
Oil and natural gas sales for period ended September 30, 2017	$	103,768	$	103,768	$	294,555



U.S. Dollars Per BOE Sales Volumes NAR	Third Quarter 2017 Compared with Second Quarter 2017			Third Quarter 2017 Compared with Third Quarter 2016		Nine Months Ended, September 30, 2017 Compared with Nine Months Ended September 30, 2016
Average realized price net of transportation expenses for the comparative period	$	37.42		$	31.72	$	27.33
Increase in benchmark prices	1.26			$	5.20	10.52
(Increase) decrease in quality and transportation discounts	(0.35		)	1.20		(0.53		)
Lower transportation expenses	0.37			0.58		1.16
Average realized price net of transportation expenses for period ended September 30, 2017	$	38.70		$	38.70	$	38.48



	Number of wells (Gross)	Number of wells (Net)
Development	15	11.6
Exploration	4	2.6
Total Colombia	19	14.2