Gran Tierra Energy - 10-Q quarterly report FY2015 Q3

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2015



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 October 30, 2015, the following number of shares of the registrant’s capital stock were outstanding: 274,499,439 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 4,957,777 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 September 30, 2015

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	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33

PART II	Other Information
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 6.	Exhibits	34
SIGNATURES		34
EXHIBIT INDEX		36

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q, particularly in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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, including without limitation statements in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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 2014 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 production and oil and gas reserves are also reported NAR, except as otherwise noted. 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 and Retained Earnings (Unaudited)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUE AND OTHER INCOME
Oil and natural gas sales (Note 4)	$	75,653		$	161,517		$	221,234		$	460,510
Interest income	266			772			1,069			2,160
	75,919			162,289			222,303			462,670
EXPENSES
Operating	33,751			33,949			89,318			81,161
Depletion, depreciation, accretion and impairment (Note 5)	204,993			53,936			360,620			140,137
General and administrative (Note 6)	7,863			13,350			25,455			40,145
Severance (Note 11)	461			—			6,827			—
Equity tax (Note 8)	—			—			3,769			—
Foreign exchange gain	(12,923		)	(12,438		)	(21,492		)	(6,604		)
Financial instruments loss (gain) (Note 10)	2,670			2,790			1,262			(2,223		)
	236,815			91,587			465,759			252,616

(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(160,896		)	70,702			(243,456		)	210,054
INCOME TAX (EXPENSE) RECOVERY
Current	(3,523		)	(24,246		)	(11,632		)	(83,183		)
Deferred	62,542			(2,272		)	69,781			(1,431		)
	59,019			(26,518		)	58,149			(84,614		)
(LOSS) INCOME FROM CONTINUING OPERATIONS	(101,877		)	44,184			(185,307		)	125,440
Loss from discontinued operations, net of income taxes (Note 3)	—			—			—			(26,990		)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)	(101,877		)	44,184			(185,307		)	98,450
RETAINED EARNINGS, BEGINNING OF PERIOD	156,192			465,227			239,622			410,961
RETAINED EARNINGS, END OF PERIOD	$	54,315		$	509,411		$	54,315		$	509,411

(LOSS) INCOME PER SHARE
BASIC
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.36	)	$	0.15		$	(0.65	)	$	0.44
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			—			—			(0.09		)
NET INCOME (LOSS)	$	(0.36	)	$	0.15		$	(0.65	)	$	0.35
DILUTED
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.36	)	$	0.15		$	(0.65	)	$	0.44
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			—			—			(0.09		)
NET INCOME (LOSS)	$	(0.36	)	$	0.15		$	(0.65	)	$	0.35
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	285,592,382			285,576,898			286,057,952			284,203,679
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	285,592,382			288,059,601			286,057,952			287,569,347

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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



	September 30,		December 31,
	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	186,978	$	331,848
Restricted cash	303		1,836
Accounts receivable	21,426		83,227
Marketable securities (Note 10)	7,016		7,586
Inventory (Note 5)	19,073		17,298
Taxes receivable	27,507		15,843
Prepaids	3,462		6,000
Deferred tax assets	583		1,552
Total Current Assets	266,348		465,190

Oil and Gas Properties
Proved	546,069		801,075
Unproved	326,717		316,856
Total Oil and Gas Properties	872,786		1,117,931
Other capital assets	9,478		11,013
Total Property, Plant and Equipment (Note 5)	882,264		1,128,944

Other Long-Term Assets
Restricted cash	3,272		2,037
Deferred tax assets	483		601
Taxes receivable	9,250		9,684
Other long-term assets	6,670		5,013
Goodwill	102,581		102,581
Total Other Long-Term Assets	122,256		119,916
Total Assets	$	1,270,868	$	1,714,050
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	25,984	$	112,401
Accrued liabilities	44,123		75,430
Foreign currency derivative (Note 10)	—		3,057
Taxes payable	750		25,412
Deferred tax liabilities	21		1,040
Asset retirement obligation (Note 7)	4,686		8,026
Total Current Liabilities	75,564		225,366

Long-Term Liabilities
Deferred tax liabilities	74,596		175,324
Asset retirement obligation (Note 7)	27,167		27,786
Other long-term liabilities	6,523		8,889
Total Long-Term Liabilities	108,286		211,999

Contingencies (Note 9)
Shareholders’ Equity
Common Stock (Note 6) (274,814,539 and 276,072,351 shares of Common Stock and 8,616,666 and 10,119,745 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2015, and December 31, 2014, respectively)	10,187		10,190
Additional paid in capital	1,022,516		1,026,873
Retained earnings	54,315		239,622
Total Shareholders’ Equity	1,087,018		1,276,685
Total Liabilities and Shareholders’ Equity	$	1,270,868	$	1,714,050

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Nine Months Ended September 30,
	2015			2014
Operating Activities
Net income (loss)	$	(185,307	)	$	98,450
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations, net of income taxes (Note 3)	—			26,990
Depletion, depreciation, accretion and impairment	360,620			140,137
Deferred tax (recovery) expense	(69,781		)	1,431
Non-cash stock-based compensation	1,511			4,341
Unrealized foreign exchange gain	(13,093		)	(6,924		)
Financial instruments loss (gain)	1,262			(2,223		)
Equity tax	—			(3,283		)
Cash settlement of foreign currency derivatives	(3,749		)	4,662
Cash settlement of asset retirement obligation (Note 7)	(4,768		)	(211		)
Net change in assets and liabilities from operating activities of continuing operations
Accounts receivable and other long-term assets	52,133			(61,224		)
Inventory	1,599			(1,688		)
Prepaids	2,538			2,565
Accounts payable and accrued and other long-term liabilities	(36,935		)	(981		)
Taxes receivable and payable	(47,483		)	(55,084		)
Net cash provided by operating activities of continuing operations	58,547			146,958
Net cash used in operating activities of discontinued operations	—			(4,792		)
Net cash provided by operating activities	58,547			142,166

Investing Activities
Decrease in restricted cash	298			877
Additions to property, plant and equipment	(116,353		)	(268,859		)
Changes in non-cash investing working capital	(75,152		)	18,225
Net cash used in investing activities of continuing operations	(191,207		)	(249,757		)
Proceeds from sale of Argentina business unit, net of cash sold and transaction costs	—			42,755
Net cash used in investing activities of discontinued operations	—			(12,384		)
Net cash used in investing activities	(191,207		)	(219,386		)

Financing Activities
Repurchase of shares of Common Stock (Note 6)	(6,616		)	—
Proceeds from issuance of shares of Common Stock (Note 6)	602			11,177
Net cash (used in) provided by financing activities	(6,014		)	11,177

Foreign exchange loss on cash and cash equivalents	(6,196		)	(2,327		)

Net decrease in cash and cash equivalents	(144,870		)	(68,370		)
Cash and cash equivalents, beginning of period	331,848			428,800
Cash and cash equivalents, end of period	$	186,978		$	360,430

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	34,023		$	72,410

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Nine Months Ended September 30,			Year Ended December 31,
	2015			2014
Share Capital
Balance, December 31, 2014	$	10,190		$	10,187
Issue of shares of Common Stock (Note 6)	—			3
Repurchase of shares of Common Stock (Note 6)	(3		)	—
Balance, September 30, 2015	10,187			10,190

Additional Paid in Capital
Balance, December 31, 2014	1,026,873			1,008,760
Exercise of stock options (Note 6)	602			11,137
Stock-based compensation (Note 6)	1,654			6,976
Repurchase of shares of Common Stock (Note 6)	(6,613		)	—
Balance, September 30, 2015	1,022,516			1,026,873

Retained Earnings
Balance, December 31, 2014	239,622			410,961
Net loss	(185,307		)	(171,339		)
Balance, September 30, 2015	54,315			239,622

Total Shareholders’ Equity	$	1,087,018		$	1,276,685

(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 oil and gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties. The Company’s principal business activities are in Colombia, 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, 2014, included in the Company’s 2014 Annual Report on Form 10-K, filed with the Securities and Exchange Commission (“SEC”) on March 2, 2015.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2014 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

Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory". The ASU provides guidance for the subsequent measurement of inventory and requires that inventory that is measured using average cost be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. 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.

Revenue from Contracts with Customers

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

3. Discontinued Operations

On June 25, 2014, the Company, through several of its indirect subsidiaries, sold its Argentina business unit to Madalena Energy Inc. ("Madalena") for aggregate consideration of $69.3 million, comprising $55.4 million in cash and $13.9 million in Madalena shares.

Accordingly, the results of the Company’s Argentina business unit are classified as “Loss from discontinued operations, net of income taxes” on the consolidated statements of operations for the nine months ended September 30, 2014. Additionally, cash flows of the Company’s Argentina business unit are presented separately in the interim unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2014, as cash provided by or used in operating and investing activities of discontinued operations.

Revenue and other income and loss from discontinued operations, net of income taxes, for the nine months ended September 30, 2014, were as follows:



(Thousands of U.S. Dollars)	Nine Months Ended September 30, 2014
Revenue and other income	$	31,985

Loss from operations of discontinued operations before income taxes	$	(6,252	)
Income tax expense	(1,458		)
Loss from operations of discontinued operations	(7,710		)

Loss on sale before income taxes	(18,235		)
Income tax expense	(1,045		)
Loss on sale	(19,280		)
Loss from discontinued operations, net of income taxes	$	(26,990	)

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. Prior to classifying the Company’s Argentina business unit as discontinued operations, Argentina was a reportable segment. The All Other category represents the Company’s corporate activities. The amounts disclosed in the tables below exclude the results of the Argentina business unit. Certain subsidiaries which were previously included in the All Other category were sold as part of the Argentina business unit, and therefore amounts disclosed in the All Other category have been reclassified to exclude amounts reported in loss from discontinued operations. The Company evaluates reportable segment performance based on income or loss from continuing operations before income taxes.

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



	Three Months Ended September 30, 2015
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	73,557		$	—		$	2,096		$	—		$	75,653
Interest income	61			—			—			205			266
Depletion, depreciation, accretion and impairment	181,981			3,208			19,396			408			204,993
Loss from continuing operations before income taxes	(130,154		)	(5,020		)	(18,540		)	(7,182		)	(160,896		)
Segment capital expenditures	18,903			3,885			1,769			12			24,569
	Three Months Ended September 30, 2014
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	153,815		$	—		$	7,702		$	—		$	161,517
Interest income	98			1			433			240			772
Depletion, depreciation, accretion and impairment	51,144			109			2,429			254			53,936
Income (loss) from continuing operations before income taxes	81,258			(3,345		)	1,746			(8,957		)	70,702
Segment capital expenditures	50,785			40,730			3,377			527			95,419
	Nine Months Ended September 30, 2015
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	215,251		$	—		$	5,983		$	—		$	221,234
Interest income	221			2			218			628			1,069
Depletion, depreciation, accretion and impairment	265,297			41,588			52,565			1,170			360,620
Loss from continuing operations before income taxes	(124,029		)	(48,723		)	(53,632		)	(17,072		)	(243,456		)
Segment capital expenditures	48,357			48,775			18,174			1,047			116,353
	Nine Months Ended September 30, 2014
(Thousands of U.S. Dollars)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	438,100		$	—		$	22,410		$	—		$	460,510
Interest income	419			1			1,292			448			2,160
Depletion, depreciation, accretion and impairment	131,742			420			7,249			726			140,137
Income (loss) from continuing operations before income taxes	229,750			(7,811		)	7,446			(19,331		)	210,054
Segment capital expenditures	147,016			103,535			17,176			1,132			268,859



	As at September 30, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	669,083	$	94,460	$	114,207	$	4,514	$	882,264
Goodwill	102,581		—		—		—		102,581
All other assets	133,776		21,822		11,255		119,170		286,023
Total Assets	$	905,440	$	116,282	$	125,462	$	123,684	$	1,270,868

	As at December 31, 2014
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	888,822	$	87,028	$	148,457	$	4,637	$	1,128,944
Goodwill	102,581		—		—		—		102,581
All other assets	157,549		40,613		14,724		269,639		482,525
Total Assets	$	1,148,952	$	127,641	$	163,181	$	274,276	$	1,714,050

5. Property, Plant and Equipment and Inventory

Property, Plant and Equipment



(Thousands of U.S. Dollars)	As at September 30, 2015			As at December 31, 2014
Oil and natural gas properties
Proved	$	1,940,596		$	1,876,371
Unproved	326,717			316,856
	2,267,313			2,193,227
Other	28,317			27,287
	2,295,630			2,220,514
Accumulated depletion, depreciation and impairment	(1,413,366		)	(1,091,570		)
	$	882,264		$	1,128,944

In the three and nine months ended September 30, 2015, the Company recorded ceiling test impairment losses of $129.4 million in its Colombia cost center, and $17.6 million and $46.9 million, respectively, in its Brazil cost center, related to lower oil prices. The Company follows the full cost method of accounting for its oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of the Company's reserves.

In the three and nine months ended September 30, 2015, the Company recorded impairment losses in its Peru cost center of $3.0 million and $41.0 million, respectively, related to costs incurred on Block 95.

Inventory

At September 30, 2015, oil and supplies inventories were $17.4 million and $1.7 million, respectively (December 31, 2014 - $15.2 million and $2.1 million, respectively). At September 30, 2015, the Company had 429 Mbbl of oil inventory (December 31, 2014 - 330 Mbbl).

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, 2014	276,072,351		5,595,118		4,524,627
Options exercised	240,000		—		—
Shares repurchased and canceled	(3,000,796	)	—		—
Exchange of exchangeable shares	1,502,995		(617,257	)	(885,738	)
Shares canceled	(11	)	(84	)	—
Balance, September 30, 2015	274,814,539		4,977,777		3,638,889

On July 22, 2015, the Company announced that it intended to implement a new share repurchase program (the “2015 Program”) through the facilities of the Toronto Stock Exchange ("TSX"), the NYSE MKT and eligible alternative trading

platforms in Canada and the United States. The Company received regulatory approval from the TSX to commence the 2015 Program on July 27, 2015. The Company is able to purchase at prevailing market prices up to 13,831,866 shares of Common Stock, representing 4.98% of the issued and outstanding shares of Common Stock as of July 21, 2015. Shares purchased pursuant to the 2015 Program will be canceled. The 2015 Program will expire on July 29, 2016, or earlier if the 4.98% share maximum is reached. The 2015 Program may be terminated by the Company at any time, subject to compliance with regulatory requirements. As such, there can be no assurance regarding the total number of shares that may be repurchased under the 2015 Program.

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 September 30,			Nine Months Ended September 30,
	2015	2014		2015	2014
Weighted average number of common and exchangeable shares outstanding	285,592,382	285,576,898		286,057,952	284,203,679
Weighted average shares issuable pursuant to stock options	—	8,117,355		—	9,399,930
Weighted average shares assumed to be purchased from proceeds of stock options	—	(5,634,652	)	—	(6,034,262	)
Weighted average number of diluted common and exchangeable shares outstanding	285,592,382	288,059,601		286,057,952	287,569,347

For the three and nine months ended September 30, 2015, 13,051,834 and 13,659,367 options, respectively, on a weighted average basis, (three and nine months ended September 30, 2014 - 6,884,227 and 6,925,117 options, respectively) were excluded from the diluted income per share calculation as the options were anti-dilutive.

Restricted Stock Units and Stock Options

The Company grants time-vested restricted stock units ("RSUs") to certain officers, employees and consultants. Additionally, the Company grants options to purchase shares of Common Stock to certain directors, officers, employees and consultants. The following table provides information about RSU and stock option activity for the nine months ended September 30, 2015:



	RSUs		Options
	Number of Outstanding Share Units		Number of Outstanding Options		Weighted Average Exercise Price $/Option
Balance, December 31, 2014	1,236,963		13,790,220		5.93
Granted	1,041,450		5,076,260		3.11
Exercised	(519,111	)	(240,000	)	2.51
Forfeited	(708,242	)	(1,344,961	)	(5.66	)
Expired	—		(4,323,143	)	(6.85	)
Balance, September 30, 2015	1,051,060		12,958,376		4.61

For the nine months ended September 30, 2015, 240,000 shares of Common Stock were issued for cash proceeds of $0.6 million upon the exercise of stock options (nine months ended September 30, 2014 - $11.2 million).

The weighted average grant date fair value for options granted in the three months ended September 30, 2015, was $0.95 (three months ended September 30, 2014 - $2.21) and for the nine months ended September 30, 2015, was $1.26 (nine months ended September 30, 2014 - $2.50).

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



	Three Months Ended September 30,					Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2015		2014			2015			2014
Compensation costs for stock options	$	967	$	1,961		$	1,654		$	5,824
Compensation costs for RSUs	46		326			583			3,967
	1,013		2,287			2,237			9,791
Less: Stock-based compensation costs capitalized	—		(278		)	(111		)	(2,100		)
Stock-based compensation expense	$	1,013	$	2,009		$	2,126		$	7,691

Stock-based compensation expense for the three and nine months ended September 30, 2015, and the three months ended September 30, 2014, was primarily recorded in general and administrative ("G&A") expenses. Of the total stock-based compensation expense for the nine months ended September 30, 2014, $6.1 million was recorded in G&A expenses, $0.3 million was recorded in operating expenses and $1.3 million was recorded in loss from discontinued operations.

At September 30, 2015, there was $5.3 million (December 31, 2014 - $4.8 million) of unrecognized compensation cost related to unvested stock options and RSUs which is expected to be recognized over a weighted average period of 1.5 years.

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:



	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 30, 2015			December 31, 2014
Balance, December 31, 2014	$	35,812		$	21,973
Settlements	(6,368		)	(1,137		)
Liability incurred	1,030			11,956
Liabilities associated with the Argentina business unit sold (Note 3)	—			(10,170		)
Foreign exchange	—			(53		)
Accretion	960			1,406
Revisions in estimated liability	419			11,837
Balance, September 30, 2015	$	31,853		$	35,812

Asset retirement obligation - current	$	4,686		$	8,026
Asset retirement obligation - long-term	27,167			27,786
	$	31,853		$	35,812

For the nine months ended September 30, 2015, settlements included cash payments of $4.8 million with the balance in accounts payable and accrued liabilities at September 30, 2015. Revisions to estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling the asset retirement obligation. At September 30, 2015, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $2.8 million (December 31, 2014 - $2.0 million). These assets are included in restricted cash on the Company's interim unaudited condensed consolidated balance sheets.

8. Taxes

The Company's effective tax rate was 24% in the nine months ended September 30, 2015, compared with 40% in the comparable period in 2014. 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 2015 impairment losses in Brazil and Peru and an increase in the tax rate in Canada, as well as non-deductible third party royalty in Colombia and other local taxes. These were partially offset by the impact of foreign taxes and other permanent differences.

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 amount of $3.8 million for the equity tax expense in the consolidated statement of operations during the three months ended March 31, 2015, and a corresponding payable on the consolidated balance sheet at March 31, 2015. This amount was paid in May and September 2015 and at September 30, 2015, accounts payable included $nil (December 31, 2014 - $nil).

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. 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 $23.6 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 September 30, 2015, based on an interest rate of three-month LIBOR plus 4% related interest would be $5.7 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 $43.6 million as at September 30, 2015. 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.

Gran Tierra Energy Colombia, Ltd. and Petrolifera Petroleum (Colombia) Ltd (collectively “GTEC”) and Ecopetrol, the contracting parties of the Guayuyaco Association Contract, are engaged in a dispute regarding the interpretation of the

procedure for allocation of oil produced and sold during the long-term test of the Guayuyaco-1 and Guayuyaco-2 wells, prior to GTEC's purchase of the companies originally involved in the dispute. There was no agreement between the parties, and Ecopetrol filed a lawsuit in the Contravention Administrative Tribunal in the District of Cauca (the "Tribunal") regarding this matter. During 2013, the Tribunal ruled in favor of Ecopetrol and awarded Ecopetrol 44,025 bbl of oil. GTEC has filed an appeal of the ruling to the Supreme Administrative Court (Consejo de Estado) in a second instance procedure. At September 30, 2015, and December 31, 2014, Gran Tierra had accrued $2.4 million in the interim unaudited condensed consolidated financial statements in relation to this dispute.

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

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

Letters of credit

At September 30, 2015, the Company had provided promissory notes totaling $75.7 million (December 31, 2014 - $86.3 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 September 30, 2015, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, trading securities, accounts payable, accrued liabilities and contingent consideration included in other long-term liabilities.

Fair Value Measurement

The fair value of trading securities and contingent consideration are being remeasured at the estimated fair value at the end of each reporting period.

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

The fair value of the contingent consideration, which relates to the acquisition of the remaining 30% working interest in certain properties in Brazil, was 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 was determined in accordance with accepted valuation methods.

The fair value of foreign currency derivatives was based on the estimated maturity value of foreign exchange non-deliverable forward contracts using applicable forward exchange rates. The most significant variable to the cash flow calculations is the estimation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are the net value of the contract.

The fair value of the trading securities, foreign currency derivative liability and contingent consideration at September 30, 2015, and December 31, 2014, were as follows:



	As at
(Thousands of U.S. Dollars)	September 30, 2015		December 31, 2014
Trading securities	$	7,016	$	7,586

Foreign currency derivative liability	$	—	$	3,057
Contingent consideration liability	1,061		1,061
	$	1,061	$	4,118

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2015		2014		2015		2014
Trading securities loss	$	2,670	$	2,540	$	570	$	2,201
Foreign currency derivatives loss (gain)	—		250		692		(4,424		)
	$	2,670	$	2,790	$	1,262	$	(2,223	)

These gains and losses are presented as financial instruments gains or losses in the interim unaudited condensed consolidated statements of operations and cash flows. There were no sales of trading securities in the nine months ended September 30, 2015, and the trading securities loss represents an unrealized loss.

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 September 30, 2015, and December 31, 2014, the fair value of the trading securities acquired in connection with the disposal of the Argentina business unit was determined using Level 1 inputs. At December 31, 2014, the fair value of the foreign currency derivative was determined using Level 2 inputs. At September 30, 2015, and December 31, 2014, the fair value of the contingent consideration payable in connection with the Brazil acquisition 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.

Foreign Exchange Rate Risk

Unrealized foreign exchange gains and losses primarily result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, which are monetary liabilities mainly denominated in the local currency of the Colombian operations. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $24,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

From time to time, the Company purchases non-deliverable forward contracts for purposes of fixing exchange rates at which it will purchase or sell Colombian pesos to settle its income tax installment payments. At September 30, 2015, the Company did not have any open foreign currency derivative positions. With the exception of these foreign currency derivatives, any foreign currency transactions are conducted on a spot basis with major financial institutions in the Company’s operating areas.

For the nine months ended September 30, 2015, 97% (nine months ended September 30, 2014 - 95%) of the Company's revenue and other income was generated in Colombia. In Colombia, the Company receives 100% of its revenues in U.S. dollars and the majority of its capital expenditures are in U.S. dollars or are based on U.S. dollar prices. In Brazil, prices for oil are in U.S. dollars, but revenues are received in local currency translated according to current exchange rates. The majority of the Company's capital expenditures within Brazil are based on U.S. dollar prices, but are paid in local currency translated according to current exchange rates. In Peru, capital expenditures are based on U.S. dollar prices and may be paid in local currency or U.S. dollars.

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and accounts receivables. The carrying value of cash and accounts receivable reflects management’s assessment of credit risk.

At September 30, 2015, cash and cash equivalents and restricted cash included balances in savings and checking accounts, as well as term deposits and certificates of deposit, placed with financial institutions with strong investment grade ratings or governments, or the equivalent in the Company’s operating areas.

11. Severance Costs

In March 2015, the Company significantly reduced the number of its full-time employees. Staff reductions as part of this cost cutting measure were substantially completed at March 31, 2015. Additional employee terminations occurred during the three months ended June 30, 2015, and the three months ended September 30, 2015. Employee termination benefits were recorded as incurred based on existing employee contracts, statutory requirements, completed negotiations and company policy.

Severance costs for the Company’s reportable segments and other activities for the three and nine months ended September 30, 2015, were as follows:



	Three Months Ended September 30, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Severance expenses	$	—	$	439	$	—	$	22	$	461
	Nine Months Ended September 30, 2015
	Colombia		Peru		Brazil		All Other		Total
Severance expenses	$	1,237	$	1,863	$	109	$	3,618	$	6,827

The amounts in the table for the nine months ended September 30, 2015, represent cumulative costs incurred to date and exclude the impact of the reversal of stock-based compensation expense for unvested options of terminated employees which was recorded in G&A expenses. Changes in the severance cost related liability were as follows:



(Thousands of U.S. Dollars)	Nine Months Ended September 30, 2015
Balance, December 31, 2014	$	—
Liability incurred	6,827
Settlements	(6,827		)
Balance, September 30, 2015	$	—

12. Credit Facility

At September 30, 2015, the Company had 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 will 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 borrowing base for the credit facility is supported by the present value of the petroleum reserves of two of the Company's 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 the Company's 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, the Company is required to maintain and was in compliance with certain financial and operating covenants. No amounts have been drawn on this facility. This credit facility was entered into and became effective on September 18, 2015, and replaced the Company's previous credit facility which was canceled on this date.

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

This Quarterly Report on Form 10-Q, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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 2014 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 U.S. Securities and Exchange Commission (“SEC”) on March 2, 2015.

Highlights



	Three Months Ended September 30,								Nine Months Ended September 30,
	2015			2014⁽²⁾			% Change		2015			2014⁽²⁾			% Change
Volumes (BOE)
Working Interest Production Before Royalties	2,149,907			2,331,276			(8	)	6,412,737			6,993,072			(8	)
Royalties	(348,270		)	(555,967		)	(37	)	(1,115,555		)	(1,698,253		)	(34	)
Production NAR	1,801,637			1,775,309			1		5,297,182			5,294,819			—
Change in Inventory	187,908			123,663			52		(199,514		)	(113,383		)	76
Sales⁽¹⁾	1,989,545			1,898,972			5		5,097,668			5,181,436			(2	)

Average Daily Volumes (BOEPD)
Working Interest Production Before Royalties	23,368			25,340			(8	)	23,490			25,615			(8	)
Royalties	(3,785		)	(6,043		)	(37	)	(4,086		)	(6,220		)	(34	)
Production NAR	19,583			19,297			1		19,404			19,395			—
Change in Inventory	2,043			1,344			52		(731		)	(415		)	76
Sales⁽¹⁾	21,626			20,641			5		18,673			18,980			(2	)

Oil and Gas Sales ($000s)	$	75,653		$	161,517		(53	)	$	221,234		$	460,510		(52	)
Operating Expenses ($000s)	(33,751		)	(33,949		)	(1	)	(89,318		)	(81,161		)	10
Operating Netback ($000s)⁽³⁾	$	41,902		$	127,568		(67	)	$	131,916		$	379,349		(65	)

General and Administrative Expenses ("G&A")
G&A Expenses Before Stock-Based Compensation, Gross	$	14,544		$	24,500		(41	)	$	52,095		$	72,503		(28	)
Stock-Based Compensation	997			1,962			(49	)	2,007			6,061			(67	)
Capitalized G&A and Overhead Recoveries	(7,678		)	(13,112		)	(41	)	(28,647		)	(38,419		)	(25	)
	$	7,863		$	13,350		(41	)	$	25,455		$	40,145		(37	)

EBITDA⁽⁴⁾	$	44,097		$	124,638		(65	)	$	117,164		$	350,191		(67	)

Net Income (Loss)	$	(101,877	)	$	44,184		(331	)	$	(185,307	)	$	98,450		(288	)

Funds Flow from Continuing Operations ($000s)⁽⁵⁾	$	36,644		$	93,569		(61	)	$	91,463		$	263,581		(65	)

Capital Expenditures for Continuing Operations ($000s)	$	24,569		$	95,419		(74	)	$	116,353		$	268,859		(57	)



	As at
	September 30, 2015		December 31, 2014		% Change
Cash & Cash Equivalents ($000s)	$	186,978	$	331,848	(44	)

Working Capital (Including Cash & Cash Equivalents) ($000s)	$	190,784	$	239,824	(20	)

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

(2) Excludes amounts relating to discontinued operations. Sales volumes associated with discontinued operations were nil BOEPD for the three and nine months ended September 30, 2015, and nil and 1,819 BOEPD, respectively, for the corresponding periods in 2014. Discontinued operations sales volumes for the nine months ended September 30, 2014, were calculated to the date of sale of June 25, 2014.

Non-GAAP measures

Operating netback, EBITDA and funds flow from continuing 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 income or 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.

(3) Operating netback as presented is oil and gas sales net of royalties and operating 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.

(4) EBITDA, as presented, is net income or loss adjusted for loss from discontinued operations, net of income taxes, depletion, depreciation, accretion and impairment (“DD&A”) expenses and income tax recovery or expense. 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 income or loss to EBITDA is as follows:



	Three Months Ended September 30,					Nine Months Ended September 30,
EBITDA - Non-GAAP Measure ($000s)	2015			2014		2015			2014
Net income (loss)	$	(101,877	)	$	44,184	$	(185,307	)	$	98,450
Adjustments to reconcile net income (loss) to EBITDA
Loss from discontinued operations, net of income taxes	—			—		—			26,990
DD&A expenses	204,993			53,936		360,620			140,137
Income tax (recovery) expense	(59,019		)	26,518		(58,149		)	84,614
EBITDA	$	44,097		$	124,638	$	117,164		$	350,191

(5) Funds flow from continuing operations, as presented, is net income or loss adjusted for loss from discontinued operations, net of income taxes, DD&A expenses, deferred tax recovery or expense, non-cash stock-based compensation, unrealized foreign exchange gains and losses, financial instruments gains and losses, equity tax and cash settlement of foreign currency derivatives. During the three months ended September 30, 2015, our new management changed our method of calculating funds flow from continuing operations to be more consistent with our peers. Funds flow from continuing 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 income or loss to funds flow from continuing operations is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
Funds Flow From Continuing Operations - Non-GAAP Measure ($000s)	2015			2014			2015			2014
Net income (loss)	$	(101,877	)	$	44,184		$	(185,307	)	$	98,450
Adjustments to reconcile net income (loss) to funds flow from continuing operations
Loss from discontinued operations, net of income taxes	—			—			—			26,990
DD&A expenses	204,993			53,936			360,620			140,137
Deferred tax (recovery) expense	(62,542		)	2,272			(69,781		)	1,431
Non-cash stock-based compensation	929			1,717			1,511			4,341
Unrealized foreign exchange (gain) loss	(7,529		)	(9,689		)	(13,093		)	(6,924		)
Financial instruments loss (gain)	2,670			2,790			1,262			(2,223		)
Equity tax	—			(1,641		)	—			(3,283		)
Cash settlement of foreign currency derivatives	—			—			(3,749		)	4,662
Funds flow from continuing operations	$	36,644		$	93,569		$	91,463		$	263,581

Consolidated Results of Operations



	Three Months Ended September 30,								Nine Months Ended September 30,
	2015			2014⁽²⁾			% Change		2015			2014⁽²⁾			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	75,653		$	161,517		(53	)	$	221,234		$	460,510		(52	)
Interest income	266			772			(66	)	1,069			2,160			(51	)
	75,919			162,289			(53	)	222,303			462,670			(52	)

Operating expenses	33,751			33,949			(1	)	89,318			81,161			10
DD&A expenses	204,993			53,936			280		360,620			140,137			157
G&A expenses	7,863			13,350			(41	)	25,455			40,145			(37	)
Severance expenses	461			—			—		6,827			—			—
Equity tax	—			—			—		3,769			—			—
Foreign exchange gain	(12,923		)	(12,438		)	(4	)	(21,492		)	(6,604		)	(225	)
Financial instruments loss (gain)	2,670			2,790			(4	)	1,262			(2,223		)	157
	236,815			91,587			159		465,759			252,616			84

(Loss) income from continuing operations before income taxes	(160,896		)	70,702			(328	)	(243,456		)	210,054			(216	)

Current income tax expense	(3,523		)	(24,246		)	(85	)	(11,632		)	(83,183		)	(86	)
Deferred income tax recovery (expense)	62,542			(2,272		)	—		69,781			(1,431		)	—
	59,019			(26,518		)	(323	)	58,149			(84,614		)	(169	)
(Loss) income from continuing operations	(101,877		)	44,184			(331	)	(185,307		)	125,440			(248	)
Loss from discontinued operations, net of income taxes	—			—			—		—			(26,990		)	100
Net income (loss)	$	(101,877	)	$	44,184		(331	)	$	(185,307	)	$	98,450		(288	)

Sales Volumes⁽¹⁾

Oil and NGL's, bbl	1,974,945			1,888,626			5		5,058,970			5,138,675			(2	)
Natural gas, Mcf	87,600			62,077			41		232,187			256,567			(10	)
Total sales volumes, BOE	1,989,545			1,898,972			5		5,097,668			5,181,436			(2	)

Total sales volumes, BOEPD	21,626			20,641			5		18,673			18,980			(2	)

Average Prices

Oil and NGL's per bbl	$	38.14		$	85.40		(55	)	$	43.56		$	89.41		(51	)
Natural gas per Mcf	$	3.77		$	4.51		(16	)	$	3.80		$	4.72		(19	)

Consolidated Results of Operations per BOE sales volumes

Oil and natural gas sales	$	38.03		$	85.05		(55	)	$	43.40		$	88.88		(51	)
Interest income	0.13			0.41			(68	)	0.21			0.42			(50	)
	38.16			85.46			(55	)	43.61			89.30			(51	)

Operating expenses	16.96			17.88			(5	)	17.52			15.66			12



DD&A expenses	103.04			28.40			263		70.74			27.05			162
G&A expenses	3.95			7.03			(44	)	4.99			7.75			(36	)
Severance expenses	0.23			—			—		1.34			—			—
Equity tax	—			—			—		0.74			—			—
Foreign exchange gain	(6.50		)	(6.55		)	1		(4.22		)	(1.27		)	(232	)
Financial instruments loss (gain)	1.34			1.47			(9	)	0.25			(0.43		)	158
	119.02			48.23			147		91.36			48.76			87

(Loss) income from continuing operations before income taxes	(80.86		)	37.23			(317	)	(47.75		)	40.54			(218	)
Current income tax expense	(1.77		)	(12.76		)	(86	)	(2.28		)	(16.05		)	(86	)
Deferred income tax recovery (expense)	31.44			(1.20		)	—		13.69			(0.28		)	—
	29.67			(13.96		)	(313	)	11.41			(16.33		)	(170	)
(Loss) income from continuing operations	$	(51.19	)	$	23.27		(320	)	$	(36.34	)	$	24.21		(250	)

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

⁽²⁾ Excludes amounts relating to discontinued operations. Sales volumes associated with discontinued operations were nil BOEPD for the three and nine months ended September 30, 2015, and nil and 1,819 BOEPD, respectively, for the corresponding periods in 2014. Discontinued operations sales volumes for the nine months ended September 30, 2014, were calculated to the date of sale of June 25, 2014.

Oil and gas production and sales volumes, BOEPD



	Three Months Ended September 30, 2015						Three Months Ended September 30, 2014
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	22,608		760		23,368		24,187		1,153		25,340
Royalties	(3,686	)	(99	)	(3,785	)	(5,889	)	(154	)	(6,043	)
Production NAR	18,922		661		19,583		18,298		999		19,297
Change in Inventory	2,055		(12	)	2,043		1,339		5		1,344
Sales	20,977		649		21,626		19,637		1,004		20,641
	Nine Months Ended September 30, 2015						Nine Months Ended September 30, 2014
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	22,833		657		23,490		24,554		1,061		25,615
Royalties	(3,998	)	(88	)	(4,086	)	(6,076	)	(144	)	(6,220	)
Production NAR	18,835		569		19,404		18,478		917		19,395
Change in Inventory	(730	)	(1	)	(731	)	(406	)	(9	)	(415	)
Sales	18,105		568		18,673		18,072		908		18,980

Oil and gas production NAR for the three months ended September 30, 2015, increased by 1% to 19,583 BOEPD compared with 19,297 BOEPD in the corresponding period in 2014. In the nine months ended September 30, 2015, oil and gas production NAR of 19,404 BOEPD was consistent with the corresponding period in 2014. Production during the three and nine months ended September 30, 2015, reflected approximately 92 and 129 days, respectively, of oil delivery restrictions in Colombia compared with 63 and 155 days, respectively, in the corresponding periods in 2014.

In the three months ended September 30, 2015, production from new wells in the Moqueta Field and increased production from the Jilguero Field as a result of the unitization of that field plus new wells coming onstream was offset by the impact of normal field production declines on the Costayaco Field. Additionally, during the three months ended September 30, 2015, our production in Brazil was 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 operator of the facility has advised that it expects to have this tank repaired and operational by mid-November 2015.

Our operations on the Tiê Field in Brazil 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 and nine months ended September 30, 2015, increased by 5% to 21,626 BOEPD, and decreased by 2% to 18,673 BOEPD, respectively, compared with 20,641 BOEPD and 18,980 BOEPD, respectively, in the corresponding periods in 2014.

During the three months ended September 30, 2015, oil inventory decreases accounted for 0.2 MMbbl or 2,043 bopd of increased sales volumes compared with oil inventory decreases which accounted for 0.1 MMbbl or 1,344 bopd of increased sales volumes in the corresponding period in 2014. We had high oil inventory at the start of the third quarter 2015 as a result of Trans-Andean Oil Pipeline ("OTA pipeline”) disruptions, but this inventory was sold in July 2015. During the nine months ended September 30, 2015, oil inventory increases accounted for 0.2 MMbbl or 731 bopd of reduced sales volumes compared with oil inventory increases which accounted for 0.1 MMbbl or 415 bopd of reduced sales volumes in the corresponding period in 2014.

Operating netbacks



	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
(Thousands of U.S. Dollars)	Colombia			Brazil			Total			Colombia			Brazil			Total
Oil and Gas Sales	$	73,557		$	2,096		$	75,653		$	153,815		$	7,702		$	161,517
Operating Expenses	(32,597		)	(1,154		)	(33,751		)	(32,261		)	(1,688		)	(33,949		)
Operating Netback⁽¹⁾	$	40,960		$	942		$	41,902		$	121,554		$	6,014		$	127,568

U.S. Dollars Per BOE
Brent							$	50.23								$	101.82

WTI							$	46.44								$	97.17

Oil and Gas Sales	$	38.12		$	35.12		$	38.03		$	85.14		$	83.39		$	85.05
Operating Expenses	(16.89		)	(19.34		)	(16.96		)	(17.86		)	(18.28		)	(17.88		)
Operating Netback⁽¹⁾	$	21.23		$	15.78		$	21.07		$	67.28		$	65.11		$	67.17

	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
(Thousands of U.S. Dollars)	Colombia			Brazil			Total			Colombia			Brazil			Total
Oil and Gas Sales	$	215,251		$	5,983		$	221,234		$	438,100		$	22,410		$	460,510
Operating Expenses	(83,840		)	(5,478		)	(89,318		)	(75,747		)	(5,414		)	(81,161		)
Operating Netback⁽¹⁾	$	131,411		$	505		$	131,916		$	362,353		$	16,996		$	379,349

U.S. Dollars Per BOE

Brent							$	55.28								$	106.56

WTI							$	50.98								$	99.61

Oil and Gas Sales	$	43.55		$	38.60		$	43.40		$	88.80		$	90.40		$	88.88
Operating Expenses	(16.96		)	(35.34		)	(17.52		)	(15.35		)	(21.84		)	(15.66		)
Operating Netback⁽¹⁾	$	26.59		$	3.26		$	25.88		$	73.45		$	68.56		$	73.22

(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 and nine months ended September 30, 2015, decreased by 53% to $75.7 million and by 52% to $221.2 million, respectively, from $161.5 million and $460.5 million, respectively, in the comparable periods in 2014 primarily due to the effect of decreased realized oil prices.

Average realized prices decreased by 55% to $38.03 per BOE for the three months ended September 30, 2015, from $85.05 per BOE in the comparable period in 2014, and decreased by 51% to $43.40 per BOE for the nine months ended September 30, 2015, from $88.88 per BOE in the comparable period in 2014. These price decreases were primarily due to lower benchmark oil prices. Average Brent oil prices for the three and nine months ended September 30, 2015, were $50.23 and $55.28 per bbl, respectively, compared with $101.82 and $106.56 per bbl, respectively, in the corresponding periods in 2014. Average WTI oil prices for the three and nine months ended September 30, 2015, were $46.44 and $50.98 per bbl, respectively, compared with $97.17 and $99.61 per bbl, respectively, in the corresponding periods in 2014.

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 and nine months ended September 30, 2015, 100% and 52%, respectively, of our oil volumes sold in Colombia, were through alternative transportation routes compared with 69% and 61%, respectively, in the corresponding periods in 2014. The effect on the Colombian realized price for the three and nine months ended September 30, 2015, was a decrease of approximately $5.90 and $3.32 per BOE, respectively, as compared with delivering all of our oil through the OTA pipeline. This compares with a reduction of approximately $4.19 and $7.53 per BOE, respectively, in the comparable periods in 2014.

Oil and gas sales for the three months ended September 30, 2015, increased by 9% to $75.7 million from $69.4 million compared with the prior quarter primarily due to higher sales volumes, partially offset by decreased realized prices. Average realized prices decreased by 25% to $38.03 per BOE for the three months ended September 30, 2015, compared with $50.91 per BOE in the prior quarter, primarily due to lower benchmark oil prices. During the prior quarter, 25% of our oil volumes sold in Colombia, were through alternative transportation routes compared with 100% in the current quarter. The effect on the Colombian realized price a decrease of approximately $0.37 per BOE in the prior quarter compared with a decrease of approximately $5.90 per BOE in the current quarter.

Operating expenses decreased by 5% to $16.96 per BOE from $17.88 per BOE in the comparable period in 2014. The decrease was primarily due to a $2.09 per BOE reduction in variable operating costs as a result of Colombian cost saving measures and the effect of the strengthening of the U.S. dollar against local currencies in South America which resulted in savings for costs denominated in local currency. Additionally, workover expenses decreased by $0.49 per BOE. This was partially offset by higher transportation costs in Colombia of $1.71 per BOE due to using alternative transportation routes with the OTA pipeline being out of commission for repairs. These alternative transportation routes carry higher transportation costs instead of the realized price reductions that we incur with some alternative customers. Operating expenses decreased by 1% to $33.8 million for the three months ended September 30, 2015, compared with the corresponding period in 2014. The decrease was due to the effect of decreased operating costs per BOE partially offset by higher sales volumes.

On a per BOE basis, operating expenses increased by 12% to $17.52 per BOE for the nine months ended September 30, 2015, from $15.66 per BOE in the comparable period in 2014. The increase was primarily due to higher transportation costs in Colombia of $2.21 per BOE and higher workover expenses of $0.89 per BOE, partially offset by Colombian operating cost savings and the effect of the strengthening of the U.S. dollar against local currencies in South America. For the nine months ended September 30, 2015, operating expenses increased by 10% to $89.3 million compared with the corresponding period in 2014. The increase was due to increased operating costs per BOE, partially offset by lower sales volumes.

In Brazil, in the nine months ended September 30, 2015, we incurred $1.7 million, or $10.73 per bbl based on volumes sold in Brazil, of one-time penalties relating 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.

On a per BOE basis, operating expenses decreased by 4% to $16.96 per BOE for the three months ended September 30, 2015, from $17.72 per BOE in the prior quarter. As noted above, in the prior quarter, we incurred $1.7 million ($1.22 per BOE based on consolidated volumes sold) of penalties in Brazil. Operating expenses increased by 40% to $33.8 million in the three months ended September 30, 2015, compared with $24.1 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 September 30, 2015				Three Months Ended September 30, 2014
	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	$	181,981	$	94.30	$	51,144	$	28.31
Brazil	19,396		325.01		2,429		26.30
Peru	3,208		—		109		—
Corporate	408		—		254		—
	$	204,993	$	103.04	$	53,936	$	28.40

	Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
	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	$	265,297	$	53.67	$	131,742	$	26.70
Brazil	52,565		339.11		7,249		29.24
Peru	41,588		—		420		—
Corporate	1,170		—		726		—
	$	360,620	$	70.74	$	140,137	$	27.05

DD&A expenses for the three and nine months ended September 30, 2015, increased to $205.0 million ($103.04 per BOE) and $360.6 million ($70.74 per BOE), respectively, from $53.9 million ($28.40 per BOE) and $140.1 million ($27.05 per BOE), respectively, in the comparable periods in 2014.

DD&A expenses for the three and nine months ended September 30, 2015, included $129.4 million of ceiling test impairment losses in our Colombia cost center, and $17.6 million and $46.9 million, respectively, in our Brazil cost center, due to lower oil prices. DD&A expenses for the three and nine months ended September 30, 2015, also included $3.0 million and $41.0 million, respectively, of impairment charges in our Peru cost center relating to costs incurred on Block 95. 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 $63.41 per bbl for the purposes of the September 30, 2015, ceiling test calculations.

G&A expenses



	Three Months Ended September 30,								Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2015			2014			% Change		2015			2014			% Change
G&A Expenses Before Stock-Based Compensation, Gross	$	14,544		$	24,500		(41	)	$	52,095		$	72,503		(28	)
Stock-Based Compensation	997			1,962			(49	)	2,007			6,061			(67	)
Capitalized G&A and Overhead Recoveries	(7,678		)	(13,112		)	(41	)	(28,647		)	(38,419		)	(25	)
	$	7,863		$	13,350		(41	)	$	25,455		$	40,145		(37	)
U.S. Dollars Per BOE
G&A Expenses Before Stock-Based Compensation, Gross	$	7.31		$	12.90		(43	)	$	10.22		$	13.99		(27	)
Stock-Based Compensation	0.50			1.03			(51	)	0.39			1.17			(67	)
Capitalized G&A and Overhead Recoveries	(3.86		)	(6.90		)	(44	)	(5.62		)	(7.41		)	(24	)
	$	3.95		$	7.03		(44	)	$	4.99		$	7.75		(36	)

G&A expenses for the three and nine months ended September 30, 2015, decreased by 41% to $7.9 million and by 37% to $25.5 million, respectively, from $13.4 million and $40.1 million, respectively, in the corresponding periods in 2014. These decreases were mainly due to reductions in the number of our employees as part of our cost saving measures, a focus on reductions 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. Additionally, G&A expenses in the nine months ended September 30, 2015, were net of a credit of $2.1 million relating to the reversal of stock-based compensation expense for unvested options and RSUs associated with terminated employees. These G&A expense reductions were partially offset by lower allocations to capital projects due to lower capital activity and deferred financing fees expensed as a result of the cancellation of our previous credit facility. G&A expenses per BOE in the three and nine months ended September 30, 2015, of $3.95 and $4.99, respectively, were 44% and 36%, respectively, lower compared with the corresponding periods in 2014 for the same reasons.

G&A expenses for the three months ended September 30, 2015, decreased by 24% to $7.9 million ($3.95 per BOE) compared with $10.3 million ($7.56 per BOE) in the prior quarter. The decrease was primarily due to further cost savings measures combined with strengthening of the U.S. dollar against local currencies in South America and Canada, partially offset by lower allocations to capital projects in Peru as a result of lower capital activity and deferred financing fees expensed as a result of the cancellation of our previous credit facility.

Severance expenses

For the three and nine months ended September 30, 2015, severance expenses were $0.5 million and $6.8 million, respectively, compared with $nil in the corresponding periods in 2014. In March 2015, we reduced the number of our employees and additional employee terminations occurred during the three months ended June 30, 2015, and the three months ended September 30, 2015, consistent with our new focused strategy.

Equity tax expense

For the nine months ended September 30, 2015, equity tax expense of $3.8 million 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 2015 annual amount of the equity tax payable on our interim unaudited condensed consolidated balance sheet at March 31, 2015, and a corresponding expense in our interim unaudited condensed consolidated statement of operations during the three months ended March 31, 2015.

Foreign exchange gains and losses

For the three and nine months ended September 30, 2015, we had foreign exchange gains of $12.9 million and $21.5 million, respectively, compared with foreign exchange gains of $12.4 million and $6.6 million, respectively, in the three and nine

months ended September 30, 2014. 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. The following table presents the change in the Colombian peso against the U.S. dollar for the three and nine months ended September 30, 2015, and the comparable periods in 2014:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Change in the Colombian peso against the U.S. dollar	weakened by	weakened by	weakened by	weakened by
Change in the Colombian peso against the U.S. dollar	21%	8%	31%	5%

Financial instrument gains and losses



	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2015		2014		2015		2014
Trading securities loss	$	2,670	$	2,540	$	570	$	2,201
Foreign currency derivatives loss (gain)	—		250		692		(4,424		)
	$	2,670	$	2,790	$	1,262	$	(2,223	)

Trading securities losses related to unrealized losses on the Madalena Energy Inc. ("Madalena") 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 September 30, 2015, we did not have any open foreign currency derivative positions.

Income tax expense

For the three and nine months ended September 30, 2015, income tax recovery was $59.0 million and $58.1 million, respectively, compared with income tax expense of $26.5 million and $84.6 million, respectively, in the corresponding periods in 2014. The income tax recovery for the three and nine months ended September 30, 2015, was primarily due to the ceiling test impairment loss in Colombia.

The effective tax rate was 24% in the nine months ended September 30, 2015, compared with 40% in the comparable period in 2014. The decrease in the effective tax rate for the nine months ended September 30, 2015, was due to an increase in the valuation allowance caused by the 2015 impairment losses in Brazil and Peru and an increase in the tax rate in Canada, as well as an increase in the foreign currency translation.

For the nine months ended September 30, 2015, the difference between the effective tax rate of 24% and the 35% U.S. statutory rate was primarily due to an increase in the valuation allowance, non-deductible third party royalty in Colombia and other local taxes, partially offset by the impact of foreign taxes and other permanent differences. The variance between the effective tax rate of 40% from the 35% U.S. statutory rate for the nine months ended September 30, 2014, was primarily attributable to the non-deductible third party royalty in Colombia the impact of other local taxes, non-deductible stock-based compensation, and an increase in the valuation allowance, partially offset by the foreign currency translation adjustments and the foreign tax rate differential.

Funds flow from continuing operations

For the three and nine months ended September 30, 2015, funds flow from continuing operations decreased by 61% to $36.6 million and by 65% to $91.5 million, respectively, compared with the corresponding periods in 2014. For the three months ended September 30, 2015, decreased oil and natural gas sales, severance expenses, and higher realized foreign exchange gains were partially offset by decreased operating, G&A and income tax expenses. For the nine months ended September 30, 2015, decreased oil and natural gas sales, higher operating, severance and equity tax expenses and cash settlement of foreign currency derivatives were partially offset by decreased G&A and income tax expenses and realized foreign exchange gains.

Business Environment Outlook

Our revenues are significantly affected by the continuing volatility in oil prices. Oil prices are volatile and unpredictable and are influenced by concerns about the world supply and demand imbalance, market competition between large suppliers for market share, political influences, financial markets and the impact of the worldwide economy on oil supply and demand growth.

Based on our current projections, our 2015 capital expenditure program and planned share repurchase program can be funded by 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 another sharp downturn in oil and gas prices, we would examine measures such as capital expenditure program reductions, use of our revolving credit facility, issuance of debt, disposition of assets, or issuance of equity. We are the operator of the majority of our capital program and therefore can increase and decrease the program based on commodity prices. Given the current economic environment, with unstable conditions in the Middle East, North Africa and Eastern Europe and the current over supply of oil in world markets, we expect the oil price environment to remain volatile in the near-term. 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 markets. Should we be required to raise debt or equity financing 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. The current low and volatile oil price has had a negative impact on the value of shares of our Common Stock. Also, raising funds by issuing shares or other equity securities could dilute our existing shareholders, and this dilution would be exacerbated by a decline in our share price. 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.

2015 Capital Program

Capital expenditures for the nine months ended September 30, 2015, were $116.4 million compared with $268.9 million for the nine months ended September 30, 2014. In 2015, capital expenditures included drilling of $53.6 million, geological and geophysical (“G&G”) expenditures of $27.5 million, facilities of $29.9 million and other expenditures of $5.4 million. G&G expenditures primarily relate to seismic acquisition and processing.

Our planned 2015 capital program is expected to be approximately $175 to $185 million. We expect to finance our 2015 capital program through cash flows from operations and cash on hand, while retaining financial flexibility to undertake further development opportunities and pursue acquisitions. However, as a result of the nature of the oil and natural gas exploration, development and exploitation industry, budgets are regularly reviewed with respect to both the success of expenditures and other opportunities that become available. Accordingly, while we currently intend that funds be expended as set forth in our 2015 capital program, there may be circumstances where, for business reasons, actual expenditures may in fact differ.

Capital Program - Colombia

Capital expenditures in our Colombian segment during the three months ended September 30, 2015, were $18.9 million bringing total capital expenditures for the nine months ended September 30, 2015, to $48.4 million. The following table provides a breakdown of capital expenditures in 2015 and 2014:



	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2015		2014		2015		2014
Drilling and completions	$	15,522	$	28,608	$	29,704	$	84,941
G&G	1,003		10,357		8,325		30,270
Facilities and equipment	1,619		6,474		8,695		20,021
Other	759		5,346		1,633		11,784
	$	18,903	$	50,785	$	48,357	$	147,016

The significant elements of our third quarter 2015 capital program in Colombia were:


•	On the Chaza Block (100% working interest ("WI"), operated), we commenced drilling the Costayaco-25D, Costayaco-26D and Moqueta-19i development wells. The Moqueta-19i well was completed as a water injector as planned and, subsequent to the quarter end, the Costayaco-25D well was completed as a multi-zone oil producing well.

•

On the Garibay and Tiple Block (38.5% WI, non-operated), unitization of the Jilguero Field was completed and we became a 38.5% WI owner in the newly unitized field. Together with our partners, we drilled three development wells, Jilguero Sur-2, Jilguero-3 and Jilguero-4. Two of these wells were completed as oil producing wells during the quarter, and the third was completed as an oil producing well shortly after the quarter-end.


•	We continued facilities work at the Costayaco and Moqueta Fields on the Chaza Block.

Outlook - Colombia

Our planned fourth quarter capital program in Colombia includes drilling a further three development wells on the Chaza Block, in addition to the three that were started during the third quarter. Facilities work is also planned for the Chaza and Garibay Blocks and we expect to pay back-in costs for the Putumayo-4 Block (70% operated, subject to ANH approval) farm-in.

Capital Program – Brazil

Capital expenditures in our Brazilian segment during the three months ended September 30, 2015, were $1.8 million, bringing total capital expenditures for the nine months ended September 30, 2015, to $18.2 million. Capital expenditures in the three months ended September 30, 2015, consisted of G&G expenditures of $0.4 million, facilities of $1.1 million and other expenditures of $0.3 million.

Outlook – Brazil

The 2015 capital program in Brazil is $22 million. A total of $16.4 million was spent in the first six months of 2015, prior to refocusing the company's efforts on Colombia.

Our planned capital program for the remainder of 2015 in Brazil includes continued work on existing facilities. The First Appraisal Plan ("PAD") phase for Blocks REC-T-129, REC-T-142 and REC-T-155 ended on May 24, 2015, however we requested and were granted a suspension of the PAD phase until regulatory policies governing unconventional activities are finalized.

Capital Program – Peru

Capital expenditures in our Peruvian segment for the three months ended September 30, 2015, were $3.9 million, bringing total capital expenditures for the nine months ended September 30, 2015, to $48.8 million. In the three months ended September 30, 2015, capital expenditures included $0.8 million on Block 95 and $3.1 million on our other blocks in Peru, and consisted of drilling of $0.6 million, facilities expenditures of $1.0 million, and G&G expenditures and other expenditures of $2.3 million.

The significant elements of our third quarter 2015 capital program in Peru were:


•	On Blocks 107 and 133 (100% WI, operated), we continued the environmental permitting process.


•	On Block 95 (100% WI, operated), we focused on maintaining tangible asset integrity and security and the process with PeruPetro S.A. of “ring-fencing” the Bretaña Field.

Outlook - Peru

Our planned capital program for the remainder of 2015 in Peru includes continuing the environmental permitting process on Blocks 107 and 133. On Block 95, we will focus on activities necessary to maintain tangible asset integrity and security and continue the process of “ring-fencing” the Bretaña Field and maintaining the remainder of the block as exploration acreage for an additional time period.

Liquidity and Capital Resources

At September 30, 2015, we had working capital of $190.8 million compared with $239.8 million at December 31, 2014, including cash and cash equivalents of $187.0 million compared with $331.8 million at December 31, 2014.

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 2015, given current oil price trends and production levels. In accordance with our investment policy, cash balances are held in our primary cash management bank in interest earning current accounts or are invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions.

At September 30, 2015, 90% of our cash and cash equivalents were held by subsidiaries and partnerships outside of Canada and the United States. This cash was generally not available to fund domestic or head office operations unless funds were repatriated. At this time, we do not intend to repatriate further funds, 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 the Special Exchange Regime, which allows us to 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.

At September 30, 2015, we had a credit facility with a syndicate of lenders. Loans under the credit agreement will 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 borrowing base for the credit facility is supported by the present value of the petroleum reserves of two 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 and were in compliance with certain financial and operating covenants. No amounts have been drawn on this facility. This credit facility was entered into and became effective on September 18, 2015, and replaced our previous credit facility which was canceled on this date.

Cash Flows

During the nine months ended September 30, 2015, our cash and cash equivalents decreased by $144.9 million as a result of cash used in investing activities of $191.2 million and cash used in financing activities of $6.0 million, partially offset by cash provided by operating activities of $58.5 million. During the nine months ended September 30, 2014, our cash and cash equivalents decreased by $68.4 million as a result of cash used in investing activities of $219.4 million (including $12.4 million of cash used in investing activities of discontinued operations and $42.8 million of proceeds from sale of Argentina business unit, net of cash sold and transaction costs), partially offset by cash provided by operating activities of $142.2 million (including $4.8 million of cash used in operating activities of discontinued operations) and cash provided by financing activities of $11.2 million.

Cash provided by operating activities in the nine months ended September 30, 2015, was primarily affected by decreased oil and natural gas sales, higher operating, severance and equity tax expenses and cash settlement of foreign currency derivatives and a $28.1 million change in assets and liabilities from operating activities. These amounts were partially offset by decreased G&A and income tax expenses and realized foreign exchange gains.

The main changes in assets and liabilities from operating activities were as follows: accounts receivable decreased by $52.1 million primarily due to lower oil and gas sales; inventory decreased by $1.6 million, excluding the effect of non-cash DD&A, primarily due to lower inventory costs per bbl offset by higher inventory volumes as a result of OTA pipeline disruptions; accounts payable and accrued liabilities decreased by $36.9 million due to a reduction in drilling activity and lower accruals for royalties due to lower oil prices and sales volumes; and net taxes receivable increased by $47.5 million primarily due to lower current income taxes for 2015 in Colombia.

Cash used in investing activities in the nine months ended September 30, 2015, included capital expenditures incurred of $116.4 million ($48.4 million in Colombia, $48.8 million in Peru, $18.2 million in Brazil and $1.0 million Corporate) and $75.2 million of net cash outflows related to changes in assets and liabilities associated with investing activities ($46.6 million in Colombia, $26.6 million in Peru, and $2.0 million in Brazil and Corporate), partially offset by a decrease in restricted cash of $0.3 million. Cash used in investing activities of continuing operations in the nine months ended September 30, 2014, included capital expenditures incurred of $268.9 million, partially offset by $18.2 million of net cash inflows related to changes in assets and liabilities associated with investing activities and a decrease in restricted cash of $0.9 million.

Cash used in financing activities in the nine months ended September 30, 2015, related to the repurchase of shares of our Common Stock pursuant to a normal course issuer bid partially offset by proceeds from issuance of shares of our Common Stock upon the exercise of stock options. Cash provided by financing activities in the nine months ended September 30, 2014, related to proceeds from issuance of shares of our Common Stock upon the exercise of stock options.

Off-Balance Sheet Arrangements

As at September 30, 2015, we had no off-balance sheet arrangements.

Contractual Obligations

As at September 30, 2015, there were no material changes to our contractual obligations outside of the ordinary course of business from those as of December 31, 2014.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2014 Annual Report on Form 10-K, filed with the SEC on March 2, 2015, 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

Holding all factors constant other than benchmark oil prices, it is reasonably likely that we will experience ceiling test impairment losses in our Brazil and Colombia cost centers in the fourth quarter of 2015.

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 fourth quarter of 2015 could exceed $15 million in Brazil and $95 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 $55.05 per bbl for the year ended December 31, 2015. 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 nine months ended September 2015, and, for the three months ended December 2015, estimated oil prices for the fourth quarter of 2015 using the forward price curve forecast of our independent reserves evaluator dated October 1, 2015.

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

Holding all factors constant other than benchmark oil prices and related royalty rates, we do not expect any downward adjustment to our consolidated NAR reserve volumes during the fourth quarter of 2015. In a continued low oil price environment, we expect that a loss of less than five percent of the December 31, 2014, consolidated proved NAR reserves in Brazil would be more than offset by an increase of NAR reserves in Colombia due to the lower rate at which cash royalties are levied in low oil price environments. This disclosure is based on a pro forma Brent oil price of $55.05 per bbl for the year ended December 31, 2015, calculated as described above.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Oil prices started falling in July 2014 and fell dramatically during the period December 2014 to March 2015. Prices have remained low and volatile. Most of our revenues are from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to West Texas Intermediate ("WTI") or Brent and adjusted for quality each month.

Foreign currency risk

Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and essentially 100% of our revenues are related to the U.S. dollar price of WTI or Brent oil. In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. In Brazil, prices for oil are in U.S. dollars, but revenues are received in local currency translated according to current exchange rates. The majority of our capital expenditures within Brazil are based on U.S. dollar prices, but are paid in local currency translated according to current exchange rates. In Peru, capital expenditures are based on U.S. dollar prices and may be paid in local currency or U.S. dollars. The majority of income and value added taxes and G&A expenses in all locations are in local currency. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our current and deferred tax liabilities, which are monetary liabilities, denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $24,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

We have engaged, from time to time, in non-deliverable foreign exchange contracts to buy or sell Colombian pesos in order to fix the exchange rate of our income tax installments and payments in Colombia. At September 30, 2015, the Company did not have any open foreign currency derivative positions.

The table below provides information about our foreign currency forward exchange agreements at December 31, 2014, including the notional amounts and weighted average exchange rates by expected (contractual) maturity dates. Expected cash flows from the forward contracts equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. The increase or decrease in the value of the forward contract was offset by the increase or decrease to the U.S. dollar equivalent of the Colombian peso current tax liabilities. We did not hold any of these investments for trading purposes.



	As at December 31, 2014
Currency	Contract Type	Notional (Millions of Colombian Pesos)	Weighted Average Fixed Rate Received (Colombian Pesos - U.S. Dollars)	Fair Value of the Forward Contracts (thousands of U.S. Dollars)		Expiration
Colombian pesos	Buy	51,597.5	2,006	(4,175	)	February and April 2015
Colombian pesos	Sell	10,275.3	1,895	1,118		February 2015

Interest Rate Risk

We consider our exposure to interest rate risk to be immaterial. Our interest rate exposures primarily relate to our investment portfolio. Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any of these investments for trading purposes. We have no debt.

Equity Investment in Madalena Energy Inc.

We hold an equity investment in Madalena received as consideration in the sale of our Argentina business unit, which closed June 25, 2014. We hold 29,831,537 shares of Madalena which had a value of $7.6 million at December 31, 2014, and $7.0 million at September 30, 2015, and represented approximately 5.5% of Madalena's outstanding shares at September 30, 2015. These shares trade on the TSX Venture Exchange and as such are subject to changes in value that are outside of our control. We may face market related obstacles such as trading volume and value in divesting these shares.

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 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 principal executive and principal financial officers have concluded that Gran Tierra's disclosure controls and procedures were effective as of September 30, 2015, 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.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2015, 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, 2014, 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, 2014. 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, 2014.

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

Issuer Purchases of Equity Securities



	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share⁽²⁾	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs⁽³⁾
Month #1 (July 1, 2015 - July 31, 2015)	—	—	—	13,831,866
Month #2 (August 1, 2015 - August 31, 2015)	2,575,996	2.18	2,575,996	11,255,870
Month #3 (September 1, 2015 - September 30, 2015)	424,800	2.30	424,800	10,831,070
Total	3,000,796	2.20	3,000,796	10,831,070

⁽¹⁾ Based on settlement date.

⁽²⁾Exclusive of commissions paid to the broker to repurchase the common shares.

⁽³⁾ On July 22, 2015, we announced that we intended to implement a share repurchase program or normal course issuer bid (the “2015 Program”) through the facilities of the Toronto Stock Exchange ("TSX"), the NYSE MKT and eligible alternative trading platforms in Canada and the United States. We received regulatory approval from the TSX to commence the 2015 Program on July 27, 2015. We are able to purchase at prevailing market prices up to 13,831,866 shares of Common Stock, representing 4.98% of our issued and outstanding shares of Common Stock as of July 21, 2015. The average daily trading volume of shares of Common Stock over the six calendar month period prior to July 28, 2015, was 946,386 meaning that we are entitled to purchase, on any trading day, up to 236,596 shares of Common Stock. Shares of Common Stock purchased pursuant to the 2015 Program will be canceled. The 2015 Program will expire on July 29, 2016, or earlier if the 4.98% share maximum is reached. The 2015 Program may be terminated by us at any time, subject to compliance with regulatory requirements. As such, there can be no assurance regarding the total number of shares that may be repurchased under the 2015 Program. Shareholders may obtain a copy of the Notice of Intention to Make A Normal Course Issuer Bid filed with the TSX detailing the 2015 Program free of charge by writing or telephoning us at the following address or phone number: 200, 150 13 Avenue S.W. Calgary, Alberta, Canada T2R 0V2, telephone: 403-265-3221.

Item 6. Exhibits

See Index to Exhibits at the end of this Quarterly Report on Form 10-Q, which is incorporated by reference here. The Exhibits listed in the accompanying Index to Exhibits are filed as part of this report.

SIGNATURES

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

GRAN TIERRA ENERGY INC.



Date: November 3, 2015		/s/ Gary Guidry
		By: Gary Guidry
		President and Chief Executive Officer
		(Principal Executive Officer)



Date: November 3, 2015		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

EXHIBIT INDEX



Exhibit No.	Description	Reference
2.1	Share Purchase and Sale Offer, dated May 29, 2014, by Gran Tierra Petroco Inc. +	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on July 1, 2014 (SEC File No. 001-34018).

2.2	Share Purchase and Sale Offer, dated May 29, 2014, by Gran Tierra Energy Inc. and PCESA Petroleros Canadienses De Ecuador S.A. +	Incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K, filed with the SEC on July 1, 2014 (SEC File No. 001-34018).

3.1	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	Seventh 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 February 26, 2014 (SEC File No. 001-34018).

10.1	Credit Agreement, dated as of September 18, 2015, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2015 (SEC File No. 001-34018).

10.2	Executive Employment Agreement effective May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Gary Guidry	Filed herewith.

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

10.4	Executive Employment Agreement effective May 11, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Alan Johnson	Filed herewith.

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

10.6	Executive Employment Agreement effective May 11, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and James Evans	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.

Gran Tierra Energy - 10-Q quarterly report FY2015 Q3

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