UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

 For the quarterly period ended September 30, 2016

or

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

 For the transition period from __________ to  __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)

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

(403) 265-3221

(Registrant’s telephone number, including area code)

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

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

Yes   ý  No o

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

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

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, 2016, the following number of shares of the registrant’s capital stock were outstanding: 347,293,909 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 3,537,302 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 4,840,877 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

1

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended September 30, 2016

Table of contents

		Page
PART I	Financial Information
Item 1.	Financial Statements	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46
PART II	Other Information
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 6.	Exhibits	47
SIGNATURES		47
EXHIBIT INDEX		48

2

 CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “objective”, “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, those set out in Part II, Item 1A “Risk Factors” in our Quarterly Reports on Form 10-Q and in Part I, Item 1A “Risk Factors” in our 2015 Annual Report on Form 10-K. The information included herein is given as of the filing date of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

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

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

Sales volumes represent production NAR adjusted for inventory changes and losses. 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.

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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,
	2016			2015			2016			2015
OIL AND NATURAL GAS SALES (NOTE 4)	$	68,539		$	75,653		$	197,655		$	221,234
EXPENSES
Operating	25,638			20,894			62,453			61,313
Transportation	5,773			12,857			24,318			28,005
Depletion, depreciation and accretion (Note 4)	35,729			55,015			104,525			143,343
Asset impairment (Notes 4 and 5)	319,974			149,978			469,715			217,277
General and administrative (Note 4)	5,592			7,863			20,614			25,455
Transaction (Note 3)	6,088			—			7,325			—
Severance	—			461			1,299			6,827
Equity tax (Note 9)	—			—			3,053			3,769
Foreign exchange (gain) loss	(507		)	(12,923		)	1,059			(21,492		)
Financial instruments loss (Note 11)	2,051			2,670			1,824			1,262
Interest expense (Note 6)	5,122			—			7,842			—
	405,460			236,815			704,027			465,759
GAIN ON ACQUISITION (NOTE 3)	—			—			11,712			—
INTEREST INCOME	730			266			1,928			1,069
LOSS BEFORE INCOME TAXES (NOTE 4)	(336,191		)	(160,896		)	(492,732		)	(243,456		)
INCOME TAX (EXPENSE) RECOVERY
Current	(3,879		)	(3,523		)	(11,680		)	(11,632		)
Deferred	110,451			62,542			166,202			69,781
	106,572			59,019			154,522			58,149
NET LOSS AND COMPREHENSIVE LOSS	$	(229,619	)	$	(101,877	)	$	(338,210	)	$	(185,307	)
NET LOSS PER SHARE - BASIC AND DILUTED	$	(0.71	)	$	(0.36	)	$	(1.11	)	$	(0.65	)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC AND DILUTED (Note 7)	321,725,379			285,592,382			304,098,944			286,057,952

(See notes to the condensed consolidated financial statements)

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Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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

	September 30,			December 31,
	2016			2015
ASSETS
Current Assets
Cash and cash equivalents	$	48,073		$	145,342
Restricted cash (Notes 3, 5 and 8)	13,198			92
Accounts receivable	20,834			29,217
Marketable securities (Note 11)	2,536			6,250
Derivatives (Note 11)	5,226			—
Inventory (Note 5)	11,808			19,056
Taxes receivable	31,660			28,635
Other current assets	3,003			5,848
Total Current Assets	136,338			234,440
Oil and Gas Properties
Proved	429,105			469,589
Unproved	766,902			310,771
Total Oil and Gas Properties	1,196,007			780,360
Other capital assets	7,924			8,633
Total Property, Plant and Equipment (Notes 4 and 5)	1,203,931			788,993
Other Long-Term Assets
Restricted cash (Notes 3 and 8)	9,993			3,317
Taxes receivable	9,468			8,276
Other long-term assets	24,846			8,511
Goodwill (Note 4)	102,581			102,581
Total Other Long-Term Assets	146,888			122,685
Total Assets (Note 4)	$	1,487,157		$	1,146,118
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	96,829		$	70,778
Short-term debt (Notes 6 and 11)	127,519			—
Taxes payable	6,444			1,067
Asset retirement obligation (Note 8)	3,673			2,146
Total Current Liabilities	234,465			73,991
Long-Term Liabilities
Long-term debt (Notes 6 and 11)	172,790			—
Deferred tax liabilities	161,080			34,592
Asset retirement obligation (Note 8)	45,028			31,078
Other long-term liabilities	11,214			4,815
Total Long-Term Liabilities	390,112			70,485
Contingencies (Note 10)
Subsequent Events (Note 13)
Shareholders’ Equity
Common Stock (Note 7) (347,291,709 and 273,442,799 shares of Common Stock and 8,380,379 and 8,572,066 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2016, and December 31, 2015, respectively)	10,260			10,186
Additional paid in capital	1,218,937			1,019,863
Deficit	(366,617		)	(28,407		)
Total Shareholders’ Equity	862,580			1,001,642
Total Liabilities and Shareholders’ Equity	$	1,487,157		$	1,146,118

(See notes to the condensed consolidated financial statements)

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Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)

	Nine Months Ended September 30,
	2016			2015
Operating Activities
Net loss	$	(338,210	)	$	(185,307	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 4)	104,525			143,343
Asset impairment (Notes 4 and 5)	469,715			217,277
Deferred tax recovery	(166,202		)	(69,781		)
Stock-based compensation expense (Note 7)	4,380			2,126
Amortization of debt issuance costs (Note 6)	2,813			—
Cash settlement of restricted share units	(1,210		)	(1,363		)
Unrealized foreign exchange loss (gain)	2,437			(13,093		)
Financial instruments loss (Note 11)	1,824			1,262
Cash settlement of financial instruments	438			(3,749		)
Cash settlement of asset retirement obligation (Note 8)	(496		)	(4,768		)
Gain on acquisition (Note 3)	(11,712		)	—
Net change in assets and liabilities from operating activities (Note 12)	18,097			(27,368		)
Net cash provided by operating activities	86,399			58,579
Investing Activities
(Increase) decrease in restricted cash	(5,334		)	298
Additions to property, plant and equipment, excluding Corporate acquisition (Note 4)	(69,667		)	(114,793		)
Additions to property, plant and equipment - acquisition of PetroGranada Colombia Limited (Note 5)	(19,388		)	—
Changes in non-cash investing working capital	(8,036		)	(76,744		)
Cash paid for business combinations, net of cash acquired (Note 3)	(471,631		)	—
Proceeds from sale of marketable securities (Note 11)	788			—
Net cash used in investing activities	(573,268		)	(191,239		)
Financing Activities
Proceeds from issuance of subscription receipts, net of issuance costs (Note 7)	165,805			—
Proceeds from issuance of Convertible Senior Notes, net of issuance costs (Note 6)	109,090			—
Proceeds from other debt, net of issuance costs (Note 6)	220,169			—
Repayment of debt (Note 6)	(110,181		)	—
Proceeds from issuance of shares of Common Stock (Note 7)	5,169			602
Repurchase of shares of Common Stock	—			(6,616		)
Net cash provided by (used in) financing activities	390,052			(6,014		)
Foreign exchange loss on cash and cash equivalents	(452		)	(6,196		)
Net decrease in cash and cash equivalents	(97,269		)	(144,870		)
Cash and cash equivalents, beginning of period	145,342			331,848
Cash and cash equivalents, end of period	$	48,073		$	186,978
Supplemental cash flow disclosures (Note 12)

(See notes to the condensed consolidated financial statements)

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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,
	2016			2015
Share Capital
Balance, beginning of period	$	10,186		$	10,190
Issuance of Common Stock (Note 7)	74			—
Repurchase of Common Stock	—			(4		)
Balance, end of period	10,260			10,186
Additional Paid in Capital
Balance, beginning of period	1,019,863			1,026,873
Issuance of Common Stock, net of share issuance costs (Note 7)	191,364			—
Exercise of stock options (Note 7)	5,347			722
Stock-based compensation (Note 7)	2,363			2,263
Repurchase of Common Stock	—			(9,995		)
Balance, end of period	1,218,937			1,019,863
Retained Earnings (Deficit)
Balance, beginning of period	(28,407		)	239,622
Net loss	(338,210		)	(268,029		)
Balance, end of period	(366,617		)	(28,407		)
Total Shareholders’ Equity	$	862,580		$	1,001,642

(See notes to the condensed consolidated financial statements)

7

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

(Expressed in U.S. Dollars, unless otherwise indicated)

1. Description of Business

Gran Tierra Energy Inc., a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on oil and natural gas exploration and production in Colombia. The Company also has business activities in Peru and Brazil.

2. Significant Accounting Policies

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

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2015, included in the Company’s 2015 Annual Report on Form 10-K, filed with the SEC on February 29, 2016.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2015 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as noted below. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

Convertible Senior Notes

The Company accounts for its 5.00% Convertible Senior Notes due 2021 (the "Notes") as a liability in their entirety. The embedded features of the Notes were assessed for bifurcation from the Notes under the applicable provisions, including the basic conversion feature, the fundamental change make-whole provision and the put and call options. Based on an assessment, the Company concluded that these embedded features did not meet the criteria to be accounted for separately.

The Company incurred debt issuance costs in connection with the issuance of the Notes which have been presented as a direct deduction against the carrying amount of the Notes and are being amortized to interest expense using the effective interest method over the contractual term of the Notes.

Derivatives

The Company's commodity price and foreign currency derivatives are recorded on its interim unaudited condensed consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized in the interim unaudited condensed consolidated statements of operations. While the Company utilizes derivative instruments to manage the price risk attributable to its expected oil production and foreign exchange risk, it has elected not to designate its derivative instruments as accounting hedges under the accounting guidance.

Recently Adopted Accounting Pronouncements

Simplifying the Accounting for Measurement - Period Adjustments

In September 2015, the Financial Accounting Standards Board (the "FASB") issued Accounting Standards Update (“ASU") 2015-16, "Simplifying the Accounting for Measurement - Period Adjustments". The amendments require that an acquirer recognize adjustments to provisional amounts identified during the measurement period in the reporting period in which the adjustments are determined and eliminates the requirement to retrospectively revise prior periods. Additionally, an acquirer should record in the same period the effects on earnings of any changes in the provisional accounts, calculated as if the accounting had been completed at the acquisition date. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

8

Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments". This ASU addresses specific cash flow issues with the objective of reducing the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The Company implemented this update retrospectively in its consolidated financial statements for the interim period ended September 30, 2016. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

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 defers 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 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing" which clarifies implementation guidance. In May 2016, the FASB issued ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients" which reduces the potential for diversity in practice at initial application and the cost and complexity of applying Topic 606 both at transition and on an ongoing basis. The Company is currently assessing the impact the new revenue recognition model will have on its consolidated financial position, results of operations, cash flows, and disclosure.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases". This ASU will require most lease assets and lease liabilities to be recognized on the balance sheet and the disclosure of key information about lease arrangements. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. The Company is currently assessing the impact the new lease standard will have on its consolidated financial position, results of operations, cash flows, and 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 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently assessing the impact this update will have on its consolidated financial position, results of operations, cash flows, and disclosure.

Financial Instruments - Credit Losses

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses". This ASU replaces the current incurred loss impairment methodology with a methodology that reflects expected credit losses and requires a broader range of reasonable and supportable information to support credit loss estimates. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company is currently assessing the impact this update will have on its consolidated financial position, results of operations, cash flows, and disclosure.

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

In October 2016, the FASB issued ASU 2016-16, "Intra-Entity Transfers of Assets Other than Inventory". Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity transfer until the asset has been sold to an outside party. This ASU eliminates the exception for intra-entity transfers of assets other than inventory and requires the income tax consequences of an intra-entity transfer of an asset other than inventory to be recognized when the transfer occurs. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. Early adoption is permitted as of the beginning of an annual reporting period. The amendments in the ASU shall be applied on a

9

modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact this update will have on its consolidated financial position, results of operations, cash flows, and disclosure.

3. Business Combinations

a) PetroLatina Energy Ltd.

On August 23, 2016 (the “PetroLatina Acquisition Date”), the Company acquired all of the issued and outstanding common shares of PetroLatina Energy Ltd. ("PetroLatina") for $525.0 million, consisting of cash consideration of $442.6 million, a deferred cash payment of $25.0 million to be paid prior to December 31, 2016, assumption of a reserve-backed credit facility with an outstanding balance of $80.0 million (Note 6), net working capital of $15.5 million, and other closing adjustments. Upon completion of the transaction on the PetroLatina Acquisition Date, Gran Tierra repaid and canceled the reserve-based credit facility and PetroLatina became an indirect wholly-owned subsidiary of Gran Tierra.

PetroLatina is an exploration and production company, incorporated in England and Wales, with assets primarily in the Middle Magdalena Basin of Colombia. The acquisition added a new core area for Gran Tierra in the prolific Middle Magdalena Basin and was accounted for as a business combination using the acquisition method, with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the PetroLatina Acquisition Date, and the results of PetroLatina were included with those of Gran Tierra from that date. Fair value estimates were made based on significant unobservable (Level 3) inputs and based on the best information available at the time.

The following table shows the allocation of the consideration based on the fair values of the assets and liabilities acquired:

(Thousands of U.S. Dollars)
Consideration Paid:
Purchase price	$	525,000
Purchase price adjustments:
PetroLatina's long-term debt assumed	(80,000		)
Working capital and other	16,350
Total cash consideration	461,350
Deferred cash payment	(25,000		)
Estimated post-closing adjustments	6,241
Cash consideration paid	$	442,591
Allocation of Total Consideration(1):
Oil and gas properties
Proved	$	364,353
Unproved	422,734
Net working capital (including cash acquired of $21.9 million, restricted cash of $0.7 million and accounts receivable of $4.0 million)	15,486
Long-term restricted cash	3,017
Long-term debt	(80,000		)
Long-term deferred tax liability	(259,401		)
Long-term portion of asset retirement obligation	(3,870		)
Other long-term liabilities	(969		)
	$	461,350

⁽¹⁾ The allocation of the consideration is incomplete and is subject to change. Management is continuing to review and assess information to accurately determine the acquisition date fair value of the assets and liabilities acquired. During the measurement period, Gran Tierra will continue to obtain information to assist in finalizing the fair value of net assets acquired, which may differ materially from the above preliminary estimates.

10

The Company's consolidated statement of operations for the three and nine months ended September 30, 2016, included oil and gas sales of $5.3 million and a loss after tax of $193.5 million from PetroLatina for the period subsequent to the PetroLatina Acquisition Date.

Pro Forma Results (unaudited)

Pro forma results for the nine months ended September 30, 2016 and 2015, are shown below, as if the acquisition had occurred on January 1, 2015. Pro forma results are not indicative of actual results or future performance.

	Nine Months Ended September 30,
(Unaudited, thousands of U.S. Dollars, except per share amounts)	2016			2015
Oil and gas sales	$	231,652		$	288,538
Net loss	$	(339,441	)	$	(233,644	)
Net loss per share - basic and diluted	$	(1.12	)	$	(0.82	)

The supplemental pro forma net loss of Gran Tierra for the nine months ended September 30, 2016, was adjusted to exclude $6.1 million of transaction expenses because they were not expected to have a continuing impact on Gran Tierra’s results of operations.

b) Petroamerica Oil Corp.

On January 13, 2016 (the “Petroamerica Acquisition Date”), the Company acquired all of the issued and outstanding common shares of Petroamerica Oil Corp. ("Petroamerica"), a Canadian corporation, pursuant to the terms and conditions of an arrangement agreement dated November 12, 2015 (the “Arrangement”). The transaction contemplated by the Arrangement was effected through a court approved plan of arrangement in Canada. The Arrangement was approved at a special meeting of Petroamerica shareholders and by the Court of Queen's Bench of Alberta on January 11, 2016. Under the Arrangement, each Petroamerica shareholder was entitled to receive, for each Petroamerica share held, either 0.40 of a Gran Tierra common share or $1.33 Canadian dollars in cash, or a combination of shares and cash, subject to a maximum of 70% of the consideration payable in cash.

As consideration for the acquisition of all the issued and outstanding Petroamerica shares, the Company issued approximately 13.7 millionshares of Gran Tierra Common Stock, par value $0.001, and paid cash consideration of approximately $70.6 million. The fair value of Gran Tierra’s Common Stock issued was determined to be $25.8 million based on the closing price of shares of Common Stock of Gran Tierra as at the Petroamerica Acquisition Date. Total net purchase price of Petroamerica was $72.2 million, after giving consideration to net working capital of $24.2 million. Upon completion of the transaction on the Petroamerica Acquisition Date, Petroamerica became an indirect wholly-owned subsidiary of Gran Tierra.

The acquisition was accounted for as a business combination using the acquisition method, with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the Petroamerica Acquisition Date, and the results of Petroamerica were included with those of Gran Tierra from that date. Fair value estimates were made based on significant unobservable (Level 3) inputs and based on the best information available at the time.

The following table shows the allocation of the consideration paid based on the fair values of the assets and liabilities acquired:

11

(Thousands of U.S. Dollars)
Consideration Paid:
Cash	$	70,625
Issuance of Common Shares, net of share issuance costs	25,811
	$	96,436
Allocation of Consideration Paid(1):
Oil and gas properties
Proved	$	48,595
Unproved	50,054
Net working capital (including cash acquired of $19.7 million, restricted cash of $2.5 million and accounts receivable of $5.0 million)	24,202
Long-term restricted cash	8,167
Other long-term assets	1,570
Long-term deferred tax liability	(10,105		)
Long-term portion of asset retirement obligation	(11,556		)
Other long-term liabilities	(2,779		)
Gain on acquisition	(11,712		)
	$	96,436

⁽¹⁾ The allocation of the consideration paid is incomplete and is subject to change. Management is continuing to review and assess information to accurately determine the acquisition date fair value of the assets and liabilities acquired. During the measurement period, Gran Tierra will continue to obtain information to assist in finalizing the fair value of net assets acquired, which may differ materially from the above preliminary estimates.

As indicated in the allocation of the consideration paid, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration paid. Consequently, Gran Tierra reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, Gran Tierra recognized a “Gain on acquisition” of $11.7 million in the interim unaudited condensed consolidated statement of operations for the nine months ended September 30, 2016. The gain reflects the impact on Petroamerica’s pre-acquisition market value resulting from the company's lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects.

The Company's consolidated statement of operations for the nine months ended September 30, 2016, included oil and gas sales of $12.6 million and a loss after tax of $24.1 million from Petroamerica for the period subsequent to the Petroamerica Acquisition Date.

Pro Forma Results (unaudited)

Pro forma results for the nine months ended September 30, 2016 and 2015, are shown below, as if the acquisition had occurred on January 1, 2015. Pro forma results are not indicative of actual results or future performance.

	Nine Months Ended September 30,
(Unaudited, thousands of U.S. Dollars, except per share amounts)	2016			2015
Oil and gas sales	$	198,125		$	267,049
Net loss	$	(349,935	)	$	(218,302	)
Net loss per share - basic and diluted	$	(1.15	)	$	(0.76	)

The supplemental pro forma net loss of Gran Tierra for the nine months ended September 30, 2016, was adjusted to exclude the $11.7 million gain on acquisition and $1.2 million of transaction expenses because they were not expected to have a continuing impact on Gran Tierra’s results of operations.

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4. 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, Peru and Brazil based on geographic organization. The All Other category represents the Company’s corporate activities. The Company evaluates reportable segment performance based on income or loss before income taxes.

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

	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(1)	20,476			1,360			3,102			142			25,080
	Three Months Ended September 30, 2015
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	73,557		$	—		$	2,096		$	—		$	75,653
Depletion, depreciation and accretion	52,617			194			1,796			408			55,015
Asset impairment	129,364			3,014			17,600			—			149,978
General and administrative expenses	2,095			936			532			4,300			7,863
Loss before income taxes	(130,154		)	(5,020		)	(18,540		)	(7,182		)	(160,896		)
Segment capital expenditures	17,811			3,873			1,779			12			23,475
	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(1)	56,997			3,730			7,982			958			69,667
	Nine Months Ended September 30, 2015
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	215,251		$	—		$	5,983		$	—		$	221,234
Depletion, depreciation and accretion	135,933			608			5,632			1,170			143,343
Asset impairment	129,364			40,980			46,933			—			217,277
General and administrative expenses	7,846			3,249			2,124			12,236			25,455
Loss before income taxes	(124,029		)	(48,723		)	(53,632		)	(17,072		)	(243,456		)
Segment capital expenditures	47,106			48,450			18,190			1,047			114,793

⁽¹⁾ On January 13, 2016 and August 23, 2016, respectively, the Company acquired all of the issued and outstanding common shares of Petroamerica and PetroLatina, which acquisitions were accounted for as business combinations (Note 3) and, therefore, property, plant and equipment acquired are not reflected in the table above. Additionally, on January 25, 2016, the Company acquired all of the issued and outstanding common shares of PetroGranada Colombia Limited ("PGC"), which acquisition was accounted for as an asset acquisition (Note 5) and property, plant and equipment acquired in this acquisition are not reflected in the table above.

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	As at September 30, 2016
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	1,018,328	$	97,726	$	83,888	$	3,989	$	1,203,931
Goodwill	102,581		—		—		—		102,581
All other assets	145,091		14,344		2,397		18,813		180,645
Total Assets	$	1,266,000	$	112,070	$	86,285	$	22,802	$	1,487,157
	As at December 31, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	574,351	$	95,069	$	115,552	$	4,021	$	788,993
Goodwill	102,581		—		—		—		102,581
All other assets	93,479		21,111		2,236		137,718		254,544
Total Assets	$	770,411	$	116,180	$	117,788	$	141,739	$	1,146,118

5. Property, Plant and Equipment and Inventory

Property, Plant and Equipment

(Thousands of U.S. Dollars)	As at September 30, 2016			As at December 31, 2015
Oil and natural gas properties
Proved	$	2,522,705		$	1,998,330
Unproved	766,902			310,771
	3,289,607			2,309,101
Other	28,805			28,342
	3,318,412			2,337,443
Accumulated depletion, depreciation and impairment	(2,114,481		)	(1,548,450		)
	$	1,203,931		$	788,993

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In the three and nine months ended September 30, 2016, the Company recorded ceiling test impairment losses in its Colombia cost center of $298.4 million and $431.1 million, respectively, and in its Brazil cost center of $21.6 million and $37.0 million, respectively. The Colombia ceiling test impairment loss related to lower oil prices and the fact that the acquisition of PetroLatina was added into the cost base at fair value (Note 3). However, these acquired assets were subjected to a prescribed U.S. GAAP ceiling test, which is not a fair value test, and which, as noted below, uses constant commodity pricing that averages prices during the preceding 12 months. The Brazil ceiling test impairment loss related to continued low oil prices and increased costs in the depletable base as a result of a $19.3 million impairment of unproved properties.

In the three and nine months ended September 30, 2015, the Company recorded ceiling test impairment losses of $129.4 million in its Colombia cost center, and $17.6 million and $46.9 million, respectively, in its Brazil cost center, related to lower oil prices.

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, less 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 estimates of future net revenues represent the fair market value of the Company's reserves. In accordance with GAAP, we used an average Brent price of $42.23 per bbl for the purposes of the September 30, 2016, ceiling test calculations (June 30, 2016 - $44.48; March 31, 2016 - $48.79; December 31, 2015 - $54.08).

In the nine months ended September 30, 2016, the Company recorded impairment losses in its Peru cost center of $0.9 million (three and nine months ended September 30, 2015 - $3.0 million and $41.0 million, respectively), related to costs incurred on Block 95. In the three months ended September 30, 2016, the Company ceased the impairment of costs incurred on Block 95 as a result of the effect of a revised field development plan for the Block.

Asset impairment for the three and nine months ended September 30, 2016, and 2015 was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2016		2015		2016		2015
Impairment of oil and gas properties	$	319,974	$	149,978	$	469,051	$	217,277
Impairment of inventory	—		—		664		—
	$	319,974	$	149,978	$	469,715	$	217,277

Acquisition of PGC

On January 25, 2016, the Company acquired all of the issued and outstanding common shares of PGC, pursuant to the terms and conditions of an acquisition agreement dated January 14, 2016. PGC is an oil and gas exploration, development and production company active in Colombia. Upon completion of the transaction, PGC became an indirect wholly-owned subsidiary of Gran Tierra. The net purchase price of PGC was $19.4 million, after giving consideration to net working capital of $18.3 million. The acquisition was accounted for as an asset acquisition with the excess consideration paid over the fair value of the net assets acquired 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:

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(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash	$	37,727
Allocation of Consideration Paid:
Oil and gas properties
Proved	$	12,228
Unproved	15,563
	27,791
Net working capital (including cash acquired of $0.2 million and restricted cash of $18.6 million)	18,339
Long-term deferred tax liability	(8,403		)
	$	37,727

Contingent consideration of $4.0 million will be payable if cumulative production from the Putumayo-7 Block plus gross proved plus probable reserves under the Putumayo-7 Block meet or exceed 8 MMbbl. Contingent consideration will be recognized when the contingency is resolved and the consideration is paid or becomes payable.

Inventory

At September 30, 2016, oil and supplies inventories were $9.6 million and $2.2 million, respectively (December 31, 2015 - $17.8 million and $1.3 million, respectively). At September 30, 2016, the Company had 269 Mbbl of oil inventory (December 31, 2015 - 616 Mbbl) NAR. In the nine months ended September 30, 2016, the Company recorded oil inventory impairment of $0.7 million (nine months ended September 30, 2015 - $nil) related to lower oil prices. In the three months ended September 30, 2016, and 2015, oil inventory impairment was $nil.

6. Debt and Debt Issuance Costs

The Company's debt at September 30, 2016, and December 31, 2015, was as follows:

(Thousands of U.S. Dollars)	As at September 30, 2016			As at December 31, 2015
Convertible senior notes (a)	$	115,000		$	—
Bridge loan facility (b)	130,000			—
Revolving credit facility (b)	65,000			—
Unamortized debt issuance costs	(9,691		)	—
	300,309			—
Short-term debt	(127,519		)	—
Long-term debt	$	172,790		$	—

a) Convertible Senior Notes

On April 6, 2016, the Company issued $100 million aggregate principal amount of Notes in a private placement to qualified institutional buyers. On April 22, 2016, the Company issued an additional $15 million aggregate principal amount of the Notes pursuant to the underwriters’ exercise of their option to acquire additional Notes. The Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2016. The Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted.

The Notes are convertible at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date. The conversion rate is initially 311.4295 shares of Common Stock per $1,000 principal amount of Notes (equivalent to an initial conversion price of approximately $3.21 per share of Common Stock). The conversion rate is subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase the conversion rate for a holder who elects to convert its Notes in connection with such a corporate event in certain circumstances.

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The Company may not redeem the Notes prior to April 5, 2019, except in certain circumstances following a fundamental change (as defined in the indenture governing the Notes). The Company may redeem for all cash or any portion of the Notes, at its option, on or after April 5, 2019, if (terms below are as defined in the indenture governing the Notes):

(i) the last reported sale price of the Company's Common Stock has been at least 150% of the conversion price then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period (including the last trading day of such period) ending on, and including, the trading day immediately preceding the date on which the Company provides notice of redemption; and

(ii) the Company has filed all reports that it is required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, as applicable (other than current reports on Form 8-K), during the twelve months preceding the date on which the Company provides such notice.

The redemption price will be equal to 100% of the principal amount of the Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. No sinking fund is provided for the Notes.

If the Company undergoes a fundamental change, holders may require the Company to repurchase for cash all or any portion of their Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.

Net proceeds from the sale of the Notes were $109.1 million, after deducting the initial purchasers' discount and the offering expenses payable by the Company.

b) Credit Facility - Revolving Credit Facility and Bridge Loan Facility

At September 30, 2016, the Company had a revolving credit facility with a syndicate of lenders.

Availability under the revolving credit facility is determined by a proven reserves-based borrowing base, and remains subject to the satisfaction of conditions precedent set forth in the credit agreement. On June 2, 2016, the Company entered into a Second Amendment (the "Second Amendment") to its credit agreement dated September 18, 2015 (the "Credit Agreement"). Pursuant to the Second Amendment, among other things, the committed borrowing base under the Company's revolving credit facility was reduced from $200 million to $185 million, with $160 million readily available and $25 million subject to the consent of all lenders. Further, the amount of permitted senior debt under the Company's revolving credit facility was decreased from $600 million to $500 million. The borrowing base will be re-determined semi-annually. The credit agreement includes a letter of credit sub-limit of up to $100 million.

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 2.00% and 3.00% per annum, or an alternate base rate plus a margin ranging from 1.00% per annum to 2.00% per annum, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. Undrawn amounts under the revolving credit facility bear interest at 0.75% per annum, based on the average daily amount of unused commitments. A letter of credit participation fee of 0.25% per annum will accrue on the average daily amount of letter of credit exposure.

On August 23, 2016, the Company entered into a Third Amendment (the "Third Amendment") to the Credit Agreement to add a bridge term loan facility (the “Bridge Loan Facility”), pursuant to which the lenders provided $130.0 million in secured bridge loan financing to fund a portion of the purchase price of the PetroLatina Acquisition. The Bridge Loan Facility has a term of 364 days, bears interest at USD LIBOR plus 6%, and has customary bridge facility repayment terms, providing for the prepayment of the Bridge Loan Facility upon the occurrence of certain events, including certain debt issuances. It is otherwise on substantially the same terms as the existing secured revolving credit facility.

On August 23, 2016, in connection with the PetroLatina Acquisition, the Company drew $95.0 million on its revolving credit facility and $130.0 million on its Bridge Loan Facility. The Company subsequently repaid $30.0 million of the outstanding balance on its revolving credit facility, resulting in an outstanding balance of $65.0 million, at September 30, 2016. Borrowings under the Bridge Loan Facility will mature on August 22, 2017, and borrowings under the revolving credit facility will mature on September 18, 2018.

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As part of the PetroLatina Acquisition, Gran Tierra assumed PetroLatina's reserve-backed credit facility with an outstanding balance as at the PetroLatina Acquisition Date of $80.0 million. This credit facility plus accrued interest was repaid by Gran Tierra upon closing of the PetroLatina Acquisition on August 23, 2016.

c) 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)	2016		2015		2016		2015
Contractual interest and other financing expenses	$	2,938	$	—	$	5,029	$	—
Amortization of debt issuance costs	2,184		—		2,813		—
	$	5,122	$	—	$	7,842	$	—

The Company incurred debt issuance costs in connection with the issuance of the Notes, the Bridge Loan Facility and its revolving credit facility. As at September 30, 2016, the balance of unamortized debt issuance costs has been presented as a direct deduction against the carrying amount of debt and is being amortized to interest expense using the effective interest method over the term of the debt.

7. Share Capital

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

	Shares of Common Stock	Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2015	273,442,799	4,933,177		3,638,889
Shares issued upon conversion of subscription receipts	57,835,134	—		—
Shares issued for acquisition (Note 3)	13,656,719	—		—
Options exercised	2,165,370	—		—
Exchange of exchangeable shares	191,687	(90,100	)	(101,587	)
Balance, September 30, 2016	347,291,709	4,843,077		3,537,302

Subscription Receipts

On July 8, 2016, the Company issued approximately 57.8 million subscription receipts (“Subscription Receipts”) in a private placement to eligible purchasers at a price of $3.00 per Subscription Receipt for gross proceeds of approximately $173.5 million, or net proceeds after share issuance costs of $165.8 million. The proceeds were used to partially fund the PetroLatina Acquisition. Each Subscription Receipt entitled the holder to automatically receive one common share of the Company upon closing of the PetroLatina Acquisition on the satisfaction of certain conditions. Upon the closing of the PetroLatina Acquisition on August 23, 2016, each Subscription Receipt was converted to one common share.

Loss per Share

Basic loss per share is calculated by dividing loss attributable to common shareholders by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted income (loss) per share is calculated by adjusting the weighted average number of shares of Common Stock and exchangeable shares outstanding for the dilutive effect, if any, of share equivalents. The Company uses 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

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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 price of shares of Common Stock during the period.

Stock options and shares issuable upon conversion of the Notes were excluded from the diluted loss per share calculation as the stock options and shares issuable upon conversion of the Notes were anti-dilutive.

Equity Compensation Awards

In December 2015, the Company's Board of Directors approved a new equity compensation program for 2016 to realign the Company's compensation programs with its renewed short and long-term strategy. The 2016 equity compensation program reflects the Company's emphasis on pay-for-performance. 

In prior years, all equity awards were subject to vesting conditions based solely on the recipient’s continued employment over a specified period of time. In contrast, 80% of the equity awards granted in early 2016 consisted of Performance Stock Units (“PSUs”) and 20% consisted of stock options. Gran Tierra's Compensation Committee and Board of Directors believed it was important to revise the Company's long-term incentive program to incorporate a new form of equity award that vests based on the achievement of certain key measures of performance. The purpose of this change was to align the Company's executives and employees to achieve the operational goals established by the Board of Directors, total shareholder return and increase the net asset value per share for stockholders. The Company’s equity compensation awards outstanding as at September 30, 2016, include PSUs, deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock options.

The Company records stock-based compensation expense, measured at the fair value of the awards that are ultimately expected to vest, in the consolidated financial statements. Fair values are determined using pricing models such as the Black-Scholes-Merton or Monte Carlo simulation stock option-pricing models and/or observable share prices. For equity-settled stock-based compensation awards, fair values are determined at the grant date and are recognized over the requisite service period. For cash-settled stock-based compensation awards, fair values are determined at each reporting date and periodic changes are recognized as compensation costs, with a corresponding change to liabilities. Stock-based compensation expense is capitalized as part of oil and natural gas properties or expensed as part of general and administrative ("G&A") or operating expenses, as appropriate.

The following table provides information about PSU, DSU, RSU and stock option activity for the nine months ended September 30, 2016:

	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, 2015	—	—	1,015,457		12,851,557		4.60
Granted	2,985,260	163,566	—		1,627,712		2.67
Exercised	—	—	(469,446	)	(2,165,370	)	2.47
Forfeited	—	—	(179,340	)	(1,655,729	)	(6.11	)
Expired	—	—	—		(1,517,500	)	(6.41	)
Balance, September 30, 2016	2,985,260	163,566	366,671		9,140,670		4.19

Stock-based compensation expense for the three months ended September 30, 2016, and 2015, was $0.9 million and $1.0 million, respectively, and for the nine months ended September 30, 2016 and 2015, $4.4 million and $2.1 million, respectively, and was primarily recorded in G&A expenses.

At September 30, 2016, there was $9.8 million (December 31, 2015 - $3.9 million) of unrecognized compensation cost related to unvested PSUs, stock options, DSUs and RSUs which is expected to be recognized over a weighted average period of 2.0 years.

PSUs

PSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company's Common Stock upon vesting of such units or a cash payment equal to the value of the underlying shares. PSUs will cliff vest

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after three years, subject to the continued employment of the grantee. The number of PSUs that vest may range from zero to 200% of the target number granted based on the Company’s performance with respect to the applicable performance targets. The performance targets for the PSUs outstanding as at September 30, 2016, are as follows:

(i) 50% of the award is subject to targets relating to the total shareholder return (“TSR”) of the Company against a group of peer companies;

(ii) 25% of the award is subject to targets relating to net asset value ("NAV") of the Company per share and NAV is based on before tax net present value discounted at 10% of proved plus probable reserves; and

(iii) 25% of the award is subject to targets relating to the execution of corporate strategy.

The compensation cost of PSUs is subject to adjustment based upon the attainability of these performance targets. No settlement will occur with respect to the portion of the PSU award subject to each performance target for results below the applicable minimum threshold for that target. PSUs in excess of the target number granted will vest and be settled if performance exceeds the targeted performance goals. The Company currently intends to settle PSUs in cash.

DSUs and RSUs

DSUs and RSUs entitle the holder to receive, either the underlying number of shares of the Company's Common Stock upon vesting of such units or, at the option of the Company, a cash payment equal to the value of the underlying shares. The Company's historic practice has been to settle RSUs in cash and the Company currently intends to settle the RSUs and DSUs outstanding as at September 30, 2016 in cash. Once a DSU or RSU is vested, it is immediately settled. During the nine months ended September 30, 2016, DSUs were granted to directors and will vest 100% at such time the grantee ceases to be a member of the Board of Directors.

Stock Options

Each stock option permits the holder to purchase one share of Common Stock at the stated exercise price. The exercise price equals the market price of a share of Common Stock at the time of grant. Stock options generally vest over three years. The term of stock options granted starting in May of 2013 is five years or three months after the grantee’s end of service to the Company, whichever occurs first. Stock options granted prior to May of 2013 continue to have a term of ten years or three months after the end of the grantee’s service to the Company, whichever occurs first.

For the nine months ended September 30, 2016, 2,165,370 shares of Common Stock were issued for cash proceeds of $5.2 million (nine months ended September 30, 2015 - $0.6 million) upon the exercise of stock options.

The weighted average grant date fair value for stock options granted in three months ended September 30, 2016, was $1.18 (three months ended September 30, 2015 - $0.95) and for the nine months ended September 30, 2016, was $1.13 (nine months ended September 30, 2015 - $1.26).

8. Asset Retirement Obligation

Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:

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	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 30, 2016			December 31, 2015
Balance, beginning of period	$	33,224		$	35,812
Settlements	(681		)	(6,317		)
Liability incurred	1,413			1,556
Liabilities assumed in acquisitions (Note 3)	15,722			—
Accretion	2,042			1,313
Revisions in estimated liability	(3,019		)	860
Balance, end of period	$	48,701		$	33,224
Asset retirement obligation - current	$	3,673		$	2,146
Asset retirement obligation - long-term	45,028			31,078
	$	48,701		$	33,224

For the nine months ended September 30, 2016, settlements included cash payments of $0.5 million with the balance in accounts payable and accrued liabilities at September 30, 2016. Revisions to 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 and the expected timing of settling the asset retirement obligation. At September 30, 2016, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $12.8 million (December 31, 2015 - $2.9 million). These assets are accounted for as restricted cash on the Company's interim unaudited condensed consolidated balance sheets.

9. Taxes

The Company's effective tax rate was 31% in the nine months ended September 30, 2016, compared with 24% in the corresponding period in 2015. The Company's effective tax rate differed from the U.S. statutory rate of 35% primarily due to an increase in the valuation allowance, which was largely attributable to impairment losses in Brazil and Colombia, as well as non-deductible local taxes, a third party royalty in Colombia, stock based compensation and a third party royalty in Colombia. These items were partially offset by the impact of foreign taxes, foreign currency translation adjustments and other permanent differences. Other permanent differences mainly related to non-taxable gain arising on the acquisition of Petroamerica, partially offset by prior periods' true-up adjustments, uncertain tax position adjustments and other expenses deductible for tax purposes. The deferred tax recovery for nine months ended September 30, 2016, included $172.5 million associated with the ceiling test impairment loss in Colombia.

On December 23, 2014, the Colombian Congress passed a law which imposes an equity tax levied on Colombian operations for 2015, 2016 and 2017. The equity tax is calculated based on a legislated measure, which is based on the Company’s Colombian legal entities' balance sheet equity for tax purposes at January 1, 2015. This measure is subject to adjustment for inflation in future years. The equity tax rates for January 1, 2015, 2016 and 2017, are 1.15%, 1% and 0.4%, respectively. The legal obligation for each year's equity tax liability arises on January 1 of each year; therefore, the Company recognized the annual amounts of $3.1 million and $3.8 million, respectively, for the equity tax expense in the consolidated statement of operations during the three months ended March 31, 2016, and 2015, and a corresponding payable on the consolidated balance sheet at March 31, 2016, and 2015. These amounts were paid in May and September of each year and at September 30, 2016, accounts payable included $nil (December 31, 2015 - $nil).

10. Contingencies

On June 6, 2016, the Company received a positive decision from the Chamber of Commerce of Bogotá Center for Arbitration and Conciliation tribunal (the "Tribunal") relating to its dispute with the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) of Colombia ("ANH") with respect to whether all production from the Moqueta Exploitation Area of the Chaza Block exploration and production contract ("Chaza Contract") was subject to an additional royalty (the "HPR Royalty"). In its decision, the Tribunal found that the HPR Royalty under the Chaza Contract was only payable when the accumulated oil production from the Moqueta Exploitation Area exceeded 5.0 MMbbl. That production threshold was reached on April 30, 2015, and since that time the Company has been paying the HPR Royalty on production from the Moqueta Exploitation Area.

The ANH and Gran Tierra are engaged in ongoing discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Based on the Company's understanding of the

21

ANH's position, the estimated compensation which would be payable if the ANH’s interpretation is correct could be up to $45.4 million as at September 30, 2016. 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.

The Company provided the purchaser of its Argentina business unit with certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations. The Company does not believe that these obligations are probable of having a material impact on its consolidated financial position, results of operations or cash flows.

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

Letters of credit

At September 30, 2016, the Company had provided promissory notes totaling $111.0 million (December 31, 2015 - $76.5 million) as security for letters of credit relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.

11. Financial Instruments and Fair Value Measurement

Financial Instruments

At September 30, 2016, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, trading securities, derivatives assets, accounts payable and accrued liabilities, short-term and 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 trading securities, derivative assets and RSU and PSU liabilities are being remeasured at the estimated fair value at the end of each reporting period.

The fair value of trading securities which were received as consideration on the sale of the Company's Argentina business unit is estimated based on quoted market prices in an active market.

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

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

The fair value of trading securities, derivative assets, and RSU and PSU liabilities at September 30, 2016, and December 31, 2015, were as follows:

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(Thousands of U.S. Dollars)	As at September 30, 2016		As at December 31, 2015
Trading securities	$	2,536	$	6,250
Commodity price derivative asset	3,707		—
Foreign currency derivative asset	1,519		—
	$	7,762	$	6,250
RSU and PSU liability	$	2,485	$	1,189

During the three months ended September 30, 2016, the Company sold trading securities for cash proceeds of $0.8 million (three months ended September 30, 2015 - $nil).

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2016			2015		2016			2015
Trading securities loss	$	701		$	2,670	$	2,926		$	570
Commodity price derivative loss	2,190			—		856			—
Foreign currency derivatives (gain) loss	(840		)	—		(1,958		)	692
Financial instruments loss	$	2,051		$	2,670	$	1,824		$	1,262

These gains and losses are presented as financial instruments gains or losses in the interim unaudited condensed consolidated statements of operations and cash flows. Of the trading securities loss, $0.7 million for the three months ended September 30, 2016, and $2.9 million for the nine months ended September 30, 2016, relates to securities still held at September 30, 2016.

Financial instruments not recorded at fair value include the Notes (Note 6). At September 30, 2016, the carrying amount of the Notes was $109.6 million, which represents the aggregate principal amount less unamortized debt issuance costs, and the fair value was $134.0 million. The fair value of long-term restricted cash, the revolving credit facility and the Bridge Loan Facility approximates 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, 2016, and December 31, 2015, the fair value of the trading securities acquired in connection with the disposal of the Argentina business unit and the RSU liability was determined using Level 1 inputs. At September 30, 2016, the fair value of the derivative assets was determined using Level 2 inputs. 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 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, revolving credit facility and term loan to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure in the paragraph above regarding the fair value of the Company’s revolving credit facility and term loan was determined using an income approach using Level 3 inputs. The disclosure in the paragraph 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 restricted cash was based on Level 1 inputs.

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

Commodity Price Derivatives

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

At September 30, 2016, the Company had outstanding commodity price derivative positions as follows:

Period and type of instrument	Volume, bopd	Reference	Sold Put		Purchased Put		Sold Call
Collar: June 1, 2016 to May 31, 2017	10,000	ICE Brent	$	35	$	45	$	65

The Company paid a premium of $4.6 million, or $1.25 per bbl, upon entering into the commodity price derivative. Collars are a combination of put options (floor) and sold call options (ceiling). For a collar position, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor strike price while the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling strike price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor strike price and equal to or less than the ceiling strike price.

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 costs.

At September 30, 2016, the Company had outstanding foreign currency derivative positions as follows:

Period and type of instrument	Amount hedged (COP)	Reference	Purchased Call (COP)	Sold Put (COP)	Sold Put (COP)
Collar: June 1, 2016 to June 30, 2016	9,794.6	COP	3,000	3,265	3,310
Collar: July 1, 2016 to September 30, 2016	25,064.6	COP	3,000	3,275	3,320
Collar: October 1, 2016 to December 31, 2016	20,930.0	COP	3,000	3,285	3,330
Collar: January 1, 2017 to March 31, 2017	31,597.6	COP	3,100	3,300	3,345
Collar: April 1, 2017 to May 31, 2017	22,697.2	COP	3,100	3,310	3,370
	110,084.0

The Company's cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company's derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

While the use of these derivative instruments may limit or partially reduce the downside risk of adverse commodity price and foreign exchange movements, their use also may limit future income and gains from favorable commodity price and foreign exchange movements.

12. Supplemental Cash Flow Information

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

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	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2016			2015
Accounts receivable and other long-term assets	$	15,233		$	52,133
Derivatives	(4,563		)	—
Inventory	3,630			1,599
Prepaids	1,864			2,538
Accounts payable and accrued and other long-term liabilities	(11,297		)	(36,155		)
Taxes receivable and payable	13,230			(47,483		)
Net changes in assets and liabilities from operating activities	$	18,097		$	(27,368	)

The following table provides additional supplemental cash flow disclosures:

	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2016		2015
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	27,520	$	34,023

13. Subsequent Events

The Company held its 2016 Annual Meeting of Stockholders on June 23, 2016, at which the Company’s stockholders approved the reincorporation of the Company from the State of Nevada to the State of Delaware. The reincorporation was effective on October 31, 2016, and the Company is now a Delaware corporation.

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

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Please see the cautionary language at the very beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements, as well as Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q and Part I, Item 1A “Risk Factors” in our 2015 Annual Report on Form 10-K.

The following discussion of our financial condition and results of operations should be read in conjunction with the "Financial Statements" as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q as well as the "Financial Statements and Supplementary Data" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in Part II, Items 8 and 7, respectively, of our Annual Report on Form 10-K, filed with the SEC on February 29, 2016.

Highlights

Acquisitions of Petroamerica, PetroLatina and PGC

On January 13, 2016, we acquired all of the issued and outstanding common shares of Petroamerica, a Calgary based oil and gas exploration, development and production company active in Colombia. As consideration we issued approximately 13.7 millionshares of Common Stock, and paid cash consideration of approximately $70.6 million. The fair value of Common Stock issued was determined to be $25.8 million based on the closing price of shares of our Common Stock on the acquisition date. Total net purchase price of Petroamerica was $72.2 million, after giving consideration to net working capital of $24.2 million.

On August 23, 2016, we acquired all of the issued and outstanding common shares of PetroLatina for $525.0 million, consisting of cash consideration of $442.6 million, a deferred cash payment of $25.0 million to be paid prior to December 31, 2016, assumption of a reserve-backed credit facility with an outstanding balance of $80.0 million, net of working capital of $15.5 million, and other closing adjustments. Upon completion of the transaction on the PetroLatina Acquisition Date, Gran Tierra repaid and canceled the reserve-based credit facility and PetroLatina became an indirect wholly-owned subsidiary of Gran Tierra. PetroLatina is an exploration and production company with assets primarily in the Middle Magdalena Basin of Colombia. The PetroLatina Acquisition was funded through a combination of our current cash balance, gross proceeds of

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$173.5 million from the Subscription Receipts as noted below, available borrowings under our existing revolving credit facility and $130.0 million of borrowings under a Bridge Loan Facility.

These acquisitions were accounted for as a business combinations using the acquisition method, with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the acquisition date, and the results of Petroamerica and PetroLatina were included with our results from that date. For the Petroamerica acquisition, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration paid. As a result, we recognized a “Gain on acquisition” of $11.7 million in the interim unaudited condensed consolidated statement of operations for the nine months ended September 30, 2016.

Additionally, on January 25, 2016, we acquired all of the issued and outstanding common shares of PGC for cash consideration. The net purchase price of PGC was $19.4 million, after giving consideration to net working capital of $18.3 million. PGC's working capital on the acquisition date included restricted cash of $18.6 million and cash of $0.2 million. Of the opening balance of restricted cash, $15.6 million was released prior to September 30, 2016, and we expect that the remaining balance will be released this year. This acquisition was accounted for as an asset acquisition.

The following table summarizes the acquisitions we completed during the nine months ended September 30, 2016:

	PetroLatina		PetroAmerica		PGC
Net purchase price (net of working capital acquired) ($000s)	$	525,000	$	72,234	$	19,388

Subscription Receipts

On July 8, 2016, we issued approximately 57.8 million Subscription Receipts in a private placement to eligible purchasers at a price of $3.00 per Subscription Receipt for gross proceeds of approximately $173.5 million or net proceeds after share issuance costs of $165.8 million. The net proceeds were used to partially fund the PetroLatina Acquisition. Each Subscription Receipt entitled the holder to automatically receive one common share of the Company upon closing of the PetroLatina Acquisition upon the satisfaction of certain conditions. Upon the closing of the PetroLatina Acquisition on August 23, 2016, each Subscription Receipt was converted to one common share.

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	Three Months Ended June 30			Three Months Ended September 30,								Nine Months Ended September 30,
	2016			2016			2015			% Change		2016			2015			% Change
Volumes (BOE)
Working Interest Production Before Royalties	2,342,681			2,376,813			2,149,907			11		7,050,034			6,412,737			10
Royalties	(368,384		)	(354,699		)	(348,270		)	2		(979,887		)	(1,115,555		)	(12	)
Production NAR	1,974,297			2,022,114			1,801,637			12		6,070,147			5,297,182			15
Decrease (Increase) in Inventory	65,753			(45,543		)	187,908			(124	)	260,633			(199,514		)	(231	)
Sales(1)	2,040,050			1,976,571			1,989,545			(1	)	6,330,780			5,097,668			24
Average Daily Volumes (BOEPD)
Working Interest Production Before Royalties	25,744			25,835			23,368			11		25,730			23,490			10
Royalties	(4,049		)	(3,855		)	(3,785		)	2		(3,576		)	(4,086		)	(12	)
Production NAR	21,695			21,980			19,583			12		22,154			19,404			14
Decrease (Increase) in Inventory	723			(495		)	2,043			(124	)	951			(731		)	(230	)
Sales(1)	22,418			21,485			21,626			(1	)	23,105			18,673			24
Operating Netback ($000s)
Oil and Natural Gas Sales	$	71,713		$	68,539		$	75,653		(9	)	$	197,655		$	221,234		(11	)
Operating Expenses	(17,748		)	(25,638		)	(20,894		)	23		(62,453		)	(61,313		)	2
Transportation Expenses	(6,217		)	(5,773		)	(12,857		)	(55	)	(24,318		)	(28,005		)	(13	)
Operating Netback(2)	$	47,748		$	37,128		$	41,902		(11	)	$	110,884		$	131,916		(16	)
G&A Expenses ($000s)	$	7,975		$	5,592		$	7,863		(29	)	$	20,614		$	25,455		(19	)
Net Loss ($000s)	$	(63,559	)	$	(229,619	)	(101,877		)	125		$	(338,210	)	$	(185,307	)	83
EBITDA ($000s)(3)	$	40,532		$	24,634		$	44,097		(44	)	$	89,350		$	117,164		(24	)
Adjusted EBITDA ($000s)(3)	$	41,313		$	24,127		$	31,174		(23	)	$	78,697		$	95,672		(18	)
Net Cash Provided by Operating Activities ($000s)	$	27,409		$	48,222		$	53,011		(9	)	$	86,399		$	58,579		47
Funds Flow From Operations ($000s)(4)	$	33,752		$	23,527		$	36,679		(36	)	$	68,798		$	90,715		(24	)
Capital Expenditures ($000s)	$	18,407		$	25,080		$	23,475		7		$	69,667		$	114,793		(39	)

	As at
	September 30, 2016		December 31, 2015		% Change
Cash, Cash Equivalents and Current Restricted Cash ($000s)	$	61,271	$	145,434	(58	)
Short-term Debt, net of Debt Issuance Costs ($000s)	$	127,519	$	—	—
Working Capital (Excluding Short-term Debt) ($000s)	$	29,392	$	160,449	(82	)

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

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Non-GAAP measures

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

⁽²⁾ Operating netback as presented is oil and gas sales net of royalties and operating and transportation expenses. Management believes that 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.

⁽³⁾ EBITDA, as presented, is net loss adjusted for depletion, depreciation and accretion (“DD&A”) expenses, asset impairment, interest expense and income tax recovery or expense. Adjusted EBITDA is EBITDA adjusted for gain on acquisition and foreign exchange losses or gains. Management uses these financial measures to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that these financial measures are also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to EBITDA and adjusted EBITDA is as follows:

	Three Months Ended June 30			Three Months Ended September 30,						Nine Months Ended September 30,
EBITDA - Non-GAAP Measure ($000s)	2016			2016			2015			2016			2015
Net loss	$	(63,559	)	$	(229,619	)	$	(101,877	)	$	(338,210	)	$	(185,307	)
Adjustments to reconcile net loss to EBITDA
DD&A expenses	31,884			35,729			55,015			104,525			143,343
Asset impairment	92,843			319,974			149,978			469,715			217,277
Interest expense	2,201			5,122			—			7,842			—
Income tax recovery	(22,837		)	(106,572		)	(59,019		)	(154,522		)	(58,149		)
EBITDA	40,532			$	24,634		$	44,097		89,350			117,164
Gain on acquisition	—			—			—			(11,712		)	—
Foreign exchange loss (gain)	781			(507		)	(12,923		)	1,059			(21,492		)
Adjusted EBITDA	$	41,313		$	24,127		$	31,174		$	78,697		$	95,672

⁽⁴⁾ Funds flow from operations, as presented, is net cash provided by operating activities adjusted for net change in assets and liabilities from operating activities and cash settlement of asset retirement obligation. Management uses this financial measure to analyze liquidity and cash flows generated by our principal business activities prior to the consideration of how changes in assets and liabilities from operating activities and cash settlement of asset retirement obligation affect those cash flows, and believes that this financial measure is also useful supplemental information for investors to analyze our liquidity and financial results. A reconciliation from net cash provided by operating activities to funds flow from operations is as follows:

	Three Months Ended June 30		Three Months Ended September 30,						Nine Months Ended September 30,
Funds Flow From Operations - Non-GAAP Measure ($000s)	2016		2016			2015			2016			2015
Net cash provided by operating activities	$	27,409	$	48,222		$	53,011		86,399			$	58,579
Adjustments to reconcile net cash provided by operating activities to funds flow from operations
Net change in assets and liabilities from operating activities	5,983		(24,727		)	(19,136		)	(18,097		)	27,368
Cash settlement of asset retirement obligation	360		32			2,804			496			4,768
Funds flow from operations	$	33,752	$	23,527		$	36,679		$	68,798		$	90,715

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Consolidated Results of Operations

	Three Months Ended June 30			Three Months Ended September 30,								Nine Months Ended September 30,
	2016			2016			2015			% Change		2016			2015			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	71,713		$	68,539		$	75,653		(9	)	$	197,655		$	221,234		(11	)
Operating expenses	17,748			25,638			20,894			23		62,453			61,313			2
Transportation expenses	6,217			5,773			12,857			(55	)	24,318			28,005			(13	)
Operating netback(1)	47,748			37,128			41,902			(11	)	110,884			131,916			(16	)
DD&A expenses	31,884			35,729			55,015			(35	)	104,525			143,343			(27	)
Asset impairment	92,843			319,974			149,978			113		469,715			217,277			116
G&A expenses	7,975			5,592			7,863			(29	)	20,614			25,455			(19	)
Transaction expenses	—			6,088			—			—		7,325			—			—
Severance expenses	281			—			461			(100	)	1,299			6,827			(81	)
Equity tax	—			—			—			—		3,053			3,769			(19	)
Foreign exchange loss (gain)	781			(507		)	(12,923		)	(96	)	1,059			(21,492		)	105
Financial instruments (gain) loss	(1,072		)	2,051			2,670			(23	)	1,824			1,262			(45	)
Interest expense	2,201			5,122			—			—		7,842			—			—
	134,893			374,049			203,064			84		617,256			376,441			64
Gain on acquisition	—			—			—			—		11,712			—			—
Interest income	749			730			266			174		1,928			1,069			80
Loss before income taxes	(86,396		)	(336,191		)	(160,896		)	109		(492,732		)	(243,456		)	102
Current income tax expense	(5,778		)	(3,879		)	(3,523		)	10		(11,680		)	(11,632		)	—
Deferred income tax recovery	28,615			110,451			62,542			77		166,202			69,781			138
	22,837			106,572			59,019			81		154,522			58,149			166
Net loss	$	(63,559	)	$	(229,619	)	$	(101,877	)	125		$	(338,210	)	$	(185,307	)	83
Sales Volumes(2)
Oil and NGL's, bbl	2,020,722			1,960,607			1,974,945			(1	)	6,273,444			5,058,970			24
Natural gas, Mcf	115,968			95,784			87,600			9		344,017			232,187			48
Total sales volumes, BOE	2,040,050			1,976,571			1,989,545			(1	)	6,330,780			5,097,668			24
Total sales volumes, BOEPD	22,418			21,485			21,626			(1	)	23,105			18,673			24
Average Prices
Oil and NGL's per bbl	$	35.31		$	34.79		$	38.14		(9	)	$	31.34		$	43.56		(28	)
Natural gas per Mcf	$	3.06		$	3.40		$	3.77		(10	)	$	3.07		$	3.80		(19	)

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Brent Price per bbl	$	45.52		$	46.98		$	50.23		(6	)	$	42.07		$	55.28		(24	)
Consolidated Results of Operations per BOE sales volumes
Oil and natural gas sales	$	35.15		$	34.68		$	38.03		(9	)	$	31.22		$	43.40		(28	)
Operating expenses	8.70			12.97			10.50			24		9.86			12.03			(18	)
Transportation expenses	3.05			2.92			6.46			(55	)	3.84			5.49			(30	)
Operating netback(1)	23.40			18.79			21.07			(11	)	17.52			25.88			(32	)
DD&A expenses	15.63			18.08			27.66			(35	)	16.51			28.12			(41	)
Asset impairment	45.51			161.88			75.38			115		74.20			42.62			74
G&A expenses	3.91			2.83			3.95			(28	)	3.26			4.99			(35	)
Transaction expenses	—			3.08			—			—		1.16			—			—
Severance expenses	0.14			—			0.23			(100	)	0.21			1.34			(84	)
Equity tax	—			—			—			—		0.48			0.74			(35	)
Foreign exchange loss (gain)	0.38			(0.26		)	(6.50		)	96		0.17			(4.22		)	104
Financial instruments (gain) loss	(0.53		)	1.04			1.34			(22	)	0.29			0.25			(16	)
Interest expense	1.08			2.59			—			—		1.24			—			—
	66.12			189.24			102.06			85		97.52			73.84			32
Gain on acquisition	—			—			—			—		1.85			—			—
Interest income	0.37			0.37			0.13			185		0.30			0.21			43
Loss before income taxes	(42.35		)	(170.08		)	(80.86		)	110		(77.85		)	(47.75		)	63
Current income tax expense	(2.83		)	(1.96		)	(1.77		)	11		(1.84		)	(2.28		)	(19	)
Deferred income tax recovery	14.03			55.88			31.44			78		26.25			13.69			92
	11.20			53.92			29.67			82		24.41			11.41			114
Net loss	$	(31.15	)	$	(116.16	)	$	(51.19	)	127		$	(53.44	)	$	(36.34	)	47

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

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

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Oil and gas production and sales volumes, BOEPD

	Three Months Ended September 30, 2016						Three Months Ended September 30, 2015
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	24,874		961		25,835		22,608		760		23,368
Royalties	(3,717	)	(138	)	(3,855	)	(3,686	)	(99	)	(3,785	)
Production NAR	21,157		823		21,980		18,922		661		19,583
Decrease (Increase) in Inventory	(497	)	2		(495	)	2,055		(12	)	2,043
Sales	20,660		825		21,485		20,977		649		21,626
Royalties, % of Working Interest Production Before Royalties	15	%	14	%	15	%	16	%	13	%	16	%
	Nine Months Ended September 30, 2016						Nine Months Ended September 30, 2015
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	24,859		871		25,730		22,833		657		23,490
Royalties	(3,439	)	(137	)	(3,576	)	(3,998	)	(88	)	(4,086	)
Production NAR	21,420		734		22,154		18,835		569		19,404
Decrease (Increase) in Inventory	949		2		951		(730	)	(1	)	(731	)
Sales	22,369		736		23,105		18,105		568		18,673
Royalties, % of Working Interest Production Before Royalties	14	%	16	%	14	%	18	%	13	%	17	%

Oil and gas production NAR for the three and nine months ended September 30, 2016, increased by 12% to 21,980 BOEPD and increased by 14% to 22,154 BOEPD, respectively, compared with 19,583 and 19,404 BOEPD, respectively, in the corresponding periods in 2015. In the three and nine months ended September 30, 2016, production increased primarily due to the drilling program in the Costayaco and Moqueta Fields in Colombia and the acquisitions of Petroamerica and PetroLatina. Royalties as a percentage of production decreased from the prior year commensurate with the decrease in oil prices.

Oil and gas production NAR for the three months ended September 30, 2016, was consistent with the prior quarter.

Oil and gas sales volumes for the three months ended September 30, 2016, were 21,485 BOEPD which was consistent with 21,626 BOEPD in the corresponding period in 2015. Higher working interest production (2,467 BOEPD) was offset by increased inventory (2,538 bopd) and higher royalty volumes (70 BOEPD). During the three months ended September 30, 2016, oil inventory increases accounted for 495 bopd of reduced sales volumes compared with oil inventory decreases, which accounted for 2,043 bopd of increased sales volumes in the corresponding period in 2015.

For the nine months ended September 30, 2016, oil and gas sales volumes increased by 24% to 23,105 BOEPD compared with 18,673 BOEPD in the corresponding period in 2015. Sales volumes increased due to higher working interest production (2,240 BOEPD), lower royalty volumes (510 BOEPD) and decreased inventory (1,682 BOEPD). During the nine months ended September 30, 2016, oil inventory decreases accounted for 951 bopd of increased sales volumes compared with oil inventory increases, which accounted for 731 bopd of reduced sales volumes in the corresponding period in 2015.

Oil and gas sales for the three months ended September 30, 2016, decreased by 4% to 21,485 BOEPD compared with 22,418 BOEPD in the prior quarter. Sales volumes decreased due to the effect of inventory changes (1,218 BOEPD), partially offset by higher working interest production (91 BOEPD) and lower royalty volumes (194 BOEPD).

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Operating netbacks

	Three Months Ended September 30, 2016									Three Months Ended September 30, 2015
(Thousands of U.S. Dollars)	Colombia			Brazil			Total			Colombia			Brazil			Total
Oil and Gas Sales	$	65,944		$	2,595		$	68,539		$	73,557		$	2,096		$	75,653
Transportation Expenses	(5,644		)	(129		)	(5,773		)	(12,833		)	(24		)	(12,857		)
	60,300			2,466			62,766			60,724			2,072			62,796
Operating Expenses	(24,899		)	(739		)	(25,638		)	(19,764		)	(1,130		)	(20,894		)
Operating Netback(1)	$	35,401		$	1,727		$	37,128		$	40,960		$	942		$	41,902
U.S. Dollars Per BOE
Brent							$	46.98								$	50.23
WTI							$	44.26								$	46.44
Oil and Gas Sales	$	34.69		$	34.21		$	34.68		$	38.12		$	35.12		$	38.03
Transportation Expenses	(2.97		)	(1.70		)	(2.92		)	(6.65		)	(0.40		)	(6.46		)
	31.72			32.51			31.76			31.47			34.72			31.57
Operating Expenses	(13.10		)	(9.74		)	(12.97		)	(10.24		)	(18.94		)	(10.50		)
Operating Netback(1)	$	18.62		$	22.77		$	18.79		$	21.23		$	15.78		$	21.07
	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015
(Thousands of U.S. Dollars)	Colombia			Brazil			Total			Colombia			Brazil			Total
Oil and Natural Gas Sales	$	191,515		$	6,140		$	197,655		$	215,251		$	5,983		$	221,234
Transportation Expenses	(24,005		)	(313		)	(24,318		)	(27,863		)	(142		)	(28,005		)
	167,510			5,827			173,337			187,388			5,841			193,229
Operating Expenses	(61,057		)	(1,396		)	(62,453		)	(55,977		)	(5,336		)	(61,313		)
Operating Netback(1)	$	106,453		$	4,431		$	110,884		$	131,411		$	505		$	131,916
U.S. Dollars Per BOE
Brent							$	42.07								$	55.28
WTI							$	41.10								$	50.98
Oil and Natural Gas Sales	$	31.25		$	30.46		$	31.22		$	43.55		$	38.60		$	43.40
Transportation Expenses	(3.92		)	(1.55		)	(3.84		)	(5.64		)	(0.92		)	(5.49		)
	27.33			28.91			27.38			37.91			37.68			37.91
Operating Expenses	(9.96		)	(6.92		)	(9.86		)	(11.32		)	(34.42		)	(12.03		)
Operating Netback(1)	$	17.37		$	21.99		$	17.52		$	26.59		$	3.26		$	25.88

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

Oil and gas sales for the three months ended September 30, 2016, decreased by 9% to $68.5 million from $75.7 million in the comparable period in 2015, primarily as a result of the effect of decreased realized oil prices. Oil and gas sales for the nine months ended September 30, 2016, decreased by 11% to $197.7 million from $221.2 million in the comparable period in 2015 primarily due to the effect of decreased realized oil prices, partially offset by higher sales volumes.

The following table shows the effect of changes in realized price and sales volumes on our oil and gas sales for the three and nine months ended September 30, 2016:

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	Three months ended September 30,			Nine months ended September 30,
Oil and natural gas sales for period ended September 30, 2015	$	75,653		$	221,234
Realized sales price decrease effect	(6,621		)	(77,096		)
Sales volume (decrease) increase effect	(493		)	53,517
Oil and natural gas sales for period ended September 30, 2016	$	68,539		$	197,655

Average realized prices for the three and nine months ended September 30, 2016, decreased by 9% and 28%, respectively, commensurate with the decrease in benchmark oil prices. Average Brent oil prices for the three and nine months ended September 30, 2016, decreased by 6% and 24%.

Oil and gas sales for the three months ended September 30, 2016, decreased by 4% to $68.5 million from $71.7 million compared with the prior quarter primarily due to lower sales volumes. Average realized prices of $34.68 per BOE for the three months ended September 30, 2016, were consistent with $35.15 per BOE in the prior quarter. Average Brent oil prices for the three months ended September 30, 2016, increased by 3% to $46.98 per bbl, compared with $45.52 per bbl in the prior quarter.

During periods of CENIT S.A-operated Trans-Andean oil pipeline (the "OTA pipeline”) disruptions, we have multiple transportation alternatives. Each transportation route has varying effects on realized prices and transportation costs. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended June 30		Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2016		2015		2016		2015
Volume sold using pipeline	50	%	36	%	16	%	50	%	55	%
Volume sold at wellhead	50	%	56	%	62	%	40	%	33	%
Volume sold not at wellhead, using trucking	—	%	8	%	22	%	10	%	12	%
	100	%	100	%	100	%	100	%	100	%

Transportation expenses for the three months ended September 30, 2016decreased by 55% to $5.8 million compared with the corresponding period in 2015. The decrease was primarily due to lower transportation expenses per BOE. On a per BOE basis, transportation expenses decreased by 55% to $2.92 per BOE from $6.46 per BOE in the corresponding period in 2015. In the three months ended September 30, 2016, we had a higher percentage of sales using pipeline, as noted above, and used alternative transportation routes during periods of OTA pipeline disruptions which had lower costs per BOE than the routes used in 2015.

Transportation expenses for the nine months ended September 30, 2016, decreased by 13% to $24.3 million compared with the corresponding period in 2015. The decrease in the nine months ended September 30, 2016 was due to decreased transportation expenses per BOE, partially offset by higher sales volumes. On a per BOE basis, transportation expenses decreased by 30% to $3.84 per BOE from $5.49 per BOE in the corresponding period in 2015. As noted above, in 2016, we used alternative transportation routes which had lower costs per BOE than the routes used in 2015.

Transportation expenses for the three months ended September 30, 2016, decreased 7% to $5.8 million compared with $6.2 million in the prior quarter as a result of decreased transportation costs per BOE combined with lower sales volumes. On a per BOE basis, transportation expenses decreased by 4% to $2.92 per BOE from $3.05 per BOE in the prior quarter. The decrease was primarily due to a higher percentage of sales at the wellhead.

Operating expenses for the three months ended September 30, 2016, increased by 23% to $25.6 million compared with the corresponding period in 2015. The increase was primarily due to increased operating costs per BOE. On a per BOE basis, operating expenses increased by 24% to $12.97 per BOE from $10.50 per BOE, in the corresponding period in 2015 primarily as a result of increased workover expenses of $3.58 per BOE. In 2016, we deferred workover activity to the second half of the year due to low commodity prices. Excluding workover expenses, operating costs decreased by $1.11 per BOE.

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In Colombia, operating costs for the three months ended September 30, 2016, increased by $2.86 per BOE compared with the corresponding period in 2015, primarily as a result of increased workover costs of $3.73 per BOE. Excluding workover expenses, operating costs in Colombia decreased by $0.87 per BOE.

Operating expenses for the nine months ended September 30, 2016, increased by 2% to $62.5 million, compared with the corresponding period in 2015. The increase was primarily due to higher sales volumes, partially offset by decreased operating costs per BOE. On a per BOE basis, operating expenses decreased by 18% to $9.86 per BOE from $12.03 per BOE, in the corresponding period in 2015. Workover expenses increased by $0.24 compared with the corresponding period in the prior year. Excluding workover expenses, operating costs decreased by $2.41 per BOE.

Colombian operating expense for the nine months ended September 30, 2016, decreased by $1.36 per BOE compared with the corresponding period in 2015, primarily as a result of cost saving measures.

In Brazil, operating costs per BOE decreased as a result of higher sales volumes and a reduction in headcount, partially offset by the effect of the weakening U.S. dollar against the local currency in Brazil, which resulted in higher expenses for costs denominated in local currency.

Operating expenses increased by 44% to $25.6 million in the three months ended September 30, 2016, compared with $17.7 million in the prior quarter primarily due to increased operating costs per BOE, partially offset by lower sales volumes. On a per BOE basis, operating expenses increased by 49% to $12.97 per BOE for the three months ended September 30, 2016, from $8.70 per BOE in the prior quarter primarily as a result of increased workover expenses of $3.52 per BOE. Excluding workover expenses, operating costs decreased by $0.75 per BOE from the prior quarter.

DD&A expenses

	Three Months Ended September 30, 2016				Three Months Ended September 30, 2015
	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	$	34,156	$	17.97	$	52,617	$	27.26
Brazil	1,022		13.47		1,796		30.09
Peru	206		—		194		—
Corporate	345		—		408		—
	$	35,729	$	18.08	$	55,015	$	27.66
	Nine Months Ended September 30, 2016				Nine Months Ended September 30, 2015
	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	$	100,350	$	16.37	$	135,933	$	27.50
Brazil	2,764		13.71		5,632		36.33
Peru	418		—		608		—
Corporate	993		—		1,170		—
	$	104,525	$	16.51	$	143,343	$	28.12

DD&A expenses for the three and nine months ended September 30, 2016, decreased to $35.7 million ($18.08 per BOE) and $104.5 million ($16.51 per BOE) from $55.0 million ($27.66 per BOE) and $143.3 million ($28.12 per BOE) in the corresponding periods in 2015. On a per BOE basis, the decrease was due to lower costs in the depletable base and increased proved reserves.

On a per BOE basis, DD&A expenses increased by 16% to $18.08 per BOE for the three months ended September 30, 2016, from $15.63 per BOE in the prior quarter due to higher costs in the depletable base.

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Asset impairment

We follow the full cost method of accounting for our oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less 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 estimates of future net revenues represent the fair market value of our reserves. In accordance with GAAP, we used an average Brent price of $42.23 per bbl for the purposes of the September 30, 2016, ceiling test calculations (June 30, 2016 - $44.48; March 31, 2016 - $48.79; December 31, 2015 - $54.08).

	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2016		2015		2016		2015
Impairment of oil and gas properties
Colombia	$	298,370	$	129,364	$	431,146	$	129,364
Brazil	21,604		17,600		37,006		46,933
Peru	—		3,014		899		40,980
	319,974		149,978		469,051		217,277
Impairment of inventory	—		—		664		—
	$	319,974	$	149,978	$	469,715	$	217,277

The Colombia ceiling test impairment loss and the inventory impairment were primarily due to lower oil prices and because the acquisition of PetroLatina was added into the cost base at fair value. However, these acquired assets were subjected to a prescribed U.S. GAAP ceiling test, which is not a fair value test, and which, as noted above, uses constant commodity pricing that averages prices during the preceding 12 months.

The Brazil ceiling test impairment loss related to lower oil prices and increased costs in the depletable base as a result of a $19.3 million impairment of unproved properties. Impairment losses in our Peru cost center related to costs incurred on Block 95. In the three months ended September 30, 2016, we ceased the impairment of costs incurred on Block 95 as a result of the effect of a revised field development plan for the Block.

G&A expenses

	Three Months Ended June 30		Three Months Ended September 30,						Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2016		2016		2015		% Change		2016		2015		% Change
G&A Expenses	$	7,975	$	5,592	$	7,863	(29	)	$	20,614	$	25,455	(19	)
U.S. Dollars Per BOE
G&A Expenses	$	3.91	$	2.83	$	3.95	(28	)	$	3.26	$	4.99	(35	)

After stock-based compensation and capitalized G&A and overhead recoveries, G&A expenses for the three and nine months ended September 30, 2016, decreased by 29% to $5.6 million ($2.83 per BOE) and by 19% to $20.6 million ($3.26 per BOE), respectively, from $7.9 million ($3.95 per BOE) and $25.5 million ($4.99 per BOE), respectively, in the corresponding periods in 2015. The decrease was mainly due to the cost control initiatives, partially offset by the effect of the weakening U.S. dollar. G&A expenses in the corresponding nine month period in 2015 were net of a credit of $2.1 million relating to the reversal of stock-based compensation expense for unvested stock options and RSUs associated with terminated employees.

35

G&A expenses for the three months ended September 30, 2016, decreased by 30% to $5.6 million ($2.83 per BOE) compared with $8.0 million ($3.91 per BOE) in the prior quarter.

Transaction expenses

For the three and nine months ended September 30, 2016, transaction expenses were $6.1 million and $7.3 million, respectively, compared with $nil in the corresponding periods in 2015. Transaction expenses in the three months ended September 30, 2016, related to our acquisition of PetroLatina, and in the nine months ended September 30, 2016, to our acquisitions of PetroLatina and Petroamerica.

Severance expenses

For the three and nine months ended September 30, 2016, severance expenses were $nil and $1.3 million, compared with $0.5 million and $6.8 million in the corresponding periods in 2015. Severance expenses in the nine months ended September 30, 2016 were consistent with the decrease in headcount.

Equity tax expense

For the nine months ended September 30, 2016, and 2015 equity tax expense of $3.1 million and $3.8 million, respectively, represented a Colombian tax which was calculated based on our Colombian legal entities' balance sheet equity for tax purposes at January 1. The legal obligation for each year's equity tax liability arises on January 1 of each year, therefore, we recognized the annual amounts of the equity tax expense in our interim unaudited condensed consolidated statement of operations during the three months ended March 31, 2016, and 2015. No equity tax expense was recorded in the three months ended September 30, 2016 and 2015.

Foreign exchange gains and losses

For the three and nine months ended September 30, 2016, we had a foreign exchange gain of $0.5 million and loss of $1.1 million, respectively, compared with foreign exchange gains of $12.9 million and $21.5 million, respectively, in the corresponding periods in 2015. Under U.S. GAAP, deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation was the main source of the foreign exchange gains and losses. The following table presents the change in the U.S. dollar against the Colombian peso for the three and nine months ended September 30, 2016, and 2015:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Change in the U.S. dollar against the Colombian peso	weakened by	strengthened by	weakened by	strengthened by
	1%	21%	9%	31%

Financial instrument gains and losses

	Three Months Ended September 30,					Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2016			2015		2016			2015
Trading securities loss	$	701		$	2,670	$	2,926		$	570
Commodity price derivative loss	2,190			—		856			—
Foreign currency derivatives (gain) loss	(840		)	—		(1,958		)	692
	$	2,051		$	2,670	$	1,824		$	1,262

Trading securities losses related to losses on the Madalena Energy Inc. shares we received in connection with the sale of our Argentina business unit in June 2014. During the three months ended September 30, 2016, we sold trading securities for cash proceeds of $0.8 million.

During the three months ended June 30, 2016, we entered into commodity price derivative contracts to manage the variability 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. We also entered into foreign currency

36

derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs. In 2015, foreign currency derivative losses related to our Colombian peso non-deliverable forward contracts which were purchased for purposes of fixing the exchange rate at which we would purchase or sell Colombian pesos to settle our income tax installments and payments.

Income tax expense and recovery

For the three and nine months ended September 30, 2016, income tax recovery was $106.6 million and $154.5 million, respectively, compared with income tax recovery of $59.0 million and $58.1 million, respectively, in the corresponding periods in 2015. The income tax recovery for the three and nine months ended September 30, 2016, was primarily due to a ceiling test impairment loss in Colombia. The income tax recovery for the three and nine months ended September 30, 2016, included $119.3 million and $172.5 million, respectively, associated with ceiling test impairment losses in Colombia. In the three and nine months ended September 30, 2015, income tax recovery associated with impairment losses in Peru and Brazil was offset by a full valuation allowance.

The effective tax rate was 31% in the nine months ended September 30, 2016, compared with 24% in the corresponding period in 2015. The change in the effective tax rate for the nine months ended September 30, 2016, was primarily due to an increase in the valuation allowance, partially offset by decreases in the impact of foreign taxes, foreign currency translation adjustments and other permanent differences.

For the nine months ended September 30, 2016, the difference between the effective tax rate of 31% and the 35% U.S. statutory rate was primarily due to an increase in the valuation allowance, which was largely attributable to impairment losses in Brazil and Colombia, as well as non-deductible local taxes, a third-party royalty in Colombia and stock based compensation. These items were partially offset by the impact of foreign taxes, foreign currency translation adjustments and other permanent differences. Other permanent differences mainly related to non-taxable gain arising on the acquisition of Petroamerica, partially offset by prior periods' true-up adjustments, uncertain tax position adjustments and other expenses deductible for tax purposes. For the nine months ended September 30, 2015, the difference between the effective tax rate of 24% and the 35% U.S. statutory rate was primarily due to an increase in the valuation allowance, non-deductible third party royalty in Colombia and other local taxes, partially offset by the impact of foreign taxes and other permanent differences.

Funds flow from operations (a non-GAAP liquidity measure)

For the three and nine months ended September 30, 2016, funds flow from operations decreased by 36% to $23.5 million and by 24% to $68.8 million, respectively, compared with the corresponding periods in 2015. For the three and nine months ended September 30, 2016, our funds flow from operations was negatively affected by transaction costs of$6.1 million and $7.3 million, respectively,Funds flow from operations for three and nine months ended September 30, 2016, is reconciled to the comparative period in 2015 and the prior quarter in the table below:

37

(Thousands of U.S. Dollars)	Third quarter 2016 compared with second quarter 2016			Three months ended September 30, 2015 compared with three months ended September 30, 2016			Nine months ended September 30, 2015 compared with Nine months ended September 30, 2016
Funds flow from operations for the prior period	$	33,752		$	36,679		$	90,715
Lower oil and natural gas sales	(3,174		)	(7,114		)	(23,579		)
Higher operating expenses	(7,890		)	(4,744		)	(1,140		)
Lower transportation expenses	444			7,084			3,687
Lower G&A expenses, excluding stock-based compensation expense and RSU settlement	1,668			2,141			7,248
Higher transaction expenses	(6,088		)	(6,088		)	(7,325		)
Lower severance expenses	281			461			5,528
Lower equity tax	—			—			716
Higher (lower) realized foreign exchange gains	3,442			(2,500		)	(7,021		)
Higher cash inflows on settlement of financial instruments	438			438			4,187
Higher interest expense, net of amortization of debt issuance costs	(1,226		)	(2,938		)	(5,029		)
Higher (lower) interest income	(19		)	464			859
Lower (higher) current income taxes	1,899			(356		)	(48		)
Funds flow from operations for the current period	$	23,527		$	23,527		$	68,798

2016 Capital Program

On May 31, 2016, we announced an increase to our 2016 capital budget of $33 million to $43 million for a revised total of $140 million to $150 million. Our previously announced base capital budget was $107 million. We expect that the increased capital budget will be entirely directed towards expenditures in Colombia. We expect to finance our 2016 capital program through cash flows from operations, cash on hand and available capacity on our credit facility.

Capital expenditures for the nine months ended September 30, 2016, were $69.7 million compared with $114.8 million for the nine months ended September 30, 2015. In the nine months ended September 30, 2016, 82% of our capital expenditures were incurred in Colombia.

Capital Expenditures - Colombia

Capital expenditures in our Colombian segment during the three months ended September 30, 2016, were $20.5 million. The significant elements of our third quarter 2016 capital program in Colombia were:

• On the Chaza Block (100% working interest ("WI"), operated), we drilled and completed the Guriyaco-1 exploration well, which was completed as an oil producer.

• On the Putumayo-7 Block (100% WI, operated), we continued civil works for the Cumplidor-1 and Alpha-1 exploration wells. Drilling of the Cumplidor-1 exploration well commenced subsequent to the end of the quarter, on October 20, 2016.

• On the Putumayo-4 Block (100% WI, operated), we continued activities related to environmental permitting for the Siriri-1 exploration well.

• On the Midas Block (100% WI, operated), we commenced civil works for three new development wells on the Acordionero Field. Drilling of the Acordionero-5 development well commenced subsequent to the end of the quarter, on October 2, 2016. We acquired the Midas Block on August 23, 2016, pursuant to the PetroLatina acquisition

• On the Suroriente Block (15.8% WI, non-operated), we commenced a well workover campaign at the Cohembi and Quinde oil fields.

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• We continued facilities work at the Moqueta Field on the Chaza Block.

Capital Expenditures – Brazil

Capital expenditures in our Brazilian segment during the three months ended September 30, 2016, were $3.1 million. In the third quarter of 2016, we continued facility improvements, including the gas liquefaction project and a flare stack.

Capital Expenditures – Peru

Capital expenditures in our Peruvian segment for the three months ended September 30, 2016, were $1.4 million, and included $0.5 million on Block 95 and $0.9 million on our other blocks in Peru. In the third quarter of 2016, we continued work on a revised development plan for Block 95, activities relating to maintaining tangible asset integrity and security of our five blocks in Peru (95, 107 and 133, 123 and 129) and moving forward with environmental approvals on Blocks 107 and 133 (100% WI, operated).

Liquidity and Capital Resources

At September 30, 2016, we had working capital (excluding short-term debt) of $29.4 million and short term debt of $127.5 million compared with working capital of $160.4 million at December 31, 2015. Working capital included cash and cash equivalents of $48.1 million and restricted cash of $13.2 million, compared with $145.3 million of cash and cash equivalents and restricted cash of $0.1 million at December 31, 2015.

We believe that our cash resources, including cash on hand, cash generated from operations and available capacity on our credit facility, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for 2016, given current oil price trends and production levels. In accordance with our investment policy, cash balances are held in our primary cash management bank in interest earning current accounts or are invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions. 

At September 30, 2016, we had outstanding commodity price derivative positions as follows:

Period and type of instrument	Volume, bopd	Reference	Sold Put		Purchased Put		Sold Call
Collar: June 1, 2016 to May 31, 2017	10,000	ICE Brent	$	35	$	45	$	65

During October 2016, we executed the following additional commodity price derivative positions:

Period and type of instrument	Volume, bopd	Reference	Sold Put		Purchased Put		Sold Call
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

At September 30, 2016, we had outstanding foreign currency derivative positions as follows:

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Period and type of instrument	Amount hedged (COP)	Reference	Purchased Call (COP)	Sold Put (COP)	Sold Put (COP)
Collar: June 1, 2016 to June 30, 2016	9,794.6	COP	3,000	3,265	3,310
Collar: July 1, 2016 to September 30, 2016	25,064.6	COP	3,000	3,275	3,320
Collar: October 1, 2016 to December 31, 2016	20,930.0	COP	3,000	3,285	3,330
Collar: January 1, 2017 to March 31, 2017	31,597.6	COP	3,100	3,300	3,345
Collar: April 1, 2017 to May 31, 2017	22,697.2	COP	3,100	3,310	3,370
	110,084.0

Notes

On April 6, 2016, we issued $115.0 million aggregate principal amount of our Notes in a private placement to qualified institutional buyers. The Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2016. The Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted.

The Notes are convertible at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date. The conversion rate is initially 311.4295 shares of Common Stock per $1,000 principal amount of Notes (equivalent to an initial conversion price of approximately $3.21 per share of Common Stock). The conversion rate is subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such a corporate event in certain circumstances.

We may not redeem the Notes prior to April 5, 2019, except in certain circumstances following a fundamental change as defined in the indenture governing the Notes). We may redeem for cash all or any portion of the Notes, at our option, on or after April 5, 2019, if (terms used below are as defined in the indenture governing the Notes):

(i) the last reported sale price of our Common Stock has been at least 150% of the conversion price then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period (including the last trading day of such period) ending on, and including, the trading day immediately preceding the date on which we provide notice of redemption; and

(ii) we have filed all reports that we are required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, as applicable (other than current reports on Form 8-K), during the twelve months preceding the date on which we provide such notice.

The redemption price will be equal to 100% of the principal amount of the Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. No sinking fund is provided for the Notes.

If we undergo a fundamental change, holders may require us to repurchase for cash all or any portion of their Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.

PetroLatina Acquisition

As disclosed above, on August 23, 2016, we acquired all of the issued and outstanding common shares of PetroLatina for cash consideration of $461.3 million, subject to closing adjustments. Funding for the Acquisition consisted of adjusted cash payments to date which aggregate $442.6 million and a deferred payment of $25.0 million to be paid prior to December 31, 2016. The PetroLatina acquisition was funded through a combination of our cash on hand, gross proceeds of $173.5 million from the Subscription Receipts, available borrowings under our existing revolving credit facility and $130.0 million of borrowings under a Bridge Loan Facility. We believe that our cash resources, including cash on hand, cash generated from operations and available capacity on our credit facility will be sufficient to pay the deferred payment of $25.0 million.

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As part of the PetroLatina Acquisition, we assumed a reserve-backed credit facility with an outstanding balance as at the PetroLatina Acquisition Date of $80.0 million. We repaid this credit facility upon closing of the PetroLatina Acquisition on August 23, 2016.

Revolving Credit Facility and Bridge Loan Facility

We have a credit facility with a syndicate of lenders. Availability under the revolving credit facility is determined by a proven reserves-based borrowing base, and remains subject to the satisfaction of conditions precedent set forth in the credit agreement.

On June 2, 2016, we entered into a Second Amendment to our credit agreement dated September 18, 2015. Pursuant to the Second Amendment, among other things, the committed borrowing base under our revolving credit facility was reduced from $200 million to $185 million, with $160 million readily available and $25 million subject to the consent of all lenders. Further, the amount of permitted senior debt under the Company's revolving credit facility was decreased from $600 million to $500 million. The borrowing base will be re-determined semi-annually based on reserve evaluation reports, subject to a maximum of $500 million. The next borrowing base redetermination is in late November 2016. The borrowing base for the revolving credit facility is supported by the present value of the petroleum reserves of our subsidiaries with operating branches in Colombia. The credit agreement includes a letter of credit sub-limit of up to $100 million. Amounts drawn down under the revolving credit facility bear interest, at our option, at the USD LIBOR rate plus a margin ranging from 2.00% per annum to 3.00% per annum, or an alternate base rate plus a margin ranging from 1.00% per annum to 2.00% per annum, in each case based on the borrowing base utilization percentage. Undrawn amounts under the revolving credit facility bear interest at 0.75% per annum, based on the average daily amount of unused commitments. A letter of credit participation fee of 0.25% per annum will accrue on the average daily amount of letter of credit exposure.

On August 23, 2016, we entered into an amendment to the terms of our credit facility to add a Bridge Loan Facility, pursuant to which the lenders provided $130.0 million in secured bridge loan financing to fund a portion of the purchase price of the PetroLatina Acquisition The Bridge Loan Facility has a term of 364 days, bears interest at USD LIBOR plus 6%, and has customary bridge facility repayment terms, providing for the prepayment of the Bridge Loan Facility upon the occurrence of certain events, including certain debt issuances. It is otherwise on substantially the same terms as the existing secured revolving credit facility.

On August 23, 2016, in connection with the PetroLatina Acquisition, we drew $95.0 million on our revolving credit facility and $130.0 million on our Bridge Loan Facility. We subsequently repaid $30.0 million of the outstanding balance on our revolving credit facility, resulting in an outstanding balance of $65.0 million, at September 30, 2016. Loans under the Bridge Loan Facility are scheduled to mature on August 22, 2017, and under the revolving credit facility on September 18, 2018. We believe that our cash resources, including cash on hand, cash generated from operations and available capacity on our credit facility will be sufficient to repay our Bridge Loan Facility.

As a result of the semi-annual redetermination of the committed borrowing base under our revolving credit facility, subject to documentation, the committed borrowing base will be increased from $185 million, with $160 million readily available and $25 million subject to the consent of all lenders, to $250 million readily available. Upon an increase to the committed borrowing base under our revolving credit facility, we would be required to partially repay our Bridge Loan Facility in an amount equal to the increase in the borrowing base.

Under the terms of the 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 ("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, 2016, 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.

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

At September 30, 2016, 77% 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. As noted above, during the nine months ended September 30, 2016, our parent company in the United States received net proceeds of $109.1 million from the Notes offering and this significantly increased the percentage of cash and cash equivalents held by our subsidiaries and partnerships in Canada and the United States. At this time, we do not intend to repatriate further funds, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the

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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.

The government in Brazil requires us to register funds that enter and exit the country with its central bank. In Brazil and Colombia, all transactions must be carried out in the local currency of the country. 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. In Peru, expenditures may be paid in local currency or U.S. dollars.

Cash Flows

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

	Nine Months Ended September 30,
	2016			2015
Sources of cash and cash equivalents:
Net cash provided by operating activities	$	86,399		$	58,579
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 other debt, net of issuance costs	220,169			—
Other	5,957			900
	587,420			59,479
Uses of cash and cash equivalents:
Acquisitions of PetroLatina and PetroAmerica, net of cash acquired	(471,631		)	—
Additions to property, plant and equipment - acquisition of PGC	(19,388		)	—
Additions to property, plant and equipment, excluding PGC acquisition	(69,667		)	(114,793		)
Repayment of debt	(110,181		)	—
Changes in non-cash investing working capital	(8,036		)	(76,744		)
Repurchase of shares of Common Stock	—			(6,616		)
Foreign exchange loss on cash and cash equivalents	(452		)	(6,196		)
Decrease in restricted cash	(5,334		)	—
	(684,689		)	(204,349		)
Net decrease in cash and cash equivalents	$	(97,269	)	$	(144,870	)

Cash provided by operating activities in the nine months ended September 30, 2016, was primarily affected by lower funds flow from operations (see funds flow from operations reconciliation above) and an $18.1 million change in assets and liabilities from operating activities.

Off-Balance Sheet Arrangements

As at September 30, 2016, we had no off-balance sheet arrangements.

Contractual Obligations

During August 2016, in connection with our acquisition of PetroLatina, we drew $95.0 million on our revolving credit facility and $130.0 million on our Bridge Loan Facility. We subsequently repaid $30.0 million of the outstanding balance on our revolving credit facility, resulting in an outstanding balance of $65.0 million, at September 30, 2016. Borrowings under the Bridge Loan Facility will mature on August 22, 2017, and borrowings under the revolving credit facility will mature on September 18, 2018. In connection with our acquisition of PetroLatina, we are obligated to make a deferred cash payment of $25.0 million prior to December 31, 2016.

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During April 2016, we issued $115.0 million aggregate principal amount of our Notes. The Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2016. The Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted.

See Note 6 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.

Except as noted above, as at September 30, 2016, there were no other material changes to our contractual obligations outside of the ordinary course of business from those as at December 31, 2015.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2015 Annual Report on Form 10-K, filed with the SEC on February 29, 2016, and have not changed materially since the filing of that document, other than as follows:

Derivative Activities

During the three months ended June 30, 2016, we entered into commodity price derivative contracts to manage the variability 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. We also entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs.

Under accounting rules, we may elect to designate certain derivative contracts that qualify for hedge accounting as hedges against the price that we will receive for our future oil and gas production. However, we do not designate any of our derivative contracts as accounting hedges. Because derivative contracts not designated for hedge accounting are accounted for on a mark-to-market basis, we are likely in the future to experience non-cash volatility in our reported net income or loss during periods of commodity price volatility.

As at September 30, 2016, we had derivative assets of $5.2 million which are classified as a Level 2 fair value measurement. The value of these contracts at their respective settlement dates could be significantly different than the fair value as at September 30, 2016. 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. We also perform an internal valuation to ensure the reasonableness of third party quotes.

For further discussion of our derivative instruments and activities, see Note 11, "Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk" to our condensed consolidated financial statements in Item 1 of this report for additional information regarding the accounting applicable to our derivative contracts, a listing of open contracts and the estimated fair market value of those contracts as at September 30, 2016.

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

In the nine months ended September 30, 2016, we recorded ceiling test impairment losses in our Colombia and Brazil cost centers of $431.1 million and $37.0 million, respectively. The Colombia ceiling test impairment loss related to lower oil prices and because the acquisition of PetroLatina was added into the cost base at fair value. However, these acquired assets were subjected to a prescribed U.S. GAAP ceiling test, which is not a fair value test, and which uses constant commodity pricing that averages prices during the preceding 12 months. The Brazil ceiling test impairment loss related to lower oil prices and increased costs in the depletable base as a result of a $19.3 million impairment of unproved properties. We used an average Brent price of $42.23 per bbl for the purposes of the September 30, 2016, ceiling test calculations (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 experience ceiling test impairment losses in our Brazil and Colombia cost centers in the fourth quarter of 2016. 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.

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Subject to these factors and inherent limitations, we believe that ceiling test impairment losses in the fourth quarter of 2016 could exceed $0.1 million in Brazil and $30 million in Colombia. The calculation of the impact of lower 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 pro forma Brent oil price of $43.07 per bbl for the year ended December 31, 2016. These pro forma oil prices were 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 30, 2016, and, for the two months ended December 31, 2016, estimated oil prices for the fourth quarter of 2016 using the forward price curve forecast from Bloomberg dated October 31, 2016.

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. In Brazil, foreign exchange rates can materially impact operating costs and the income tax calculation.

Holding all factors constant other than benchmark oil prices and related royalty rates, we do not expect any downward adjustment to our consolidated NAR reserve volumes during the fourth quarter of 2016. This disclosure is based on a pro forma Brent oil price of $43.07 per bbl for the year ended December 31, 2016, calculated as described above.

Business Environment Outlook

For over 40 years, the Colombian government has been engaged in a conflict with two main Marxist guerrilla groups: Revolutionary Armed Forces of Colombia ("FARC") and the National Liberation Army ("ELN"). Both of these groups have been designated as terrorist organizations by the United States and the European Union. Another threat comes from criminal gangs formed from the former members of the United Self-Defense Forces of Colombia militia, a paramilitary group that originally was organized to combat FARC and ELN, but has since been dissolved by the Columbian government. We operate principally in the Putumayo Basin in Colombia. Pipelines have been primary targets because of the length of such pipelines and the remoteness of the areas in which the pipelines are laid. The OTA pipeline which transports oil from the Putumayo region and which is one of our export routes has been targeted by these guerrilla groups.

On September 26, 2016, the Colombian government and the FARC signed a peace agreement (the "Agreement"). However, on October 2, 2016, the Agreement was rejected by Colombian voters in a national referendum. Pursuant to the Agreement, the FARC would have demobilized its troops and urban militia members and handed over its weapons to a United Nations mission within 180 days. Once demobilized and disarmed, the FARC would have become a legal political party and would have been guaranteed at least five seats in the Senate and another five seats in the House of Representatives in 2018 congressional elections.

While peace talks continue between the Colombian government and the FARC, peace process negotiations between the government and FARC may not generate the intended outcome for both parties. The impact of such a peace process is not determinable on our operations. Continuing attempts by the Colombian government to reduce or prevent guerrilla activity may not be successful and guerrilla activity may continue to disrupt our operations in the future. Our efforts to increase security measures may not be successful and there can also be no assurance that we can maintain the safety of our or our contractors' field personnel and Bogota head office personnel or operations in Colombia or that this violence will not continue to adversely affect our operations in the future and cause significant loss.

Our revenues are significantly affected by the continuing fluctuations in world oil prices. Oil prices are volatile and unpredictable and are influenced by concerns about the quantity of world supply and demand fundamentals, market competition between large producers, predominately members of OPEC (Organization of Petroleum Producing Countries), for market share, political influences, financial markets and the impact of the worldwide economy on oil supply and demand growth.

We believe that our current operations and 2016 capital expenditure program can be funded from cash flow from existing operations, available capacity on our credit facility and cash on hand. Should our operating cash flow decline due to unforeseen events, including additional pipeline delivery restrictions in Colombia or continued downturn in oil and gas prices, we would consider financing our capital expenditure program with proceeds from the disposition of assets or capital markets transactions, or a combination thereof, or we would consider reducing our capital expenditure program. We are the operator in the majority of our blocks and therefore have discretion on the timing of our capital expenditures. Given the current economic environment and unstable conditions in the Middle East, North Africa, and Europe and the current over supply of oil in world markets, the oil price environment is unpredictable and unstable. We are unable to determine the impact, if any, these events

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may have on oil prices and demand. The timing and execution of our capital expenditure program are also affected by the availability of services from third party oil field contractors and our ability to obtain, sustain or renew necessary government licenses and permits on a timely basis to conduct exploration and development activities. Any delay may affect our ability to execute our capital expenditure program.

The credit markets, including the high yield bond market and other debt markets that provide capital to oil and gas companies, have experienced adverse conditions. We have not been materially impacted by these conditions; however, continuing volatility in oil prices may continue to contribute to these adverse conditions, which could increase costs associated with renewing or issuing debt or affect our ability to access those markets.

Our future growth and acquisitions may depend on our ability to raise additional funds through equity and debt capital market transactions. Should we access such capital markets to fund capital expenditures or other acquisition and development opportunities, such funding may be affected by the market value of shares of our Common Stock. Issuing additional shares of Common Stock, or other equity securities convertible into Common Stock, may further dilute our existing shareholders. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve further pledging of some or all of our assets may require compliance with debt covenants and will expose us to interest rate risk. Depending on the currency used to borrow money, we may also be exposed to further foreign exchange risk. Our ability to borrow money and the interest rate we pay for any money we borrow will be affected by market conditions and we cannot predict what price we may pay for any borrowed money.

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.

During the three months ended June 30, 2016, we entered into commodity price derivative contracts to manage the variability 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 essentially 100% of our revenues are related to the U.S. dollar price of WTI or Brent 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 Brazil, prices for oil are in U.S. dollars, but revenues are received in local currency translated according to current exchange rates. The majority of our capital expenditures within Brazil are based on U.S. dollar prices, but are paid in local currency translated according to current exchange rates. 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 all locations are in local currency. 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 to the U.S. dollar functional currency.

During the three months ended June 30, 2016, we entered into foreign currency derivative contracts to manage the variability in cash flows associated with the Company's 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 and Bridge Loan Facility, which bear floating rates of interest. At September 30, 2016, our outstanding our revolving credit facility and Bridge Loan Facility totaled $195.0 million (December 31, 2015 - $nil).

Further information

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See Note 11 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 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(e) of the Exchange Act. Based on their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as at September 30, 2016.

Changes in Internal Control over Financial Reporting

We acquired Petroamerica, PGC and PetroLatina on January 13, 2016, January 25, 2016, and August 23, 2016, respectively, and are currently in the process of integrating these companies into our existing internal controls and procedures. There were no changes in our internal control over financial reporting during the quarter ended September 30, 2016, 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 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 material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 2015, and material matters that have arisen since the filing of such report.

Item 1A. Risk Factors

See Part I, Item 1A Risk Factors of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Except as set forth below, the risks facing our company have not changed materially from those set forth in Part I, Item 1A Risk Factors of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

Guerrilla Activity in Colombia Has Disrupted and Delayed, and Could Continue to Disrupt or Delay, Our Operations and We May Be Unable to Safeguard Our Operations and Personnel in Colombia.

For over 40 years, the Colombian government has been engaged in a conflict with two main Marxist guerrilla groups: the FARC and the ELN. Both of these groups have been designated as terrorist organizations by the United States and the European Union. Another threat comes from criminal gangs formed from the former members of the United Self-Defense Forces of Colombia militia, a paramilitary group that originally was organized to combat FARC and ELN, but has since been dissolved by the Columbian government.

On September 26, 2016, the Colombian government and the FARC signed a peace agreement, however, on October 2, 2016, the Agreement was rejected by Colombian voters in a national referendum. Pursuant to the Agreement, the FARC would have demobilized its troops and urban militia members and handed over its weapons to a United Nations mission within 180 days.

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Once demobilized and disarmed, the FARC would have become a legal political party and would have been guaranteed at least five seats in the Senate and another five seats in the House of Representatives in 2018 congressional elections.

Negotiations between the government and FARC may lead to a peaceful resolution and may not generate the intended outcome for either party. The impact of these negotiations or any potential resolution is not determinable on our operations.

We operate principally in the Putumayo Basin in Colombia, and have properties in other basins, including the Catatumbo, Cauca, Llanos, Sinu-San Jacinto, Middle Magdalena and Lower Magdalena Basins. Pipelines have been primary targets of guerrillaactivity, because of the length of such pipelines and the remoteness of the areas in which the pipelines are laid. The OTA pipeline, which transports oil from the Putumayo region to the Port of Tumaco and which is one of our export routes, has been targeted by FARC. Starting in 2008, the OTA pipeline experienced outages of various lengths of time. Since 2012, the OTA pipeline has been shut down for 863 days (including 166 days as a result of landslides and maintenance works). Such disruptions may continue indefinitely and could harm our business.

Continuing attempts by the Colombian government to reduce or prevent guerrilla activity may not be successful and dissident guerrilla activity may continue to disrupt our operations in the future. Our efforts to increase security measures may not be successful and there can also be no assurance that we can maintain the safety of our or our contractors' field personnel and Bogota head office personnel or operations in Colombia or that this violence will not continue to adversely affect our operations in the future and cause significant loss.

We may not realize the benefits anticipated as a result of the PetroLatina acquisition.

The Acquisition involves potential risks, including, without limitation, inefficiencies and unexpected costs and liabilities. If these risks or other expected costs and liabilities were to materialize, any desired benefits of the Acquisition may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted.

Item 6. Exhibits

The exhibits required to be filed by Item 6 are set forth in the Exhibit Index accompanying this Quarterly Report.

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 4, 2016	/s/ Gary Guidry
	By: Gary Guidry
	President and Chief Executive Officer
	(Principal Executive Officer)

Date: November 4, 2016	/s/ Ryan Ellson
	By: Ryan Ellson
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibit No.	Description	Reference
2.1+	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+	Share Purchase Agreement dated as at June 30, 2016, among Gran Tierra Energy International Holdings Ltd., Tribeca Oil & Gas Inc., Macquarie Bank Limited, Rorick Ventures Group Inc., as vendors, and PetroLatina Energy Limited.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on July 7, 2016 (SEC File No. 001-34018).
3.1	Amended and Restated Articles of Incorporation.	Incorporated by reference to Exhibit 3.1 to the Annual Report on Form 10-K, filed with the SEC on February 26, 2014 (SEC File No. 001-34018).
3.2	Amended and Restated Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on March 3, 2016 (SEC File No. 001-34018).
3.3	Certificate of Incorporation.	Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 3, 2016 (SEC File No. 001-34018).
3.4	By-Laws 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 3, 2016 (SEC File No. 001-34018).
4.1	Subscription Receipt Agreement, dated July 8, 2016, by and between Gran Tierra Energy Inc. and Computershare Trust Company of Canada.	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).
4.2	Form of Registration Rights Agreement.	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).
10.1	Bridge Loan Facility between Gran Tierra Energy Inc. and Scotiabank.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on August 29, 2016 (SEC File No. 001-34018).
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

101.SCH  XBRL Taxonomy Extension Schema Document

101.CAL  XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB  XBRL Taxonomy Extension Label Linkbase Document

101.PRE  XBRL Taxonomy Extension Presentation Linkbase Document

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

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