Edgar Filing: GRAN TIERRA ENERGY INC.

10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2016



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)



Nevada		98-0479924
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

200, 150 13 Avenue S.W. Calgary, Alberta, Canada T2R 0V2
(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 April 28, 2016, the following number of shares of the registrant’s capital stock were outstanding: 287,962,518 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 3,638,889 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 4,875,177 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Quarterly Period Ended March 31, 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	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34

PART II	Other Information
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 6.	Exhibits	34
SIGNATURES		34
EXHIBIT INDEX		36

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 this Quarterly Report 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 ("NGL") volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

PART I - Financial Information

Item 1. Financial Statements

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations (Unaudited)

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



	Three Months Ended March 31,
	2016			2015
OIL AND NATURAL GAS SALES (NOTE 4)	$	57,403		$	76,231

EXPENSES
Operating	19,067			22,661
Transportation	12,328			8,773
Depletion, depreciation and accretion (Note 4)	36,912			49,140
Asset impairment (Notes 4 and 5)	56,898			37,014
General and administrative (Notes 4 and 12)	8,805			7,294
Severance	1,018			4,378
Equity tax (Note 8)	3,051			3,769
Foreign exchange loss (gain)	785			(11,538		)
Financial instruments loss (gain) (Note 10)	845			(42		)
	139,709			121,449

GAIN ON ACQUISITION (NOTE 3)	11,712			—
INTEREST INCOME (NOTE 4)	449			421
LOSS BEFORE INCOME TAXES (NOTE 4)	(70,145		)	(44,797		)

INCOME TAX (EXPENSE) RECOVERY
Current	(2,023		)	(2,425		)
Deferred	27,136			2,356
	25,113			(69		)
NET LOSS AND COMPREHENSIVE LOSS	$	(45,032	)	$	(44,866	)

NET LOSS PER SHARE - BASIC AND DILUTED	$	(0.15	)	$	(0.16	)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	293,812,226			286,194,315
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	293,812,226			286,194,315

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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



	March 31,			December 31,
	2016			2015
ASSETS
Current Assets
Cash and cash equivalents	$	51,308		$	145,342
Restricted cash (Notes 3 and 5)	18,474			92
Accounts receivable	35,573			29,217
Marketable securities (Note 10)	5,362			6,250
Inventory (Note 5)	10,690			19,056
Taxes receivable	34,712			28,635
Other current assets	5,992			5,848
Total Current Assets	162,111			234,440

Oil and Gas Properties
Proved	472,062			469,589
Unproved	373,899			310,771
Total Oil and Gas Properties	845,961			780,360
Other capital assets	8,229			8,633
Total Property, Plant and Equipment (Note 5)	854,190			788,993

Other Long-Term Assets
Restricted cash	6,414			3,317
Taxes receivable	8,978			8,276
Other long-term assets	13,998			8,511
Goodwill	102,581			102,581
Total Other Long-Term Assets	131,971			122,685
Total Assets	$	1,148,272		$	1,146,118
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	77,303		$	70,778
Taxes payable	943			1,067
Asset retirement obligation (Note 7)	3,255			2,146
Total Current Liabilities	81,501			73,991

Long-Term Liabilities
Deferred tax liabilities	30,880			34,592
Asset retirement obligation (Note 7)	43,205			31,078
Other long-term liabilities	8,096			4,815
Total Long-Term Liabilities	82,181			70,485

Contingencies (Note 9)
Subsequent Event (Note 13)
Shareholders’ Equity
Common Stock (Note 6) (287,657,518 and 273,442,799 shares of Common Stock and 8,514,066 and 8,572,066 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2016, and December 31, 2015, respectively)	10,199			10,186
Additional paid in capital	1,047,830			1,019,863
Deficit	(73,439		)	(28,407		)
Total Shareholders’ Equity	984,590			1,001,642
Total Liabilities and Shareholders’ Equity	$	1,148,272		$	1,146,118

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Three Months Ended March 31,
	2016			2015
Operating Activities
Net loss	$	(45,032	)	$	(44,866	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 4)	36,912			49,140
Asset impairment (Notes 4 and 5)	56,898			37,014
Deferred tax recovery	(27,136		)	(2,356		)
Stock-based compensation expense (recovery) (Note 6)	1,460			(513		)
Cash settlement of restricted share units	(673		)	(955		)
Unrealized foreign exchange gain	(183		)	(6,069		)
Financial instruments loss (gain) (Note 10)	845			(42		)
Cash settlement of financial instruments	44			(2,357		)
Cash settlement of asset retirement obligation (Note 7)	(104		)	(1,425		)
Gain on acquisition (Note 3)	(11,712		)	—
Net change in assets and liabilities from operating activities (Note 11)	(507		)	(25,226		)
Net cash provided by operating activities	10,812			2,345

Investing Activities
Increase in restricted cash	(10,771		)	(497		)
Additions to property, plant and equipment, excluding Corporate acquisitions (Note 4)	(26,180		)	(73,446		)
Additions to property, plant and equipment - acquisition of PetroGranada Colombia Limited (Note 5)	(19,388		)	—
Changes in non-cash investing working capital	50			(54,324		)
Cash paid for business combination, net of cash acquired (Note 3)	(50,909		)	—
Net cash used in investing activities	(107,198		)	(128,267		)

Financing Activities
Proceeds from issuance of shares of Common Stock (Note 6)	1,198			502
Net cash provided by financing activities	1,198			502

Foreign exchange gain (loss) on cash and cash equivalents	1,154			(2,968		)

Net decrease in cash and cash equivalents	(94,034		)	(128,388		)
Cash and cash equivalents, beginning of period	145,342			331,848
Cash and cash equivalents, end of period	$	51,308		$	203,460

Supplemental cash flow disclosures (Note 11)

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Three Months Ended March 31,			Year Ended December 31,
	2016			2015
Share Capital
Balance, beginning of period	$	10,186		$	10,190
Issuance of Common Stock (Note 6)	13			—
Repurchase of Common Stock	—			(4		)
Balance, end of period	10,199			10,186

Additional Paid in Capital
Balance, beginning of period	1,019,863			1,026,873
Issuance of Common Stock (Note 6)	25,798			—
Exercise of stock options (Note 6)	1,198			722
Stock-based compensation (Note 6)	971			2,263
Repurchase of Common Stock	—			(9,995		)
Balance, end of period	1,047,830			1,019,863

Retained Earnings (Deficit)
Balance, beginning of period	(28,407		)	239,622
Net loss	(45,032		)	(268,029		)
Balance, end of period	(73,439		)	(28,407		)

Total Shareholders’ Equity	$	984,590		$	1,001,642

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

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

1. Description of Business

Gran Tierra Energy Inc., a Nevada 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. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

Recently Issued Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the Financial Accounting Standards Board (the "FASB") issued guidance regarding the accounting for revenue from contracts with customers. In August 2015, the FASB issued Accounting Standards Update (“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)". The amendments in this ASU affect the guidance in ASU 2014-09 and clarify implementation guidance on principal versus agent considerations. 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.

Simplifying the Accounting for Measurement - Period Adjustments

In September 2015, the FASB issued 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 is not expected to materially impact the Company’s consolidated financial position, results of operations or cash flows or 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.

3. Business Combination

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 million shares 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 transferred based on the fair values of the assets and liabilities acquired:



(Thousands of U.S. Dollars)
Consideration Transferred:
Cash	$	70,625
Shares of Common Stock issued net of share issue costs	25,811
	$	96,436

Allocation of Consideration Transferred⁽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 transferred 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 transferred, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration transferred. 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. 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.

Pro Forma Results (unaudited)

Pro forma results for the three months ended March 31, 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.



	Three Months Ended March 31,
(Unaudited, thousands of U.S. Dollars, except per share amounts)	2016			2015
Oil and gas sales	$	57,874		$	93,286
Net loss	$	(56,757	)	$	(80,511	)
Net loss per share - basic and diluted	$	(0.19	)	$	(0.28	)

The supplemental pro forma net loss of Gran Tierra for the three months ended March 31, 2016, was adjusted to exclude the $11.7 million gain on acquisition and $1.3 million of acquisition costs recorded in general and administrative ("G&A") expenses because they were not expected to have a continuing impact on Gran Tierra’s results of operations.

The Company's consolidated statement of operations for the three months ended March 31, 2016, included oil and gas sales of $2.7 million and a loss after tax of $11.8 million from Petroamerica for the period subsequent to the Petroamerica Acquisition Date.

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 March 31, 2016
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	56,300		$	—		$	1,103		$	—		$	57,403
Interest income	229			5			12			203			449
Depletion, depreciation and accretion	35,736			141			718			317			36,912
Asset impairment	55,232			416			1,250			—			56,898
General and administrative expenses	3,265			409			292			4,839			8,805
(Loss) income before income taxes	(72,721		)	(712		)	(1,509		)	4,797			(70,145		)
Segment capital expenditures⁽¹⁾	21,986			1,268			2,720			206			26,180
	Three Months Ended March 31, 2015
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	74,067		$	—		$	2,164		$	—		$	76,231
Interest income	67			—			140			214			421
Depletion, depreciation and accretion	46,255			267			2,261			357			49,140
Asset impairment	—			32,681			4,333			—			37,014
General and administrative expenses	2,716			1,040			627			2,911			7,294
Income (loss) before income taxes	2,928			(35,442		)	(6,881		)	(5,402		)	(44,797		)
Segment capital expenditures	21,123			37,697			13,907			719			73,446

⁽¹⁾On January 13, 2016, the Company acquired all of the issued and outstanding common shares of Petroamerica, which acquisition was accounted for as a business combination (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.



	As at March 31, 2016
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	638,097	$	95,867	$	116,314	$	3,912	$	854,190
Goodwill	102,581		—		—		—		102,581
All other assets	141,741		21,208		1,873		26,679		191,501
Total Assets	$	882,419	$	117,075	$	118,187	$	30,591	$	1,148,272

	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 March 31, 2016			As at December 31, 2015
Oil and natural gas properties
Proved	$	2,088,937		$	1,998,330
Unproved	373,899			310,771
	2,462,836			2,309,101
Other	28,557			28,342
	2,491,393			2,337,443
Accumulated depletion, depreciation and impairment	(1,637,203		)	(1,548,450		)
	$	854,190		$	788,993

In the three months ended March 31, 2016, the Company recorded ceiling test impairment losses in its Colombia and Brazil cost centers of $54.6 million and $1.3 million, respectively, related to lower oil prices. In the three months ended March 31, 2015, the Company recorded a ceiling test impairment loss in its Brazil cost center of $4.3 million, 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 the three months ended March 31, 2016, and 2015, the Company recorded impairment losses in its Peru cost center of $0.4 million, and $32.7 million, respectively, related to costs incurred on Block 95.

Asset impairment for the three months ended March 31, 2016, and 2015 was as follows:



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016		2015
Impairment of oil and gas properties	$	56,234	$	37,014
Impairment of inventory	664		—
	$	56,898	$	37,014

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. 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 transferred 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:



(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash	$	37,727

Allocation of Consideration Transferred:
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	(8,402		)
	$	37,728

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 Block meet or exceed eight MMbbl. PGC is an oil and gas exploration, development and production company active in Colombia. Contingent consideration will be recognized when the contingency is resolved.

Inventory

At March 31, 2016, oil and supplies inventories were $9.4 million and $1.3 million, respectively (December 31, 2015 - $17.8 million and $1.3 million, respectively). At March 31, 2016, the Company had 331 Mbbl of oil inventory (December 31, 2015 - 616 Mbbl) NAR. In the three months ended March 31, 2016, the Company recorded oil inventory impairment of $0.7 million (three months ended March 31, 2015 - $nil) related to lower oil prices.

6. Share Capital

The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as Common Stock, par value $0.001 per share, 25 million are designated as Preferred Stock, par value $0.001 per share, and two shares are designated as special 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 for acquisition (Note 3)	13,656,719	—		—
Options exercised	500,000	—		—
Exchange of exchangeable shares	58,000	(58,000	)	—
Balance, March 31, 2016	287,657,518	4,875,177		3,638,889

Income (Loss) Per Share

Basic income (loss) per share is calculated by dividing income (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 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.



	Three Months Ended March 31,
	2016	2015
Weighted average number of common and exchangeable shares outstanding	293,812,226	286,194,315
Weighted average shares issuable pursuant to stock options	—	—
Weighted average shares assumed to be purchased from proceeds of stock options	—	—
Weighted average number of diluted common and exchangeable shares outstanding	293,812,226	286,194,315

For the three months ended March 31, 2016, 12,667,761 stock options (three months ended March 31, 2015 - 13,742,502 stock options), on a weighted average basis, were excluded from the diluted income per share calculation as the stock options 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 (“PSU”) and 20% consisted of stock options. Gran Tierra's Compensation Committee and Board of Directors believed it was important to revise the Company's equity compensation 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 further incentivize the Company's executives to achieve the operational goals established by the Board of Directors and to increase share and net asset value for stockholders. The Company’s equity compensation awards outstanding as of March 31, 2016, include PSUs, stock options, deferred share units ("DSUs") and restricted stock units (“RSUs”).

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 operating expenses or G&A expenses, as appropriate.

The following table provides information about PSU, DSU, RSU and stock option activity for the three months ended March 31, 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	2,297,700	59,229	—		1,286,525		2.65
Exercised	—	—	(272,397	)	(500,000	)	2.40
Forfeited	—	—	(166,685	)	(457,436	)	(4.71	)
Expired	—	—	—		(127,051	)	(6.49	)
Balance, March 31, 2016	2,297,700	59,229	576,375		13,053,595		4.46

The amounts recognized for stock-based compensation were as follows:



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016			2015
Compensation costs for PSUs	$	165		$	—
Compensation costs for stock options	971			(422		)
Compensation costs for DSUs	146			—
Compensation costs for RSUs	364			(60		)
	1,646			(482		)
Less: Stock-based compensation costs capitalized	(186		)	(31		)
Stock-based compensation expense (recovery)	$	1,460		$	(513	)

Stock-based compensation expense for the three months ended March 31, 2016, was primarily recorded in G&A expenses. For the three months ended March 31, 2015, stock-based compensation was a recovery of $0.5 million due to the reversal of stock-based compensation expense for unvested stock options of terminated employees and a decrease in the Company's share price since December 31, 2014. The stock-based compensation recovery for the three months ended March 31, 2015, was primarily recorded in G&A expenses.

At March 31, 2016, there was $9.6 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 2.3 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 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 of March 31, 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;

(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.

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 at the time of grant. Stock options generally vest over three years. The term of stock options granted starting May 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 2013 continue to have a term of ten years or three months after the grantee’s end of service to the Company, whichever occurs first.

For the three months ended March 31, 2016, 500,000 shares of Common Stock were issued for cash proceeds of $1.2 million (three months ended March 31, 2015 - $0.5 million) upon the exercise of stock options.

The weighted average grant date fair value for stock options granted in the three months ended March 31, 2016, was $1.12 (three months ended March 31, 2015 - $1.10).

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 of March 31, 2016 in cash. Once a DSU or RSU is vested, it is immediately settled. During the three months ended March 31, 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.

7. 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:



	Three Months Ended			Year Ended
(Thousands of U.S. Dollars)	March 31, 2016			December 31, 2015
Balance, December 31, 2015	$	33,224		$	35,812
Settlements	(194		)	(6,317		)
Liability incurred	923			1,556
Liabilities assumed in acquisition (Note 3)	11,852			—
Accretion	655			1,313
Revisions in estimated liability	—			860
Balance, March 31, 2016	$	46,460		$	33,224

Asset retirement obligation - current	$	3,255		$	2,146
Asset retirement obligation - long-term	43,205			31,078
	$	46,460		$	33,224

For the three months ended March 31, 2016, settlements included cash payments of $0.1 million with the balance in accounts payable and accrued liabilities at March 31, 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 March 31, 2016, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $8.5 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.

8. Taxes

The Company's effective tax rate was 36% in the three months ended March 31, 2016, compared with 0.2% 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, as well as non-deductible, other local taxes and third party royalty in Colombia. These were partially offset by other permanent differences, which mainly related to the non-taxable gain on the acquisition of Petroamerica, foreign currency translation adjustments and the impact of foreign taxes. The deferred tax recovery for three months ended March 31, 2016, included $22.4 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. At March 31, 2016, accounts payable included $3.3 million (December 31, 2015 - $nil) which will be paid in May and September 2016.

9. Contingencies

Gran Tierra’s production from the Costayaco Exploitation Area is subject to an additional royalty (the "HPR royalty"), which applies when cumulative gross production from an Exploitation Area is greater than five MMbbl. The HPR royalty is calculated on the difference between a trigger price defined in the Chaza Block exploration and production contract (the "Chaza Contract") and the sales price. The Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) has interpreted the Chaza Contract as requiring that the HPR royalty must be paid with respect to all production from the Moqueta Exploitation Area and initiated a noncompliance procedure under the Chaza Contract, which was contested by Gran Tierra because the Moqueta Exploitation Area and the Costayaco Exploitation Area are separate Exploitation Areas. ANH did not proceed with that noncompliance procedure. Gran Tierra also believes that the evidence shows that the Costayaco and Moqueta Fields are two clearly separate and independent hydrocarbon accumulations. Therefore, it is Gran Tierra’s view that, pursuant to the terms of the Chaza Contract, the HPR royalty is only to be paid with respect to production from the Moqueta Exploitation Area when the accumulated oil production from that Exploitation Area exceeds five MMbbl. Discussions with the ANH have not resolved this issue and Gran Tierra has initiated the dispute resolution process under the Chaza Contract by filing on January 14, 2013, an arbitration claim before the Center for Arbitration and Conciliation of the Chamber of Commerce of Bogotá, Colombia, seeking a decision that the HPR royalty is not payable until production from the Moqueta Exploitation Area exceeds five MMbbl. Gran Tierra supplemented its claim on May 30, 2013. The ANH filed a response to the claim seeking a declaration that its interpretation is correct and a counterclaim seeking, amongst other remedies, declarations that Gran Tierra breached the Chaza Contract by not paying the disputed HPR royalty, that the amount of the alleged HPR royalty is payable, and that the Chaza Contract be terminated.

Gran Tierra filed a response to the ANH's counterclaim and filed its comments on the ANH's responses to Gran Tierra's claim. The ANH filed an amended counterclaim and Gran Tierra filed a response to the ANH's amended counterclaim. The submission of evidence in the arbitration has been completed and final arguments were made by the parties to the arbitration tribunal on April 7, 2016. The arbitration tribunal indicated it would make its award on June 8, 2016. On April 30, 2015, total cumulative production from the Moqueta Exploitation Area reached 5.0 MMbbl and Gran Tierra commenced paying the HPR royalty payable on production over that threshold. The estimated compensation which would be payable on cumulative production if the ANH's claims are accepted in the arbitration is $66.3 million plus related interest of $30.7 million. Gran Tierra also disagrees with the interest rate that the ANH has used in calculating the interest cost. Gran Tierra asserts that since the HPR royalty is denominated in the U.S. dollar, the contract requires the interest rate to be three-month LIBOR plus 4%, whereas the ANH has applied the highest legally authorized interest rate on Colombian peso liabilities, which during the period of production to date has averaged approximately 29% per annum. At March 31, 2016, based on an interest rate of three-month LIBOR plus 4% related interest would be $7.1 million. At this time no amount has been accrued in the interim unaudited condensed consolidated financial statements nor deducted from the Company's reserves for the disputed HPR royalty as Gran Tierra does not consider it probable that a loss will be incurred.

Additionally, the ANH and Gran Tierra are engaged in discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Discussions with the ANH are ongoing. Based on the Company's understanding of the ANH's position, the estimated compensation which would be payable if the ANH’s interpretation is correct could be up to $44.8 million as at March 31, 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 March 31, 2016, the Company had provided promissory notes totaling $74.9 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.

10. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk

Financial Instruments

At March 31, 2016, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, trading securities, accounts payable and accrued liabilities, contingent consideration and 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, contingent consideration 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 contingent consideration, which relates to the acquisition of the remaining 30% working interest in certain properties in Brazil, is estimated based on the consideration expected to be transferred and discounted back to present value by applying an appropriate discount rate that reflected the risk factors associated with the payment streams. The discount rate used is determined in accordance with accepted valuation methods. 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, contingent consideration and RSU and PSU liabilities at March 31, 2016, and December 31, 2015, were as follows:



(Thousands of U.S. Dollars)	As at March 31, 2016		As at December 31, 2015
Trading securities	$	5,362	$	6,250

Contingent consideration liability	$	1,061	$	1,061
RSU and PSU liability	$	1,190	$	1,189
	$	2,251	$	2,250

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



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016		2015
Trading securities loss (gain)	$	845	$	(412	)
Foreign currency derivatives loss	—		370
Financial instruments loss (gain)	$	845	$	(42	)

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

The fair value of long-term restricted cash approximates its carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

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

At March 31, 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 and the fair value of the contingent

consideration payable in connection with the Brazil acquisition and PSU liability was determined using Level 3 inputs. The disclosure in the paragraph above regarding the fair value of cash and restricted cash was based on Level 1 inputs.

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

11. Supplemental Cash Flow Information

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



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016			2015
Accounts receivable and other long-term assets	(2,513		)	13,484
Inventory	4,339			2,159
Prepaids	606			528
Accounts payable and accrued and other long-term liabilities	(5,975		)	(21,414		)
Taxes receivable and payable	3,036			(19,983		)
Net changes in assets and liabilities from operating activities	$	(507	)	$	(25,226	)

The following table provides additional supplemental cash flow disclosures:



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016		2015
Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	35,606	$	55,335

See Note 3 in these condensed consolidated financial statements for disclosure regarding the Company's acquisition of Petroamerica.

12. General and Administrative Expenses



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016			2015
G&A expenses before stock-based compensation	$	14,085		$	20,265
Stock-based compensation	1,397			(530		)
Capitalized G&A and overhead recoveries	(6,677		)	(12,441		)
	$	8,805		$	7,294

13. Subsequent Event

On April 6, 2016, the Company issued $100 million aggregate principal amount of its 5.00% Convertible Senior Notes due 2021 (the "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.

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 cash all 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 was approximately $109.0 million, after deducting the initial purchasers' discount and the offering expenses payable by the Company. The Company intends to use the net proceeds from the sale of Notes for general corporate purposes, which may include acquisitions and/or capital expenditures.

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 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 13.7 million shares of Common Stock, and paid cash consideration of $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.

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, $6.6 million was released prior to March 31, 2016 and we expect that the remaining balance will be released this year. The acquisition was accounted for as an asset acquisition.



	Three Months Ended December 31,			Three Months Ended March 31,
	2015			2016			2015			% Change
Volumes (BOE)
Working Interest Production Before Royalties	2,128,655			2,330,539			2,161,331			8
Royalties	(312,534		)	(256,803		)	(348,776		)	(26	)
Production NAR	1,816,121			2,073,736			1,812,555			14
Decrease (Increase) in Inventory	(249,049		)	240,424			(66,653		)	(461	)
Sales⁽¹⁾	1,567,072			2,314,160			1,745,902			33

Average Daily Volumes (BOEPD)
Working Interest Production Before Royalties	23,138			25,610			24,015			7
Royalties	(3,397		)	(2,822		)	(3,875		)	(27	)
Production NAR	19,741			22,788			20,140			13
Decrease (Increase) in Inventory	(2,707		)	2,642			(741		)	(457	)
Sales⁽¹⁾	17,034			25,430			19,399			31

Operating Netback ($000s)
Oil and Natural Gas Sales	$	54,777		$	57,403		$	76,231		(25	)
Operating Expenses	(14,252		)	(19,067		)	(22,661		)	(16	)
Transportation Expenses	(12,199		)	(12,328		)	(8,773		)	41
Operating Netback⁽²⁾	$	28,326		$	26,008		$	44,797		(42	)

General and Administrative Expenses ("G&A") ($000s)
G&A Expenses Before Stock-Based Compensation, Gross	$	14,155		$	14,085		$	20,265		(30	)
Stock-Based Compensation	566			1,397			(530		)	(364	)
Capitalized G&A and Overhead Recoveries	(7,823		)	(6,677		)	(12,441		)	(46	)
	$	6,898		$	8,805		$	7,294		21

EBITDA ($000s)⁽³⁾	$	15,052		$	23,665		$	41,357		(43	)
Adjusted EBITDA ($000s)⁽³⁾	19,302			$	12,738		$	29,819		(57	)

Net Loss ($000s)	$	(82,722	)	$	(45,032	)	(44,866		)	—

Funds Flow From Operations ($000s)⁽⁴⁾	$	16,828		$	11,423		$	28,996		(61	)

Capital Expenditures ($000s)	$	41,878		$	26,180		$	73,446		(64	)



	As at
	March 31, 2016		December 31, 2015		% Change
Cash, Cash Equivalents and Current Restricted Cash ($000s)	$	69,782	$	145,434	(52	)

Working Capital ($000s)	$	80,610	$	160,449	(50	)

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

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. 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.

⁽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 operating performance and provide 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 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 December 31,			Three Months Ended March 31,
EBITDA - Non-GAAP Measure ($000s)	2015			2016			2015
Net loss	$	(82,722	)	$	(45,032	)	$	(44,866	)
Adjustments to reconcile net loss to EBITDA
DD&A expenses	33,044			36,912			49,140
Asset impairment	106,640			56,898			37,014
Income tax (recovery) expense	(41,910		)	(25,113		)	69
EBITDA	15,052			23,665			41,357
Gain on acquisition	—			(11,712		)	—
Foreign exchange loss (gain)	4,250			785			(11,538		)
Adjusted EBITDA	$	19,302		$	12,738		$	29,819

⁽⁴⁾ Funds flow from operations, as presented, is net loss adjusted for DD&A expenses, asset impairment, deferred tax recovery, stock-based compensation, cash settlement of RSUs, unrealized foreign exchange gains and losses, financial instruments gains and losses, cash settlement of foreign currency derivatives, other gain, and gain on acquisition. During the three months ended September 30, 2015, we changed our method of calculating funds flow from operations to be more consistent with our peers. Funds flow from operations is no longer net of cash settlement of asset retirement obligation. Additionally, foreign exchange losses on cash and cash equivalents have been excluded from funds flow. Comparative information has been restated to be calculated on a consistent basis. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to funds flow from operations is as follows:



	Three Months Ended December 31,			Three Months Ended March 31,
Funds Flow From Operations - Non-GAAP Measure ($000s)	2015			2016			2015
Net loss	$	(82,722	)	$	(45,032	)	$	(44,866	)
Adjustments to reconcile net loss to funds flow from operations
DD&A expenses	33,044			36,912			49,140
Asset impairment	106,640			56,898			37,014
Deferred tax recovery	(45,661		)	(27,136		)	(2,356		)
Stock-based compensation expense (recovery)	580			1,460			(513		)
Cash settlement of RSUs	(29		)	(673		)	(955		)
Unrealized foreign exchange loss (gain)	4,713			(183		)	(6,069		)
Financial instruments loss (gain)	765			845			(42		)
Cash settlement of financial instruments	—			44			(2,357		)
Gain on acquisition	—			(11,712		)	—
Other gain	(502		)	—			—
Funds flow from operations	$	16,828		$	11,423		$	28,996

Consolidated Results of Operations



	Three Months Ended December 31,			Three Months Ended March 31,
	2015			2016			2015			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	54,777		$	57,403		$	76,231		(25	)
Operating expenses	14,252			19,067			22,661			(16	)
Transportation expenses	12,199			12,328			8,773			41
Operating netback⁽¹⁾	28,326			26,008			44,797			(42	)

DD&A expenses	33,044			36,912			49,140			(25	)
Asset impairment	106,640			56,898			37,014			54
G&A expenses	6,898			8,805			7,294			21
Severance expenses	2,163			1,018			4,378			(77	)
Equity tax	—			3,051			3,769			(19	)
Foreign exchange loss (gain)	4,250			785			(11,538		)	107
Financial instruments loss (gain)	765			845			(42		)	—
Other gain	(502		)	—			—			—
	153,258			108,314			90,015			20

Gain on acquisition	—			11,712			—			—
Interest income	300			449			421			7

Loss before income taxes	(124,632		)	(70,145		)	(44,797		)	57

Current income tax expense	(3,751		)	(2,023		)	(2,425		)	(17	)
Deferred income tax recovery	45,661			27,136			2,356			1,052
	41,910			25,113			(69		)	—
Net loss	$	(82,722	)	$	(45,032	)	$	(44,866	)	—

Sales Volumes⁽²⁾

Oil and NGL's, bbl	1,552,708			2,292,116			1,734,898			32
Natural gas, Mcf	86,186			132,265			66,026			100
Total sales volumes, BOE	1,567,072			2,314,160			1,745,902			33

Total sales volumes, BOEPD	17,034			25,430			19,399			31

Average Prices

Oil and NGL's per bbl	$	35.07		$	24.88		$	43.79		(43	)
Natural gas per Mcf	$	3.81		$	2.83		$	3.87		(27	)

Brent Price per bbl	$	43.57		$	33.70		53.91			(37	)

Consolidated Results of Operations per BOE sales volumes



Oil and natural gas sales	$	34.95		$	24.81		$	43.66		(43	)
Operating expenses	9.09			8.24			12.98			(37	)
Transportation expenses	7.78			5.33			5.02			6
Operating netback⁽¹⁾	18.08			11.24			25.66			(56	)

DD&A expenses	21.09			15.95			28.15			(43	)
Asset impairment	68.05			24.59			21.20			16
G&A expenses	4.40			3.80			4.18			(9	)
Severance expenses	1.38			0.44			2.51			(82	)
Equity tax	—			1.32			2.16			(39	)
Foreign exchange loss (gain)	2.71			0.34			(6.61		)	105
Financial instruments loss (gain)	0.49			0.37			(0.02		)	—
Other gain	(0.32		)	—			—			—
	97.80			46.81			51.57			(9	)

Gain on acquisition	—			5.06			—			—
Interest income	0.19			0.19			0.24			(21	)

Loss before income taxes	(79.53		)	(30.32		)	(25.67		)	18
Current income tax expense	(2.39		)	(0.87		)	(1.39		)	(37	)
Deferred income tax recovery	29.14			11.73			1.35			769
	26.75			10.86			(0.04		)	—
Net loss	$	(52.78	)	$	(19.46	)	$	(25.71	)	(24	)

⁽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.

Oil and gas production and sales volumes, BOEPD



	Three Months Ended March 31, 2016						Three Months Ended March 31, 2015
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	24,886		724		25,610		23,297		718		24,015
Royalties	(2,676	)	(146	)	(2,822	)	(3,778	)	(97	)	(3,875	)
Production NAR	22,210		578		22,788		19,519		621		20,140
Decrease (Increase) in Inventory	2,647		(5	)	2,642		(771	)	30		(741	)
Sales	24,857		573		25,430		18,748		651		19,399

Royalties, % of Working Interest Production Before Royalties	11	%	20	%	11	%	16	%	14	%	16	%

Oil and gas production NAR for the three months ended March 31, 2016, increased by 13% to 22,788 BOEPD compared with 20,140 BOEPD in the corresponding period in 2015. In the three months ended March 31, 2016, production from the newly acquired Petroamerica properties contributed 1,848 BOEPD NAR. Additionally, in the three months ended March 31, 2016, new wells in the Moqueta Field increased production in Colombia. The Company commenced its drilling program in the Chaza Block in late 2015 and continued into 2016. Production is expected to increase in the Chaza Block as additional wells are tied in. Royalties as a percentage of production decreased from the prior year commensurate with the decrease in oil prices.

In the three months ended March 31, 2016, our production in Brazil continued to be limited by a temporary capacity reduction at a third party's shipping facility due to an integrity issue with one of their oil receiving tanks. The third party operator completed repairs on the facility and the tank was fully operational as of March 21, 2016. Receiving capacity for the field's crude oil is now restored to 1,100 bopd.

In the corresponding period in Brazil in 2015, our operations in the Tiê Field were suspended by the Agência Nacional de Petróleo Gás Natural e Biocombustíveis ("ANP") from March 11, 2015, to May 15, 2015, due to alleged non-compliance with certain requirements regarding the health and safety management system identified during a safety and operational audit conducted by the ANP in early 2015. Clearance to resume production was received on May 15, 2015.

Oil and gas sales volumes for the three months ended March 31, 2016, increased by 31% to 25,430 BOEPD, compared with 19,399 BOEPD, in the corresponding period in 2015. Sales volumes increased due to higher working interest production (1,595 BOEPD), lower royalty volumes (1,053 BOEPD) and decreased inventory (3,383 bopd). During the three months ended March 31, 2016, oil inventory decreases accounted for 0.2 MMbbl or 2,642 bopd of increased sales volumes compared with oil inventory increases which accounted for 0.1 MMbbl or 741 bopd of reduced sales volumes in the corresponding period in 2015.

Operating netbacks



	Three Months Ended March 31, 2016									Three Months Ended March 31, 2015
(Thousands of U.S. Dollars)	Colombia			Brazil			Total			Colombia			Brazil			Total
Oil and Natural Gas Sales	$	56,300		$	1,103		$	57,403		$	74,067		$	2,164		$	76,231
Transportation Expenses	(12,256		)	(72		)	(12,328		)	(8,682		)	(91		)	(8,773		)
	44,044			1,031			45,075			65,385			2,073			67,458
Operating Expenses	(19,164		)	97			(19,067		)	(21,292		)	(1,369		)	(22,661		)
Operating Netback⁽¹⁾	$	24,880		$	1,128		$	26,008		$	44,093		$	704		$	44,797

U.S. Dollars Per bbl
Brent							$	33.70								53.91
WTI							$	33.45								48.63

U.S. Dollars Per BOE
Oil and Natural Gas Sales	$	24.89		$	21.13		$	24.81		$	43.90		$	36.92		$	43.66
Transportation Expenses	(5.42		)	(1.38		)	(5.33		)	(5.15		)	(1.55		)	(5.02		)
	19.47			19.75			19.48			38.75			35.37			38.64
Operating Expenses	(8.47		)	1.86			(8.24		)	(12.62		)	(23.36		)	(12.98		)
Operating Netback⁽¹⁾	$	11.00		$	21.61		$	11.24		$	26.13		$	12.01		$	25.66

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

Oil and gas sales for the three months ended March 31, 2016, decreased by 25% to $57.4 million, from $76.2 million in the corresponding period in 2015 primarily due to the effect of decreased realized oil prices, partially offset by higher sales volumes. Average realized prices decreased by 43% to $24.81 per BOE for the three months ended March 31, 2016, from $43.66 per BOE in the corresponding period in 2015. These price decreases were primarily due to lower benchmark oil prices. Average Brent and WTI oil prices for the three months ended March 31, 2016, decreased 37% and 31%, respectively, compared with the corresponding period in 2015.

During periods of OTA pipeline disruptions, we have multiple transportation alternatives. Each transportation route has varying effects on realized prices and transportation costs. During the three months ended March 31, 2016, 54% of our oil volumes sold in Colombia were sold through the OTA pipeline compared with 80% in the corresponding period in 2015. Sales during the three months ended March 31, 2016, reflected an inventory decrease in Ecuador of 235 Mbbl.

Oil and gas sales for the three months ended March 31, 2016, increased by 5% to $57.4 million from $54.8 million compared with the prior quarter primarily due to higher sales volumes, partially offset by lower realized prices. Average realized prices decreased

by 29% to $24.81 per BOE for the three months ended March 31, 2016, compared with $34.95 per BOE in the prior quarter, primarily due to lower benchmark oil prices. Average Brent oil prices for the three months ended March 31, 2016, were $33.70 per bbl, compared with $43.57 per bbl, in the prior quarter, a 23% decrease. During the prior quarter, 6% of our oil volumes sold in Colombia were sold through the OTA pipeline compared with 54% in the current quarter.

Transportation expenses increased by 41% to $12.3 million for the three months ended March 31, 2016, compared with the corresponding period in 2015. The increase was due to higher sales volumes combined with increased transportation expenses per BOE. On a per BOE basis, transportation expenses increased by 6% to $5.33 per BOE from $5.02 per BOE in the corresponding period in 2015. The increase was primarily due to the alternative transportation routes used during periods of OTA pipeline disruptions.

Transportation expenses for the three months ended March 31, 2016, were consistent with the prior quarter. The effect of higher sales volumes was offset by decreased transportation costs per BOE. On a per BOE basis, transportation expenses decreased by 31% to $5.33 per BOE from $7.78 per BOE in the prior quarter. The decrease was primarily due to the alternative transportation routes used during periods of OTA pipeline disruptions.

Operating expenses decreased by 16% to $19.1 million for the three months ended March 31, 2016, compared with the corresponding period in 2015. The decrease was due to decreased operating costs per BOE, partially offset by higher sales volumes. On a per BOE basis, operating expenses decreased by 37% to $8.24 per BOE for the three months ended March 31, 2016, from $12.98 per BOE in the corresponding period in 2015.

In Colombia, operating costs decreased by $4.15 per BOE primarily as a result of cost saving measures and the effect of the strengthening of the U.S. dollar against the local currency in Colombia, which resulted in savings for costs denominated in local currency.

In Brazil in the three months ended March 31, 2016, we reduced the value of a contingent loss by $0.4 million, or $7.97 per bbl based on volumes sold in Brazil, after we settled a one-time penalty for less than we had estimated. The one-time penalty related to alleged non-compliance with certain requirements regarding the health and safety management system, identified during a safety and operational audit conducted by the ANP in early 2015. Additionally, in Brazil operating costs per BOE decreased as a result of a reduction in headcount and the effect of the strengthening of the U.S. dollar against the local currency in Brazil.

On a per BOE basis, operating expenses decreased by 9% to $8.24 per BOE for the three months ended March 31, 2016, from $9.09 per BOE in the prior quarter. Operating expenses increased by 34% to $19.1 million in the three months ended March 31, 2016, compared with $14.3 million in the prior quarter primarily due to higher sales volumes, partially offset by the effect of decreased operating costs per BOE.

DD&A expenses



	Three Months Ended March 31, 2016				Three Months Ended March 31, 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	$	35,736	$	15.80	$	46,255	$	27.41
Brazil	718		13.75		2,261		38.58
Peru	141		—		267		—
Corporate	317		—		357		—
	$	36,912	$	15.95	$	49,140	$	28.15

DD&A expenses for the three months ended March 31, 2016, decreased to $36.9 million ($15.95 per BOE) from $49.1 million ($28.15 per BOE) in the corresponding period 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 decreased by 24% to $15.95 per BOE for the three months ended March 31, 2016, from $21.09 per BOE in the prior quarter.

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. We used an average Brent price of $48.79 per bbl for the purposes of the March 31, 2016, ceiling test calculations.



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016		2015
Impairment of oil and gas properties
Colombia	$	54,568	$	—
Brazil	1,250		4,333
Peru	416		32,681
	56,234		37,014
Impairment of inventory	664		—
	$	56,898	$	37,014

In the three months ended March 31, 2016, and 2015, ceiling test impairment losses in our Colombia and Brazil cost centers and inventory impairment were primarily due to lower oil prices and impairment losses in our Peru cost center related to costs incurred on Block 95.

G&A expenses



	Three Months Ended December 31,			Three Months Ended March 31,
(Thousands of U.S. Dollars)	2015			2016			2015			% Change
G&A Expenses Before Stock-Based Compensation, Gross	$	14,155		$	14,085		$	20,265		(30	)
Stock-Based Compensation	566			1,397			(530		)	(364	)
Capitalized G&A and Overhead Recoveries	(7,823		)	(6,677		)	(12,441		)	(46	)
	$	6,898		$	8,805		$	7,294		21
U.S. Dollars Per BOE	$	4.40		$	3.80		$	4.18		(9	)

G&A expenses before stock-based compensation and capitalized G&A and overhead recoveries decreased by 30% to $14.1 million ($6.09 per BOE), from $20.3 million ($11.61 per BOE), in the corresponding period in 2015 as a result of reductions in the number of our employees, commitment to cost control including focusing on all of our other G&A expenses, and the effect of the strengthening of the U.S. dollar against local currencies in South America and Canada which resulted in savings for costs denominated in local currency. G&A expenses in the three months ended March 31, 2016, included $1.3 million of costs relating to the acquisition of Petroamerica.

After stock-based compensation and capitalized G&A and overhead recoveries, G&A expenses for the three months ended March 31, 2016, increased by 21% to $8.8 million ($3.80 per BOE), from $7.3 million ($4.18 per BOE), in the corresponding period in 2015. The increase was mainly due to lower allocations to capital projects due to lower capital activity. Additionally, G&A expenses in the corresponding period in 2015 were net of a credit of $1.7 million relating to the reversal of stock-based compensation expense for unvested stock options and RSUs associated with terminated employees.

G&A expenses before stock-based compensation and capitalized G&A and overhead recoveries were consistent with the prior quarter, $14.1 million ($6.09 per BOE) compared with $14.2 million ($9.03 per BOE). G&A expenses for the three months ended March 31, 2016, increased by 28% to $8.8 million ($3.80 per BOE) compared with $6.9 million ($4.40 per BOE) in the prior quarter. The increase was primarily due to lower allocations to capital projects due to lower capital activity and higher stock-based compensation expense.

Severance expenses

For the three months ended March 31, 2016, severance expenses were $1.0 million, compared with $4.4 million in the corresponding period in 2015. Severance expenses were consistent with the decrease in headcount from both the corresponding period in the prior year and the prior quarter.

Equity tax expense

For the three months ended March 31, 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, 2015. 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.

Foreign exchange gains and losses

For the three months ended March 31, 2016, we had foreign exchange losses of $0.8 million, compared with foreign exchange gains of $11.5 million, in the corresponding period 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 Colombian peso against the U.S. dollar for the three months ended March 31, 2016, and 2015:



	Three Months Ended March 31,
	2016	2015
Change in the Colombian peso against the U.S. dollar	strengthened by	weakened by
Change in the Colombian peso against the U.S. dollar	4%	8%

Financial instrument gains and losses



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2016		2015
Trading securities loss (gain)	$	845	$	(412	)
Foreign currency derivatives loss	—		370
	$	845	$	(42	)

Trading securities gains and losses related to unrealized losses on the Madalena Energy Inc. shares we received in connection with the sale of our Argentina business unit in June 2014. Foreign currency derivative gains and losses related to our Colombian peso non-deliverable forward contracts. We purchased these contracts for purposes of fixing the exchange rate at which we would purchase or sell Colombian pesos to settle our income tax installments and payments. At March 31, 2016, we did not have any open foreign currency derivative positions.

Income tax expense and recovery

For the three months ended March 31, 2016, income tax recovery was $25.1 million, compared with income tax expense of $0.1 million in the corresponding period in 2015. The income tax recovery for the three months ended March 31, 2016, was primarily due to the ceiling test impairment loss in Colombia. The income tax recovery for the three months ended March 31, 2016, included $22.4 million associated with the ceiling test impairment loss in Colombia. In the three months ended March 31, 2015, income tax recovery associated with impairment losses in Peru and Brazil was offset by a full valuation allowance.

The effective tax rate was 36% in the three months ended March 31, 2016, compared with 0.2% in the corresponding period in 2015. The change in the effective tax rate for the three months ended March 31, 2016, was due to a decrease in other permanent differences caused by the gain on acquisition, a decrease in the valuation allowance, as well as a decrease in the foreign currency translation and the impact of foreign taxes.

For the three months ended March 31, 2016, the difference between the effective tax rate of 36% and the 35% U.S. statutory rate was primarily due to an increase in the valuation allowance, other local taxes and a non-deductible third party royalty in Colombia, partially offset by other permanent differences, the impact of foreign taxes and foreign currency translation. For the three months ended March 31, 2015, the difference between the effective tax rate of 0.2% and the 35% U.S. statutory rate was primarily a result of a loss before income taxes caused by the 2015 impairment losses in Peru and Brazil which were fully offset by an increase in the valuation allowance. Other factors that affected the effective tax rate in the three months ended March 31, 2015, were other local taxes, a non-deductible third party royalty in Colombia and other permanent differences, partially offset by foreign currency translation adjustments.

Funds flow from operations

For the three months ended March 31, 2016, funds flow from operations decreased by 61% to $11.4 million compared with the corresponding period in 2015. For the three months ended March 31, 2016, our funds flow was negatively impacted by equity tax of $3.1 million, realized foreign exchange losses of $1.0 million, transaction costs of $1.3 million and severance expenses of $1.0 million. Lower oil and natural gas sales, higher transportation and G&A expenses and realized foreign exchange losses were partially offset by lower operating, severance, equity tax and income tax expenses and the absence of cash settlement of financial instruments.

2016 Capital Program

In January 2016, we announced our 2016 capital budget. Our base 2016 capital program of $107.0 million consists of: $76.0 million for Colombia; $8.0 million for Brazil; $6.0 million for Peru; and $17.0 million for other. Included in other expenditures are asset retirement obligations, geological and geophysical studies, environmental impact assessments, Health, Safety, and Environmental services, other technical services and capitalized G&A.

In Colombia, our base 2016 capital program includes two water injector wells in the Costayaco Field and three development wells in the Moqueta Field, both on the Chaza Block (100% WI, operated), two exploration wells in the Putumayo-7 Block (subject to regulatory approval, 100% WI, operated) and an exploration well on the Llanos-10 Block (50% WI, non-operated) with the costs being carried by a third party. Minor facilities work is also planned for the Chaza

In Peru, the 2016 capital program includes only those activities required for retention of lands and security of assets. In Brazil, the capital program includes minimal activity to implement water injection for reservoir pressure maintenance, and to preserve current production levels. In both Peru and Brazil, operations have been scaled back significantly, with the aim of allowing time to explore and execute on options to maximize shareholder value.

In addition to our 2016 base capital budget, we have a discretionary capital budget of $61 million that we may utilize during 2016 in the event of an increase in commodity prices. If deployed, we expect that our discretionary capital budget would target six exploration wells, five development wells and seismic activities in Colombia.

We expect to finance our 2016 capital program through cash flows from operations and cash on hand, while retaining financial flexibility to undertake further development opportunities and opportunistically pursue acquisitions.

Capital expenditures for the three months ended March 31, 2016, were $26.2 million compared with $73.4 million for the three months ended March 31, 2015. In 2016, capital expenditures included drilling of $20.5 million, seismic of $0.2 million, facilities of $1.8 million and other expenditures of $3.7 million. Included in other expenditures are geological and geophysical studies, environmental impact assessments, Health, Safety, and Environmental services, other technical services and capitalized G&A.

Capital Expenditures - Colombia

Capital expenditures in our Colombian segment during the three months ended March 31, 2016, were $22.0 million. Capital expenditures in the three months ended March 31, 2016, consisted of drilling of $18.7 million, seismic of $0.1 million, facilities of $0.9 million and other expenditures of $2.3 million.

The significant elements of our first quarter 2016 capital program in Colombia were:

•

On the Chaza Block (100% working interest ("WI"), operated), we completed the Costayaco-24 development well and drilled and completed the Costayaco-23i, Costayaco-27i and Moqueta-20 development wells in the Costayaco and Moqueta Fields. All four wells were completed as oil producers. We completed a dual completion on the Moqueta-19i water injector well. We drilled the Moqueta-23 development well and started pre-drilling activities for the Moqueta 22 development well. The Moqueta 22 development well was spud subsequent to quarter end.


•	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 March 31, 2016, were $2.7 million, and consisted of drilling of $1.5 million, seismic of $0.1 million, facilities of $0.9 million and other expenditures of $0.2 million. In the first quarter of 2016, we commenced work on a water injection/pressure support project with an initial workover ongoing on the 1-GTE-7HPC-BA well to assess potential as a water source well.

Capital Expenditures – Peru

Capital expenditures in our Peruvian segment for the three months ended March 31, 2016, were $1.3 million, and included $0.4 million on Block 95 and $0.9 million on our other blocks in Peru. In the first quarter of 2016, operations in Peru continued to focus on 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 March 31, 2016, we had working capital of $80.6 million compared with $160.4 million at December 31, 2015. Working capital included cash and cash equivalents of $51.3 million and restricted cash of $18.5 million, compared with $145.3 million of cash and cash equivalents and restricted cash of $0.1 million at December 31, 2015. Of the opening balance of PGC restricted cash of $18.6 million, $6.6 million was released prior to March 31, 2016 and we expect that the remaining balance will be released this year.

Subsequent to March 31, 2016, we issued $100 million aggregate principal amount of our 5.00% Convertible Senior Notes due 2021 (the "Notes") in a private placement to qualified institutional buyers. On April 22, 2016, we issued an additional $15 million aggregate principal amount of the Notes pursuant to the underwriters’ exercise of their option to acquire additional Notes. Net proceeds from the sale of the Notes were approximately $109.0 million, after deducting the initial purchasers' discount and the offering expenses.

We believe that our cash resources, including cash on hand and cash generated from operations, 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 March 31, 2016, 81% 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, subsequent to March 31, 2016, our parent company in the United States received net proceeds of $109.0 million from the Notes offering. 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 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.

Credit Facility

We have a credit facility with a syndicate of lenders. Availability under the 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. Loans under the credit agreement are scheduled to mature on September 18, 2018. The initial borrowing base is $200 million and 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 May 2016. The borrowing base for the 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 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 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. 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 December 31, 2015, we were in compliance with all financial and operating covenants in our credit agreement. As of March 31, 2016, no amounts have been drawn on this facility. Under the terms of the credit facility, we are limited in our ability to pay any dividends to our shareholders without bank approval.

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.

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.

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.

Cash Flows

During the three months ended March 31, 2016, our cash and cash equivalents decreased by $94.0 million as a result of cash used in investing activities of $107.2 million (including $50.9 million and $19.4 million of cash used in investing activities in relation to the Petroamerica and PGC acquisitions, respectively), partially offset by cash provided by operating activities of

$10.8 million and cash provided by financing activities of $1.2 million. During the three months ended March 31, 2015, our cash and cash equivalents decreased by $128.4 million as a result of cash used in investing activities of $128.3 million, partially offset by cash provided by operating activities of $2.3 million and cash provided by financing activities of $0.5 million.

Cash provided by operating activities in the three months ended March 31, 2016, was primarily affected by lower oil and natural gas sales, higher transportation and G&A expenses and realized foreign exchange losses and a $0.5 million change in assets and liabilities from operating activities. These amounts were partially offset by lower operating, severance, equity tax and income tax expenses and the absence of cash settlement of financial instruments.

Cash used in investing activities in the three months ended March 31, 2016, included an increase in restricted cash of $10.8 million, capital expenditures incurred of $26.2 million plus $19.4 million of cash paid for property, plant and equipment for the PGC acquisition and net cash paid for the Petroamerica acquisition of $50.9 million, partially offset by $0.1 million of net cash inflows related to changes in assets and liabilities associated with investing activities. Cash used in investing activities in the three months ended March 31, 2015, included an increase in restricted cash of $0.5 million, capital expenditures incurred of $73.4 million, and net cash outflows related to changes in assets and liabilities associated with investing activities of $54.3 million.

Cash provided by financing activities in the three months ended March 31, 2016 and 2015, related to proceeds from issuance of shares of our Common Stock upon the exercise of stock options.

Off-Balance Sheet Arrangements

As at March 31, 2016, we had no off-balance sheet arrangements.

Contractual Obligations

As at March 31, 2016, there were no material changes to our contractual obligations outside of the ordinary course of business from those as of 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:

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

In the three months ended March 31, 2016, we recorded ceiling test impairment losses in our Colombia and Brazil cost centers of $54.6 million and $1.3 million, respectively, related to lower oil prices. 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 second 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. Subject to these factors and inherent limitations, we believe that ceiling test impairment losses in the second quarter of 2016 could exceed $11 million in Brazil and $109 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 $44.46 per bbl for the year ended June 30, 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 April 30, 2016, and, for the two months ended June 30, 2016, estimated oil prices for the second quarter of 2016 using the forward price curve forecast of our independent reserves evaluator dated April 1 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 second quarter of 2016. This disclosure is based on a pro forma Brent oil price of $44.46 per bbl for the year ended June 30, 2016, calculated as described above.

Business Environment Outlook

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 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 borrowings under our revolving credit facility, 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 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.

For over 40 years, the Colombian government has been engaged in a conflict with two main Marxist guerrilla groups: the 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 sprouted up to combat FARC and ELN, which the Colombian government successfully dissolved. We operate principally in the Putumayo Basin in Colombia. Pipelines have been primary targets because such pipelines cannot be adequately secured due to the sheer length of such pipelines and the remoteness of the areas in which the pipelines are laid. The CENIT S.A-operated Trans-Andean oil pipeline (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. In the three months ended March 31, 2016, the OTA pipeline was shutdown for approximately six days, however this was unrelated to the FARC and for operational reasons.

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

See Part II, Item 7A Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. The risks facing our company have not changed materially from those set forth in Part II, Item 7A Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

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 of March 31, 2016.

Changes in Internal Control over Financial Reporting

We acquired Petroamerica Oil Corp. and PetroGranada Colombia Limited on January 13, 2016 and January 25, 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 March 31, 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 9 in the Notes to the Condensed Consolidated Financial Statements (Unaudited) in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in our Annual Report on Form 10-K for the year ended December 31, 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. 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.

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: May 3, 2016		/s/ Gary Guidry
		By: Gary Guidry
		President and Chief Executive Officer
		(Principal Executive Officer)



Date: May 3, 2016		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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).

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).

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

4.2	Form of 5.00% Convertible Senior Notes due 2021.	Included as Exhibit A to Exhibit 4.1.

10.1	Purchase Agreement, dated as of March 31, 2016, by and between Gran Tierra Energy Inc. and Nomura Securities International, Inc., Dundee Securities Inc. and RBC Dominion Securities Inc.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

10.2	First Amendment to Credit Agreement, dated as of March 31, 2016, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

10.3	Form of Performance Stock Unit Award Agreement Under the 2007 Equity Incentive Plan	Filed herewith.

10.4	Form of Performance Stock Unit Grant Notice	Filed herewith.

10.5	Executive Employment Agreement effective May 11 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Ryan Ellson	Filed herewith.

10.6	Severance Agreement and Release dated April 6, 2016, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Duncan Nightingale.	Filed herewith.

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

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

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

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

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

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