GRAN TIERRA ENERGY INC. - Quarter Report: 2015 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 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 July 31, 3015, the following number of shares of the registrant’s capital stock were outstanding: 277,748,335 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 5,044,777 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 June 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	31
Item 4.	Controls and Procedures	33

PART II	Other Information
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 6.	Exhibits	33
SIGNATURES		33
EXHIBIT INDEX		35

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. The information included herein is given as of the filing date of this 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	MBOE	thousand barrels of oil equivalent
MMbbl	million barrels	BOEPD	barrels of oil equivalent per day
bopd	barrels of oil per day	Mcf	thousand cubic feet
NAR	net after royalty

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. 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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
REVENUE AND OTHER INCOME
Oil and natural gas sales (Note 4)	$	69,350		$	147,888		$	145,581		$	298,993
Interest income	382			638			803			1,388
	69,732			148,526			146,384			300,381
EXPENSES
Operating	24,133			25,346			55,567			47,212
Depletion, depreciation, accretion and impairment	69,473			41,937			155,627			86,201
General and administrative (Note 6)	10,298			13,932			17,592			26,795
Severance (Note 11)	1,988			—			6,366			—
Equity tax (Note 8)	—			—			3,769			—
Foreign exchange loss (gain)	2,969			10,044			(8,569		)	5,834
Financial instruments gain (Note 10)	(1,366		)	(2,604		)	(1,408		)	(5,013		)
	107,495			88,655			228,944			161,029

(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(37,763		)	59,871			(82,560		)	139,352
INCOME TAX (EXPENSE) RECOVERY
Current	(5,684		)	(26,968		)	(8,109		)	(58,937		)
Deferred	4,883			(1,419		)	7,239			841
	(801		)	(28,387		)	(870		)	(58,096		)
(LOSS) INCOME FROM CONTINUING OPERATIONS	(38,564		)	31,484			(83,430		)	81,256
Loss from discontinued operations, net of income taxes (Note 3)	—			(22,347		)	—			(26,990		)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)	(38,564		)	9,137			(83,430		)	54,266
RETAINED EARNINGS, BEGINNING OF PERIOD	194,756			456,090			239,622			410,961
RETAINED EARNINGS, END OF PERIOD	$	156,192		$	465,227		$	156,192		$	465,227

(LOSS) INCOME PER SHARE
BASIC
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.13	)	$	0.11		$	(0.29	)	$	0.29
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			(0.08		)	—			(0.10		)
NET INCOME (LOSS)	$	(0.13	)	$	0.03		$	(0.29	)	$	0.19
DILUTED
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.13	)	$	0.11		$	(0.29	)	$	0.29
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			(0.08		)	—			(0.10		)
NET INCOME (LOSS)	$	(0.13	)	$	0.03		$	(0.29	)	$	0.19
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	286,393,772			283,773,204			286,294,595			283,505,690
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	286,393,772			287,856,959			286,294,595			288,338,698

(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)



	June 30,		December 31,
	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	166,399	$	331,848
Restricted cash	347		1,836
Accounts receivable	51,332		83,227
Marketable securities (Note 10)	9,686		7,586
Inventory (Note 5)	33,459		17,298
Taxes receivable	28,732		15,843
Prepaids	3,867		6,000
Deferred tax assets	1,416		1,552
Total Current Assets	295,238		465,190

Oil and Gas Properties
Proved	721,951		801,075
Unproved	324,979		316,856
Total Oil and Gas Properties	1,046,930		1,117,931
Other capital assets	10,339		11,013
Total Property, Plant and Equipment (Note 5)	1,057,269		1,128,944

Other Long-Term Assets
Restricted cash	3,847		2,037
Deferred tax assets	567		601
Taxes receivable	13,654		9,684
Other long-term assets	6,068		5,013
Goodwill	102,581		102,581
Total Other Long-Term Assets	126,717		119,916
Total Assets	$	1,479,224	$	1,714,050
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	34,260	$	112,401
Accrued liabilities	53,346		75,430
Foreign currency derivative (Note 10)	—		3,057
Taxes payable	2,440		25,412
Deferred tax liabilities	23		1,040
Asset retirement obligation (Note 7)	5,582		8,026
Total Current Liabilities	95,651		225,366

Long-Term Liabilities
Deferred tax liabilities	156,194		175,324
Asset retirement obligation (Note 7)	25,657		27,786
Other long-term liabilities	7,178		8,889
Total Long-Term Liabilities	189,029		211,999

Contingencies (Note 9)
Shareholders’ Equity
Common Stock (Note 6) (277,728,335 and 276,072,351 shares of Common Stock and 8,703,666 and 10,119,745 exchangeable shares, par value $0.001 per share, issued and outstanding as at June 30, 2015, and December 31, 2014, respectively)	10,190		10,190
Additional paid in capital	1,028,162		1,026,873
Retained earnings	156,192		239,622
Total Shareholders’ Equity	1,194,544		1,276,685
Total Liabilities and Shareholders’ Equity	$	1,479,224	$	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)



	Six Months Ended June 30,
	2015			2014
Operating Activities
Net income (loss)	$	(83,430	)	$	54,266
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Loss from discontinued operations, net of income taxes (Note 3)	—			26,990
Depletion, depreciation, accretion and impairment	155,627			86,201
Deferred tax recovery	(7,239		)	(841		)
Non-cash stock-based compensation	582			2,624
Unrealized foreign exchange (gain) loss	(8,436		)	4,567
Unrealized financial instruments gain	(5,157		)	(351		)
Equity tax	—			(1,642		)
Cash settlement of asset retirement obligation (Note 7)	(1,964		)	—
Net cash provided by operating activities of continuing operations before changes in operating assets and liabilities	49,983			171,814
Net change in assets and liabilities from operating activities of continuing operations
Accounts receivable and other long-term assets	23,652			(67,862		)
Inventory	(7,697		)	(9,348		)
Prepaids	2,133			1,642
Accounts payable and accrued and other long-term liabilities	(21,102		)	9,747
Taxes receivable and payable	(44,273		)	(77,306		)
Net cash provided by operating activities of continuing operations	2,696			28,687
Net cash used in operating activities of discontinued operations	—			(4,792		)
Net cash provided by operating activities	2,696			23,895

Investing Activities
(Increase) decrease in restricted cash	(320		)	351
Additions to property, plant and equipment	(91,785		)	(173,440		)
Changes in non-cash investing working capital	(76,642		)	15,269
Net cash used in investing activities of continuing operations	(168,747		)	(157,820		)
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	(168,747		)	(127,449		)

Financing Activities
Proceeds from issuance of shares of Common Stock (Note 6)	602			7,113
Net cash provided by financing activities	602			7,113

Net decrease in cash and cash equivalents	(165,449		)	(96,441		)
Cash and cash equivalents, beginning of period	331,848			428,800
Cash and cash equivalents, end of period	$	166,399		$	332,359

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	33,658		$	76,506

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Six Months Ended June 30,			Year Ended December 31,
	2015			2014
Share Capital
Balance, beginning of period	$	10,190		$	10,187
Issue of shares of Common Stock (Note 6)	—			3
Balance, end of period	10,190			10,190

Additional Paid in Capital
Balance, beginning of period	1,026,873			1,008,760
Exercise of stock options (Note 6)	602			11,137
Stock-based compensation (Note 6)	687			6,976
Balance, end of period	1,028,162			1,026,873

Retained Earnings
Balance, beginning of period	239,622			410,961
Net loss	(83,430		)	(171,339		)
Balance, end of period	156,192			239,622

Total Shareholders’ Equity	$	1,194,544		$	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 and 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.

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 three and six months ended June 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 six months ended June 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 three and six months ended June 30, 2014, were as follows:



	Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of U.S. Dollars)	2014			2014
Revenue and other income	$	14,161		$	31,985

Loss from operations of discontinued operations before income taxes	$	(2,079	)	$	(6,252	)
Income tax expense	(988		)	(1,458		)
Loss from operations of discontinued operations	(3,067		)	(7,710		)

Loss on sale before income taxes	(18,235		)	(18,235		)
Income tax expense	(1,045		)	(1,045		)
Loss on sale	(19,280		)	(19,280		)
Loss from discontinued operations, net of income taxes	$	(22,347	)	$	(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 June 30, 2015
(Thousands of U.S. Dollars)	Colombia		Peru			Brazil			All Other			Total
Oil and natural gas sales	$	67,627	$	—		$	1,723		$	—		$	69,350
Interest income	93		2			78			209			382
Depletion, depreciation, accretion and impairment	37,061		5,432			26,575			405			69,473
Income (loss) from continuing operations before income taxes	3,197		(8,261		)	(28,211		)	(4,488		)	(37,763		)
Segment capital expenditures	8,087		6,856			2,505			316			17,764
	Three Months Ended June 30, 2014
(Thousands of U.S. Dollars)	Colombia		Peru			Brazil			All Other			Total
Oil and natural gas sales	$	139,350	$	—		$	8,538		$	—		$	147,888
Interest income	184		—			434			20			638
Depletion, depreciation, accretion and impairment	39,348		103			2,241			245			41,937
Income (loss) from continuing operations before income taxes	62,481		(2,408		)	3,750			(3,952		)	59,871
Segment capital expenditures	45,688		41,912			3,433			306			91,339
	Six Months Ended June 30, 2015
(Thousands of U.S. Dollars)	Colombia		Peru			Brazil			All Other			Total
Oil and natural gas sales	$	141,694	$	—		$	3,887		$	—		$	145,581
Interest income	160		2			218			423			803
Depletion, depreciation, accretion and impairment	83,316		38,380			33,169			762			155,627
Income (loss) from continuing operations before income taxes	6,125		(43,703		)	(35,092		)	(9,890		)	(82,560		)
Segment capital expenditures	29,454		44,890			16,406			1,035			91,785
	Six Months Ended June 30, 2014
(Thousands of U.S. Dollars)	Colombia		Peru			Brazil			All Other			Total
Oil and natural gas sales	$	284,285	$	—		$	14,708		$	—		$	298,993
Interest income	321		—			859			208			1,388
Depletion, depreciation, accretion and impairment	80,598		311			4,820			472			86,201
Income (loss) from continuing operations before income taxes	148,492		(4,466		)	5,700			(10,374		)	139,352
Segment capital expenditures	96,231		62,805			13,799			605			173,440



	As at June 30, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	826,824	$	93,700	$	131,834	$	4,911	$	1,057,269
Goodwill	102,581		—		—		—		102,581
All other assets	176,055		23,602		3,421		116,296		319,374
Total Assets	$	1,105,460	$	117,302	$	135,255	$	121,207	$	1,479,224

	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

The Company’s revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions.

In the three and six months ended June 30, 2015, the Company had two significant customers in Colombia: Ecopetrol S.A. ("Ecopetrol") and one other customer. In the three and six months ended June 30, 2015, sales to Ecopetrol accounted for 75% and 77%, respectively, of the Company's consolidated oil and natural gas sales from continuing operations and sales to the other customer accounted for 16% and 11%, respectively. In the three and six months ended June 30, 2014, sales to Ecopetrol accounted for 54% and 52%, respectively, of the Company's consolidated oil and natural gas sales from continuing operations and sales to the other significant customer accounted for 33% and 38%, respectively, of the Company's consolidated oil and natural gas sales from continuing operations.

5. Property, Plant and Equipment and Inventory

Property, Plant and Equipment



(Thousands of U.S. Dollars)	As at June 30, 2015			As at December 31, 2014
Oil and natural gas properties
Proved	$	1,920,806		$	1,876,371
Unproved	324,979			316,856
	2,245,785			2,193,227
Other	28,499			27,287
	2,274,284			2,220,514
Accumulated depletion, depreciation and impairment	(1,217,015		)	(1,091,570		)
	$	1,057,269		$	1,128,944

In the three and six months ended June 30, 2015, the Company recorded ceiling test impairment losses in its Brazil cost center of $25.0 million and $29.3 million, respectively, 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 six months ended June 30, 2015, the Company recorded impairment losses in its Peru cost center of $5.3 million and $38.0 million, respectively, related to costs incurred on Block 95.

Inventory

At June 30, 2015, oil and supplies inventories were $32.1 million and $1.4 million, respectively (December 31, 2014 - $15.2 million and $2.1 million, respectively). At June 30, 2015, the Company had 679 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		—		—
Exchange of exchangeable shares	1,415,995		(530,257	)	(885,738	)
Shares canceled	(11	)	(84	)	—
Balance, June 30, 2015	277,728,335		5,064,777		3,638,889

Income (loss) per share

Basic income (loss) per share is calculated by dividing income (loss) attributable to common shareholders by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted income (loss) per share is calculated by adjusting the weighted average number of shares of Common Stock and exchangeable shares outstanding for the dilutive effect, if any, of share equivalents. The Company uses the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume weighted average trading price of shares of Common Stock during the period.



	Three Months Ended June 30,			Six Months Ended June 30,
	2015	2014		2015	2014
Weighted average number of common and exchangeable shares outstanding	286,393,772	283,773,204		286,294,595	283,505,690
Weighted average shares issuable pursuant to stock options	—	13,373,568		—	13,462,797
Weighted average shares assumed to be purchased from proceeds of stock options	—	(9,289,813	)	—	(8,629,789	)
Weighted average number of diluted common and exchangeable shares outstanding	286,393,772	287,856,959		286,294,595	288,338,698

For the three months ended June 30, 2015, 14,104,370 options, on a weighted average basis, (three months ended June 30, 2014 - 3,137,840 options) were excluded from the diluted income per share calculation as the options were anti-dilutive. For the six months ended June 30, 2015, 14,550,722 options, on a weighted average basis, (six months ended June 30, 2014 - 3,137,840 options) 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 six months ended June 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		4,726,260		3.17
Exercised	(497,409	)	(240,000	)	(2.51	)
Forfeited	(683,261	)	(1,314,380	)	(5.68	)
Expired	—		(3,727,376	)	(6.83	)
Balance, June 30, 2015	1,097,743		13,234,724		4.77

For the six months ended June 30, 2015, 240,000 shares of Common Stock were issued for cash proceeds of $0.6 million upon the exercise of stock options (six months ended June 30, 2014 - $7.1 million).

The weighted average grant date fair value for options granted in the three months ended June 30, 2015, was $1.43 (three months ended June 30, 2014 - $2.38) and for the six months ended June 30, 2015, was $1.28 (six months ended June 30, 2014 - $2.51).

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



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2015			2014			2015			2014
Compensation costs for stock options	$	1,109		$	1,847		$	687		$	3,863
Compensation costs for RSUs	597			2,397			537			3,641
	1,706			4,244			1,224			7,504
Less: Stock-based compensation costs capitalized	(80		)	(1,039		)	(111		)	(1,822		)
Stock-based compensation expense	$	1,626		$	3,205		$	1,113		$	5,682

Stock-based compensation expense for the three and six months ended June 30, 2015, was primarily recorded in general and administrative ("G&A") expenses. Of the total stock-based compensation expense for the three months ended June 30, 2014, $2.0 million was recorded in G&A expenses, $0.1 million was recorded in operating expenses and $1.1 million was recorded in loss from discontinued operations. Of the total stock-based compensation expense for the six months ended June 30, 2014, $4.1 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 June 30, 2015, there was $6.8 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 1.6 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:



	Six Months Ended			Year Ended
(Thousands of U.S. Dollars)	June 30, 2015			December 31, 2014
Balance, beginning of period	$	35,812		$	21,973
Settlements	(5,565		)	(1,137		)
Liability incurred	432			11,956
Liabilities associated with the Argentina business unit sold (Note 3)	—			(10,170		)
Foreign exchange	—			(53		)
Accretion	631			1,406
Revisions in estimated liability	(71		)	11,837
Balance, end of period	$	31,239		$	35,812

Asset retirement obligation - current	$	5,582		$	8,026
Asset retirement obligation - long-term	25,657			27,786
Balance, end of period	$	31,239		$	35,812

For the six months ended June 30, 2015, settlements included cash payments of $2.0 million with the balance in accounts payable and accrued liabilities at June 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 June 30, 2015, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $3.4 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 (1.1)% in the six months ended June 30, 2015, compared with 41.7% in the comparable period in 2014. In the six months ended June 30, 2015, the Company had income tax expense despite having a loss from continuing operations. The Company's effective tax rate differed from the U.S. statutory rate of 35% primarily due to an increase to the valuation allowance, which was largely attributable to the 2015 impairment losses and increases in tax rates, as well as other local taxes and the non-deductible third party royalty in Colombia. 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. At June 30, 2015, accounts payable included the unpaid balance of equity tax liability of $1.7 million (December 31, 2014 - $nil) which will be paid in September 2015.

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 $24.8 million. Gran Tierra also disagrees with the interest rate that the ANH has used in calculating the interest cost. Gran Tierra asserts that since the HPR royalty is denominated in the U.S. dollar, the contract requires the interest rate to be three-month LIBOR plus 4%, whereas the ANH has applied the highest legally authorized interest rate on Colombian peso liabilities, which during the period of production to date has averaged approximately 29% per annum. At March 31, 2015, based on an interest rate of three-month LIBOR plus 4% related interest would be $4.9 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 $42.1 million as at June 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 June 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 June 30, 2015, the Company had provided promissory notes totaling $76.2 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 June 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, foreign currency derivatives 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 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 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 the trading securities, foreign currency derivative liability and contingent consideration at June 30, 2015, and December 31, 2014, were as follows:



	As at
(Thousands of U.S. Dollars)	June 30, 2015		December 31, 2014
Trading securities	$	9,686	$	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 June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2015			2014			2015			2014
Trading securities gain	$	(1,688	)	$	(339	)	$	(2,100	)	$	(339	)
Foreign currency derivatives loss (gain)	322			(2,265		)	692			(4,674		)
	$	(1,366	)	$	(2,604	)	$	(1,408	)	$	(5,013	)

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

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 June 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 June 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 $60,000 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 June 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 six months ended June 30, 2015, 97% (six months ended June 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, accounts receivables and foreign currency derivatives. The carrying value of cash, accounts receivable and foreign currency derivatives reflects management’s assessment of credit risk.

At June 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, largely as a result of the current low commodity price environment, 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. These terminations were not part of the planned March 2015 staff reductions.

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 six months ended June 30, 2015, were as follows:



	Three Months Ended June 30, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Severance expenses	$	71	$	901	$	—	$	1,016	$	1,988
	Six Months Ended June 30, 2015
	Colombia		Peru		Brazil		All Other		Total
Severance expenses	$	1,237	$	1,424	$	109	$	3,596	$	6,366

The amounts in the table for the six months ended June 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.

At June 30, 2015, accounts payable and accrued liabilities included $2.3 million in relation to these actions which are expected to be settled within the three months ending September 30, 2015. Changes in the severance cost related liability were as follows:



(Thousands of U.S. Dollars)	Six Months Ended June 30, 2015
Balance, beginning of period	$	—
Liability incurred	6,366
Settlements	(4,090		)
Balance, end of period	$	2,276

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

This report, 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.

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.

Overview

We are an independent international energy company incorporated in the United States and engaged in oil and natural gas acquisition, exploration, development and production. Our operations are carried out in South America in Colombia, Peru and Brazil, and we are headquartered in Calgary, Alberta, Canada.

During the three months ending June 30, 2015, a new management team and board of directors of the Company was appointed. On May 7, 2015, we entered into an agreement (the “Agreement”) with West Face SPV (Cayman) I L.P. (“West Face”) pursuant to which we settled a proxy contest. Pursuant to the terms of the Agreement, Gary Guidry was appointed as our President and Chief Executive Officer. Mr. Guidry replaced Duncan Nightingale in that role, who was serving as interim Chief Executive Officer since February 2015 and, with the appointment of Mr. Guidry as Chief Executive Officer, was designated as Executive Vice President. Additionally, effective May 11, 2015, Ryan Ellson was appointed as Chief Financial Officer. Under the terms of the Agreement, our Board of Directors was expanded from six to eight directors. At our Annual General Meeting on June 24, 2015, the majority of our shareholders elected the proposed board members.

For the six months ended June 30, 2015, 97% (six months ended June 30, 2014 - 95%) of our revenue and other income from continuing operations was generated in Colombia. During the three months ending June 30, 2015, our board approved a new capital program, focused on accelerating development activities in Colombia.

The price of oil is a critical factor to our business, has historically been volatile and decreased dramatically in December 2014 through March 2015, remaining at relatively low levels through June 30, 2015. Sustained periods of low oil prices have decreased our financial performance; however we remain in a strong financial position with working capital of $199.6 million including cash and cash equivalents of $166.4 million and zero debt. During the six months ended June 30, 2015, the average price realized for our oil was $47.03 per barrel (six months ended June 30, 2014 - $91.74). Average Brent oil prices for the six months ended June 30, 2015, were $57.81 per bbl compared with $108.93 per bbl in the corresponding period in 2014. West Texas Intermediate ("WTI") oil prices for the six months ended June 30, 2015, were $53.25 per bbl compared with $100.84 per bbl in the corresponding period in 2014. Despite the fall in the oil prices, at June 30, 2015, we had working capital of $199.6 million, no debt, and an undrawn $150 million credit facility.

Highlights



	Three Months Ended June 30,								Six Months Ended June 30,
	2015			2014⁽²⁾			% Change		2015			2014⁽²⁾			% Change
Volumes (MBOE)
Working Interest Production Before Royalties	2,101			2,390			(12	)	4,263			4,662			(9	)
Royalties	(418		)	(583		)	(28	)	(768		)	(1,142		)	(33	)
Production NAR	1,683			1,807			(7	)	3,495			3,520			(1	)
Inventory Adjustments and Losses	(321		)	(212		)	51		(387		)	(237		)	63
Sales⁽¹⁾	1,362			1,595			(15	)	3,108			3,283			(5	)

Average Daily Volumes (BOEPD)
Working Interest Production Before Royalties	23,094			26,261			(12	)	23,552			25,756			(9	)
Royalties	(4,600		)	(6,404		)	(28	)	(4,240		)	(6,311		)	(33	)
Production NAR	18,494			19,857			(7	)	19,312			19,445			(1	)
Inventory Adjustments and Losses	(3,524		)	(2,333		)	51		(2,140		)	(1,310		)	63
Sales⁽¹⁾	14,970			17,524			(15	)	17,172			18,135			(5	)

Oil and Gas Sales ($000s)	$	69,350		$	147,888		(53	)	$	145,581		$	298,993		(51	)
Operating Expenses ($000s)	(24,133		)	(25,346		)	(5	)	(55,567		)	(47,212		)	18
Operating Netback ($000s)⁽³⁾	$	45,217		$	122,542		(63	)	$	90,014		$	251,781		(64	)

General and Administrative Expenses ("G&A")
G&A Expenses Before Stock-Based Compensation, Gross	$	17,288		$	24,504		(29	)	$	37,551		$	48,001		(22	)
Stock-Based Compensation	1,540			1,957			(21	)	1,010			4,100			(75	)
Capitalized G&A and Overhead Recoveries	(8,530		)	(12,529		)	(32	)	(20,969		)	(25,306		)	(17	)
	$	10,298		$	13,932		(26	)	$	17,592		$	26,795		(34	)

EBITDA⁽⁴⁾	$	31,710		$	101,808		(69	)	$	73,067		$	225,553		(68	)

Net Income (Loss)	$	(38,564	)	$	9,137		(522	)	$	(83,430	)	$	54,266		(254	)

Funds Flow from Continuing Operations ($000s)⁽⁵⁾	$	24,425		$	85,145		(71	)	$	49,983		$	171,814		(71	)

Capital Expenditures for Continuing Operations ($000s)	$	17,764		$	91,339		(81	)	$	91,785		$	173,440		(47	)



	As at
	June 30, 2015		December 31, 2014		% Change
Cash & Cash Equivalents ($000s)	$	166,399	$	331,848	(50	)

Working Capital (including Cash & Cash Equivalents) ($000s)	$	199,587	$	239,824	(17	)

(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 six months ended June 30, 2015, and 2,426 BOEPD and 2,744 BOEPD for the corresponding periods in 2014. Discontinued operations sales volumes for the three and six months ended June 30, 2014, were calculated to the date of sale of June 25, 2014.

(3) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. 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. Investors are cautioned that this measure should not be construed as an alternative to net income or loss or other measures of financial performance as determined in accordance with GAAP. Our method of calculating this measure may differ from other companies and, accordingly, it may not be comparable to similar measures used by other companies. Operating netback as presented is oil and gas sales net of royalties and operating expenses.

(4) EBITDA is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Management believes that this financial measure is also useful supplemental information for management and investors as an indicator of the company’s ability to generate liquidity through operating cash flow to fund future working capital needs and fund future capital expenditures. Investors are cautioned that this measure should not be construed as an alternative to net income or loss or other measures of financial performance as determined in accordance with GAAP. Our method of calculating this measure may differ from other companies and, accordingly, it may not be comparable to similar measures used by other companies. 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. A reconciliation from net income or loss to EBITDA is as follows:



	Three Months Ended June 30,					Six Months Ended June 30,
EBITDA - Non-GAAP Measure ($000s)	2015			2014		2015			2014
Net income (loss)	$	(38,564	)	$	9,137	$	(83,430	)	$	54,266
Adjustments to reconcile net income (loss) to EBITDA
Loss from discontinued operations, net of income taxes	—			22,347		—			26,990
DD&A expenses	69,473			41,937		155,627			86,201
Income tax (recovery) expense	801			28,387		870			58,096
EBITDA	$	31,710		$	101,808	$	73,067		$	225,553

(5) Funds flow from continuing operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. 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. Investors are cautioned that this measure should not be construed as an alternative to net income or loss or other measures of financial performance as determined in accordance with GAAP. Our method of calculating this measure may differ from other companies and, accordingly, it may not be comparable to similar measures used by other companies. 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 and financial instruments gains and losses, equity tax and cash settlement of asset retirement obligation. A reconciliation from net income or loss to funds flow from continuing operations is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
Funds Flow From Continuing Operations - Non-GAAP Measure ($000s)	2015			2014			2015			2014
Net income (loss)	$	(38,564	)	$	9,137		$	(83,430	)	$	54,266
Adjustments to reconcile net income (loss) to funds flow from continuing operations
Loss from discontinued operations, net of income taxes	—			22,347			—			26,990
DD&A expenses	69,473			41,937			155,627			86,201
Deferred tax (recovery) expense	(4,883		)	1,419			(7,239		)	(841		)
Non-cash stock-based compensation	1,095			1,144			582			2,624
Unrealized foreign exchange loss (gain)	601			8,745			(8,436		)	4,567
Unrealized financial instruments (gain) loss	(2,758		)	2,058			(5,157		)	(351		)
Equity tax	—			(1,642		)	—			(1,642		)
Cash settlement of asset retirement obligation	(539		)	—			(1,964		)	—
Funds flow from continuing operations	$	24,425		$	85,145		$	49,983		$	171,814

Results of Operations



	Three Months Ended June 30,								Six Months Ended June 30,
	2015			2014⁽²⁾			% Change		2015			2014⁽²⁾			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	69,350		$	147,888		(53	)	$	145,581		$	298,993		(51	)
Interest income	382			638			(40	)	803			1,388			(42	)
	69,732			148,526			(53	)	146,384			300,381			(51	)

Operating expenses	24,133			25,346			(5	)	55,567			47,212			18
DD&A expenses	69,473			41,937			66		155,627			86,201			81
G&A expenses	10,298			13,932			(26	)	17,592			26,795			(34	)
Severance expenses	1,988			—			—		6,366			—			—
Equity tax	—			—			—		3,769			—			—
Foreign exchange loss (gain)	2,969			10,044			(70	)	(8,569		)	5,834			(247	)
Financial instruments gain	(1,366		)	(2,604		)	48		(1,408		)	(5,013		)	72
	107,495			88,655			21		228,944			161,029			42

(Loss) income from continuing operations before income taxes	(37,763		)	59,871			(163	)	(82,560		)	139,352			(159	)

Current income tax expense	(5,684		)	(26,968		)	(79	)	(8,109		)	(58,937		)	(86	)
Deferred income tax recovery (expense)	4,883			(1,419		)	(444	)	7,239			841			761
	(801		)	(28,387		)	(97	)	(870		)	(58,096		)	(99	)
(Loss) income from continuing operations	(38,564		)	31,484			(222	)	(83,430		)	81,256			(203	)
Loss from discontinued operations, net of income taxes	—			(22,347		)	100		—			(26,990		)	100
Net income (loss)	$	(38,564	)	$	9,137		(522	)	$	(83,430	)	$	54,266		(254	)

Sales volumes⁽¹⁾

Oil and NGL's, bbl	1,349,127			1,573,071			(14	)	3,084,025			3,250,049			(5	)
Natural gas, Mcf	78,578			129,711			(39	)	144,605			194,490			(26	)
Total sales volumes, BOE	1,362,223			1,594,690			(15	)	3,108,126			3,282,464			(5	)

Total sales volumes, BOEPD	14,970			17,524			(15	)	17,172			18,135			(5	)

Average Prices

Oil and NGL's per bbl	$	51.18		$	93.72		(45	)	$	47.03		$	91.74		(49	)
Natural gas per Mcf	$	3.78		$	4.01		(6	)	$	3.82		$	4.79		(20	)

Consolidated Results of Operations per BOE sales volumes

Oil and natural gas sales	$	50.91		$	92.74		(45	)	$	46.84		$	91.09		(49	)
Interest income	0.28			0.40			(30	)	0.26			0.42			(38	)
	51.19			93.14			(45	)	47.10			91.51			(49	)

Operating expenses	17.72			15.89			12		17.88			14.38			24



DD&A expenses	51.00			26.30			94		50.07			26.26			91
G&A expenses	7.56			8.74			(14	)	5.66			8.16			(31	)
Severance expenses	1.46			—			—		2.05			—			—
Equity tax	—			—			—		1.21			—			—
Foreign exchange loss (gain)	2.18			6.30			(65	)	(2.76		)	1.78			(255	)
Financial instruments gain	(1.00		)	(1.63		)	39		(0.45		)	(1.53		)	71
	78.92			55.60			42		73.66			49.05			50

(Loss) income from continuing operations before income taxes	(27.73		)	37.54			(174	)	(26.56		)	42.46			(163	)
Current income tax expense	(4.17		)	(16.91		)	(75	)	(2.61		)	(17.96		)	(85	)
Deferred income tax recovery (expense)	3.58			(0.89		)	(502	)	2.33			0.26			(796	)
	(0.59		)	(17.80		)	(97	)	(0.28		)	(17.70		)	(98	)
(Loss) income from continuing operations	$	(28.32	)	$	19.74		(243	)	$	(26.84	)	$	24.76		(208	)

⁽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 six months ended June 30, 2015, and 2,426 BOEPD and 2,744 BOEPD for the corresponding periods in 2014. Discontinued operations sales volumes for the three and six months ended June 30, 2014, were calculated to the date of sale of June 25, 2014.

Oil and gas production and sales volumes, BOEPD



	Three Months Ended June 30, 2015						Three Months Ended June 30, 2014
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	22,601		493		23,094		25,117		1,144		26,261
Royalties	(4,531	)	(69	)	(4,600	)	(6,253	)	(151	)	(6,404	)
Production NAR	18,070		424		18,494		18,864		993		19,857
Inventory Adjustments and Losses	(3,503	)	(21	)	(3,524	)	(2,320	)	(13	)	(2,333	)
Sales	14,567		403		14,970		16,544		980		17,524
	Six Months Ended June 30, 2015						Six Months Ended June 30, 2014
Average Daily Volumes (BOEPD)	Colombia		Brazil		Total		Colombia		Brazil		Total
Working Interest Production Before Royalties	22,947		605		23,552		24,741		1,015		25,756
Royalties	(4,157	)	(83	)	(4,240	)	(6,172	)	(139	)	(6,311	)
Production NAR	18,790		522		19,312		18,569		876		19,445
Inventory Adjustments and Losses	(2,145	)	5		(2,140	)	(1,293	)	(17	)	(1,310	)
Sales	16,645		527		17,172		17,276		859		18,135

Oil and gas production NAR for the three and six months ended June 30, 2015, decreased by 7% to 18,494 BOEPD, and by 1% to 19,312 BOEPD, respectively, compared with 19,857 BOEPD and 19,445 BOEPD, respectively, in the corresponding periods in 2014. In the three months ended June 30, 2015, production from new wells in the Moqueta field was offset by the impact of field production declines on the Costayaco field and the impact of a water cut increase on the Juanambu field. Production during the three and six months ended June 30, 2015, reflected approximately 27 and 37 days, respectively, of oil delivery restrictions in Colombia compared with 41 and 92 days, respectively, in the corresponding periods in 2014. Additionally, 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.

Oil and gas sales volumes for the three and six months ended June 30, 2015, decreased by 15% to 14,970 BOEPD, and by 5% to 17,172 BOEPD, respectively, compared with 17,524 BOEPD and 18,135 BOEPD, respectively, in the corresponding periods in 2014. During the three and six months ended June 30, 2015, oil inventory increases accounted for 0.3 MMbbl or 3,524 bopd, and 0.4 MMbbl or 2,140 bopd, of reduced sales volumes, respectively, compared with oil inventory increases which accounted for 0.2 MMbbl or 2,333 bopd, and 0.2 MMbbl or 1,310 bopd, of reduced sales volumes in the corresponding periods in 2014. The increase in oil inventory was primarily a result of OTA pipeline disruptions. All inventory was sold in July 2015.

Operating netbacks



	Three Months Ended June 30, 2015									Three Months Ended June 30, 2014
(Thousands of U.S. Dollars)	Colombia			Brazil			Total			Colombia			Brazil			Total
Oil and gas sales	$	67,627		$	1,723		$	69,350		$	139,350		$	8,538		$	147,888
Operating expenses	(21,269		)	(2,864		)	(24,133		)	(23,281		)	(2,065		)	(25,346		)
Operating netback⁽¹⁾	$	46,358		$	(1,141	)	$	45,217		$	116,069		$	6,473		$	122,542

U.S. Dollars Per BOE
Brent							$	61.70								$	109.70

WTI							$	57.87								$	102.99

Oil and gas sales	$	51.02		$	46.92		$	50.91		$	92.56		$	95.70		$	92.74
Operating expenses	(16.05		)	(78.00		)	(17.72		)	(15.46		)	(23.15		)	(15.89		)
Operating netback⁽¹⁾	$	34.97		$	(31.08	)	$	33.19		$	77.10		$	72.55		$	76.85

	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
(Thousands of U.S. Dollars)	Colombia			Brazil			Total			Colombia			Brazil			Total
Oil and gas sales	$	141,694		$	3,887		$	145,581		$	284,285		$	14,708		$	298,993
Operating expenses	(51,243		)	(4,324		)	(55,567		)	(43,486		)	(3,726		)	(47,212		)
Operating netback⁽¹⁾	$	90,451		$	(437	)	$	90,014		$	240,799		$	10,982		$	251,781

U.S. Dollars Per BOE

Brent							$	57.81								$	108.93

WTI							$	53.25								$	100.84

Oil and gas sales	$	47.03		$	40.77		$	46.84		$	90.92		$	94.56		$	91.09
Operating expenses	(17.01		)	(45.36		)	(17.88		)	(13.91		)	(23.96		)	(14.38		)
Operating netback⁽¹⁾	$	30.02		$	(4.59	)	$	28.96		$	77.01		$	70.60		$	76.71

(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 six months ended June 30, 2015, decreased by 53% to $69.4 million and by 51% to $145.6 million, respectively, from $147.9 million and $299.0 million, respectively, in the comparable periods in 2014 due to the effect of decreased realized oil prices and lower sales volumes.

Average realized prices decreased by 45% to $50.91 per BOE for the three months ended June 30, 2015, from $92.74 per BOE in the comparable period in 2014, and decreased by 49% to $46.84 per BOE for the six months ended June 30, 2015, from $91.09 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 six months ended June 30, 2015, were $61.70 and $57.81 per bbl, respectively, compared with $109.70 and $108.93 per bbl, respectively, in the corresponding periods in 2014. Average WTI oil prices for the three and six months ended June 30, 2015, were $57.87 and $53.25 per bbl, respectively, compared with $102.99 and $100.84

per bbl, respectively, in the corresponding period in 2014. Additionally, beginning July 1, 2014, the port operations fee component of the Trans-Andean oil pipeline ("OTA pipeline”) pricing structure increased by $2.94 per bbl resulting in a reduction of realized oil prices by this amount on sales delivered through the OTA pipeline.

During periods of OTA pipeline disruptions we use transportation alternatives. These sales have varying effects on realized prices and transportation costs. During the three and six months ended June 30, 2015, 25% and 22%, respectively, of our oil volumes sold in Colombia, were through these transportation alternatives compared with 51% and 55%, respectively, in the corresponding periods in 2014. The effect on the Colombian realized price for the three and six months ended June 30, 2015, was a decrease of approximately $0.37 and $0.05 per BOE, respectively, as compared with delivering all of our oil through the OTA pipeline. This compares with a reduction of approximately $7.24 and $8.12 per BOE, respectively, in the comparable periods in 2014.

Operating expenses decreased by 5% to $24.1 million, and increased by 18% to $55.6 million, respectively, for the three and six months ended June 30, 2015, compared with the corresponding periods in 2014. In the three months ended June 30, 2015, the decrease in operating expenses was primarily due to the effect of lower sales volumes partially offset by increased operating costs per BOE. In the six months ended June 30, 2015, increased operating costs per BOE were partially offset by lower sales volumes.

On a per BOE basis, operating expenses increased by 12% to $17.72, and by 24% to $17.88, respectively, for the three and six months ended June 30, 2015, from $15.89 and $14.38 in the comparable periods in 2014. The increase in operating expenses per BOE was primarily due to higher transportation costs in Colombia of $2.15 and $2.43 per BOE, respectively, associated with higher sales using the OTA pipeline which carried higher transportation costs instead of the realized price reductions that we incur with some alternative customers. The increase in Colombian transportation costs was partially offset by other Colombian operating cost savings. Additionally, in the six months ended June 30, 2015, workover expenses were $1.78 per BOE higher than in the corresponding period in 2014.

In Brazil, in the three months ended June 30, 2015, we incurred $1.7 million, or $45.32 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 February 2015.

DD&A expenses



	Three Months Ended June 30, 2015				Three Months Ended June 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	$	37,061	$	27.96	$	39,348	$	26.14
Brazil	26,575		$	723.72	2,241		$	25.12
Peru	5,432		$	—	103		$	—
Corporate	405		$	—	245		$	—
	$	69,473	$	51.00	$	41,937	$	26.30

	Six Months Ended June 30, 2015				Six Months Ended June 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	$	83,316	$	27.65	$	80,598	$	25.78
Brazil	33,169		$	347.93	4,820		$	30.99
Peru	38,380		$	—	311		$	—
Corporate	762		$	—	472		$	—
	$	155,627	$	50.07	$	86,201	$	26.26

DD&A expenses for the three and six months ended June 30, 2015, increased by 66% to $69.5 million ($51.00 per BOE) and by 81% to $155.6 million ($50.07 per BOE), respectively, from $41.9 million ($26.30 per BOE) and $86.2 million ($26.26 per BOE), respectively, in the comparable periods in 2014. DD&A expenses for the three and six months ended June 30, 2015,

included $25.0 million and $29.3 million, respectively, of ceiling test impairment losses in our Brazil cost center due to lower oil prices, and $5.3 million and $38.0 million, respectively, of impairment charges in our Peru cost center relating to costs incurred on Block 95. These 2015 impairment losses were partially offset by the effect of lower sales volumes.

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.

G&A expenses



	Three Months Ended June 30,								Six Months Ended June 30,
(Thousands of U.S. Dollars)	2015			2014			% Change		2015			2014			% Change
G&A Expenses Before Stock-Based Compensation, Gross	$	17,288		$	24,504		(29	)	$	37,551		$	48,001		(22	)
Stock-Based Compensation	1,540			1,957			(21	)	1,010			4,100			(75	)
Capitalized G&A and Overhead Recoveries	(8,530		)	(12,529		)	(32	)	(20,969		)	(25,306		)	(17	)
	$	10,298		$	13,932		(26	)	$	17,592		$	26,795		(34	)
U.S. Dollars Per BOE
G&A Expenses Before Stock-Based Compensation, Gross	$	12.69		$	15.37		(17	)	$	12.08		$	14.62		(17	)
Stock-Based Compensation	1.13			1.23			(8	)	0.32			1.25			(74	)
Capitalized G&A and Overhead Recoveries	(6.26		)	(7.86		)	(20	)	(6.75		)	(7.71		)	(12	)
	$	7.56		$	8.74		(14	)	$	5.66		$	8.16		(31	)

G&A expenses for the three and six months ended June 30, 2015, decreased by 26% to $10.3 million ($7.56 per BOE), and by 34% to $17.6 million ($5.66 per BOE), respectively, from $13.9 million ($8.74 per BOE) and $26.8 million ($8.16 per BOE), 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 to 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. These G&A expense reductions were partially offset by lower allocations to capital projects due to lower capital activity. Additionally, G&A expenses in the six months ended June 30, 2015, were net of a credit of $1.7 million relating to the reversal of stock-based compensation expense for unvested options and RSUs associated with terminated employees.

G&A expenses per BOE in the three and six months ended June 30, 2015, of $7.56 and $5.66, respectively, were 14% and 31% lower compared with the corresponding periods in 2014 for the same reasons, partially offset by the effect of lower sales volumes.

Severance expenses

For the three and six months ended June 30, 2015, severance expenses were $2.0 million and $6.4 million 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.

Equity tax expense

For the six months ended June 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 six months ended June 30, 2015, we had a foreign exchange loss of $3.0 million and a foreign exchange gain of $8.6 million, respectively. For the three months ended June 30, 2015, we had realized foreign exchange losses of $2.4 million and an unrealized non-cash foreign exchange loss of $0.6 million. For the six months ended June 30, 2015, we had realized foreign exchange gains of $0.2 million and an unrealized non-cash foreign exchange gain of $8.4 million. Unrealized foreign exchange losses and gains are primarily a result of a net monetary liability position in Colombia and the strengthening and weakening of Colombian Peso versus U.S. dollar. 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 is the main source of the unrealized foreign exchange losses or gains. The Colombian peso weakened by 0.4% and strengthened by 4% against the U.S. dollar in the three months ended June 30, 2015, and 2014, respectively, and weakened by 8% and strengthened by 2% against the U.S. dollar in the six months ended June 30, 2015, and 2014, respectively.

For the three and six months ended June 30, 2014, we had foreign exchange losses of $10.0 million and $5.8 million, respectively. For the three months ended June 30, 2014, we had an unrealized non-cash foreign exchange loss of $8.7 million and realized foreign exchange losses of $1.3 million. For the six months ended June 30, 2014, we had $4.6 million of unrealized non-cash foreign exchange losses and realized foreign exchange losses of $1.2 million.

Financial instrument gains and losses



	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of U.S. Dollars)	2015			2014			2015			2014
Trading securities gain	$	(1,688	)	$	(339	)	$	(2,100	)	$	(339	)
Foreign currency derivatives loss (gain)	322			(2,265		)	692			(4,674		)
	$	(1,366	)	$	(2,604	)	$	(1,408	)	$	(5,013	)

Trading securities gains related to unrealized gains on the Madalena Energy Inc. shares we received in connection with the sale of our Argentina business unit in June 2014. Foreign currency derivative gains and losses related to our Colombian peso non-deliverable forward contracts. We purchased these contracts for purposes of fixing the exchange rate at which we would purchase or sell Colombian pesos to settle our income tax installments and payments. At June 30, 2015, we did not have any open foreign currency derivative positions.

For the three months ended June 30, 2015, financial instruments gains of $1.4 million included $2.8 million of unrealized financial instruments gains which were partially offset by $1.4 million of realized financial instrument losses. In the six months ended June 30, 2015, financial instruments gains of $1.4 million included $5.2 million of unrealized financial instrument gains which were partially offset by $3.8 million of realized financial instrument losses.

For the three months ended June 30, 2014, financial instruments gains of $2.6 million included $4.7 million of realized financial instruments gains which were partially offset by $2.1 million of unrealized financial instrument losses. For the six months ended June 30, 2014, financial instruments gains of $5.0 million included $4.7 million of realized financial instruments gains and unrealized financial instruments gains of $351 thousand.

Income tax expense

For the three and six months ended June 30, 2015, income tax expense was $0.8 million and $0.9 million, respectively, compared with income tax expense of $28.4 million and $58.1 million, respectively, in the corresponding periods in 2014. The decrease in the income tax expense for the three and six months ended June 30, 2015, compared with the corresponding period in 2014 was primarily due to lower taxable income.

The effective tax rate was (1.1)% in the six months ended June 30, 2015, compared with 41.7% in the comparable period in 2014. In the six months ended June 30, 2015, we had income tax expense despite having loss from continuing operations. The change in the effective tax rate for the six months ended June 30, 2015, was also due to lower foreign currency translation adjustments, impact of foreign taxes, stock-based compensation, non-deductible third party royalty in Colombia and other

permanent differences. These amounts were partially offset by an increase in valuation allowances, which was largely attributable to the 2015 impairment losses.

For the six months ended June 30, 2015, the difference between the effective tax rate of (1.1)% and the 35% U.S. statutory rate was primarily due to other local taxes, an increase in the valuation allowance and the non-deductible third party royalty in Colombia, which were partially offset by the impact of foreign taxes and other permanent differences. The variance from the 35% U.S. statutory rate for the six months ended June 30, 2014, was primarily attributable to other local taxes, stock-based compensation, the non-deductible third party royalty in Colombia and other permanent differences, which were partially offset by the impact of foreign taxes.

Loss from discontinued operations, net of income taxes

For the three and six months ended June 30, 2015, loss from discontinued operations, net of income taxes, was $nil compared with $22.3 million and $27.0 million, in the corresponding periods in 2014. We sold our Argentina business unit on June 25, 2014, and results for the three and six months ended June 30, 2014, included the loss on disposal of the Argentina business unit of $19.3 million.

Funds flow from continuing operations

For the three and six months ended June 30, 2015, funds flow from continuing operations decreased by 71% to $24.4 million and decreased by 71% to $50.0 million, respectively, compared with the corresponding periods in 2014. For the three months ended June 30, 2015, decreased oil and natural gas sales, higher DD&A expenses, severance expenses, realized financial instrument losses and higher realized foreign exchange losses were partially offset by decreased operating, G&A and income tax expenses. For the six months ended June 30, 2015, decreased oil and natural gas sales, higher operating and DD&A expenses, severance and equity tax expenses and realized financial instruments losses were only 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 fluctuations in oil prices and pipeline disruptions in Colombia. Oil prices are volatile and unpredictable and are influenced by concerns about the quantity of world supply and demand, market competition between large suppliers to the market 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 current operations, 2015 capital expenditure program and planned share repurchase program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including additional pipeline delivery restrictions in Colombia or another sharp downturn in oil and gas prices, we would examine measures such as further 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, unstable conditions in the Middle East, North Africa and Eastern Europe and the current over supply of oil in world markets, the oil price environment is unpredictable and unstable. We are unable to determine the impact, if any, these events may have on oil prices and demand. The timing and execution of our capital expenditure program are also affected by the availability of services from third party oil field contractors and our ability to obtain, sustain or renew necessary government licenses and permits on a timely basis to conduct exploration and development activities. Any delay may affect our ability to execute our capital expenditure program.

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

Our future growth and acquisitions may depend on our ability to raise additional funds through equity and debt 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 would further 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 six months ended June 30, 2015, were $91.8 million compared with $173.4 million for the six months ended June 30, 2014. In 2015, these capital expenditures included drilling of $36.5 million, geological and geophysical (“G&G”) of $26.1 million, facilities of $25.8 million and other expenditures of $3.4 million.

As announced on June 24, 2015, our planned 2015 capital program has been increased to $185 million from $140 million and includes $115 million for Colombia, $49 million for Peru, $20 million for Brazil and $1 million associated with corporate activities. The capital spending program allocates $97 million for drilling, $45 million for facilities, pipelines and other and $43 million for G&G expenditures.

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 June 30, 2015, were $8.1 million bringing total capital expenditures for the six months ended June 30, 2015, to $29.5 million. The following table provides a breakdown of capital expenditures in 2015 and 2014:



	Three Months Ended June 30,					Six Months Ended June 30,
(Thousands of U.S. Dollars)	2015			2014		2015		2014
Drilling and completions	$	3,132		$	25,715	$	14,205	$	56,330
G&G	1,276			8,848		7,321		19,915
Facilities and equipment	3,892			7,316		7,075		13,546
Other	(213		)	3,809		853		6,440
	$	8,087		$	45,688	$	29,454	$	96,231

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


•	On the Chaza Block (100% working interest ("WI"), operated), we incurred costs drilling the Moqueta-18i development well which encountered mechanical difficulties. The well is currently suspended pending the results of injectivity testing at the Zapotero-1 well, which is interpreted to be in the same fault compartment as Moqueta 18i (the Moqueta South Block).


•	We continued processing and interpretation of 2-D seismic on the Cauca-7 (100% WI, operated) and Sinu-3 (51% WI, operated) Blocks. We also commenced environmental impact assessments ("EIA"s) for future drilling on the Sinu-3 Block.


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

Outlook - Colombia

The 2015 capital program in Colombia is $115 million with $70 million allocated to drilling, $21 million to facilities and pipelines and $24 million for G&G expenditures.

Our planned capital program for the remainder of 2015 in Colombia includes drilling six development wells on the Chaza Block and two development wells on the Garibay Block. Additionally, we plan to continue the interpretation and processing of

2-D seismic on the Cauca-7 and Sinu-3 Blocks. 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 June 30, 2015, were $2.5 million, bringing total capital expenditures for the six months ended June 30, 2015, to $16.4 million. Capital expenditures in the three months ended June 30, 2015, consisted of drilling and other expenditures of $0.3 million, G&G expenditures of $0.2 million and facilities of $2.0 million

Our second quarter 2015 capital program in Brazil included:


•	On Block REC-T-155 (100% WI, operated), we continued construction of an infield gas pipeline between the Tiê facilities and 3-GTE-03-BA.


•	On Blocks REC-T-86, Block REC-T-117 and Block REC-T-118 (100% WI, operated)), we completed processing of 3-D seismic. Interpretation is ongoing.

Outlook – Brazil

The 2015 capital program in Brazil is $20 million with $4 million allocated to drilling, $5 million to facilities and pipelines and $11 million for G&G and other expenditures.

Our planned capital program for the remainder of 2015 in Brazil includes continued work on 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 temporary suspension of the PAD phase. The temporary suspension is valid until the ANP Board of Directors makes a final decision on our request for suspension of the PAD phase.

Capital Program – Peru

Capital expenditures in our Peruvian segment for the three months ended June 30, 2015, were $6.9 million, bringing total capital expenditures for the six months ended June 30, 2015, to $44.9 million. In the three months ended June 30, 2015, capital expenditures included $5.3 million on Block 95 and $1.6 million on our other blocks in Peru and consisted of drilling of $0.6 million, facilities expenditures of $2.9 million, and G&G expenditures and other expenditures of $3.4 million.

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


•	On Block 95 (100% WI, operated), we incurred contract termination fees associated with the decision not to proceed with the long-term test, restocking fees associated with the cancellation of a multi-lateral trial well, and asset retirement obligation cost estimate revisions.


•	On Block 107 (100% WI, operated), we continued interpretation and processing of 2-D seismic.

Outlook - Peru

The 2015 capital program in Peru is $49 million with $23 million allocated to drilling primarily for the Bretaña Sur 95-3-4-1X appraisal well on the L4 lobe on the Bretaña field, $18 million for facilities and $8 million for G&G expenditures. The budgeted Bretaña Sur 95-3-4-1X appraisal well drilling costs were primarily incurred in January and February 2015.

During the three months ended June 30, 2015, we further reduced our headcount in Peru to less than 30 people to secure our assets, continue geologic and engineering studies and consider/investigate alternatives to fund future exploration drilling, appraisal and development activities on our portfolio of opportunities. Our planned capital program for the remainder of 2015 in Peru includes activities related to suspending and securing the L4 well location on Block 95. On Blocks 107 and 133, we plan to continue pre-consultation and environmental permitting processes.

Liquidity and Capital Resources

At June 30, 2015, we had cash and cash equivalents of $166.4 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, HSBC Bank plc., 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 June 30, 2015, 82% 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 the 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 June 30, 2015, one of our subsidiaries had a credit facility with a syndicate of banks, led by Wells Fargo Bank National Association as administrative agent. This reserve-based facility has a current borrowing base of $150 million and a maximum borrowing base that is dependent on the value of our reserves as assessed by the banking syndicate, but in no case would be more than $300 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 and our subsidiary in Brazil. Amounts drawn down under the facility bear interest at the U.S. dollar LIBOR rate plus a margin ranging between 2.25% and 3.25% per annum depending on the rate of borrowing base utilization. In addition, a stand-by fee of 0.875% per annum is charged on the unutilized balance of the committed borrowing base and is included in G&A expenses. The credit facility was entered into on August 30, 2013, and became effective on October 31, 2013, for a three-year term. Under the terms of the facility, we are required to maintain and were in compliance with certain financial and operating covenants. Under the terms of the credit facility, we cannot pay any dividends to our shareholders if we are in default under the facility and, if we are not in default, we are required to obtain bank approval for any dividend payments exceeding $2.0 million in any fiscal year. No amounts have been drawn on this facility.

Cash Flows

During the six months ended June 30, 2015, our cash and cash equivalents decreased by $165.4 million as a result of cash used in investing activities of $168.7 million, partially offset by cash provided by operating activities of $2.7 million and cash provided by financing activities of $0.6 million. During the six months ended June 30, 2014, our cash and cash equivalents decreased by $96.4 million as a result of cash used in investing activities of $127.4 million (including $12.4 million of cash used for 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 $23.9 million (including $4.8 million of cash used in operating activities of discontinued operations) and cash provided by financing activities of $7.1 million.

Cash provided by operating activities in the six months ended June 30, 2015, was primarily affected by decreased oil and natural gas sales, higher operating expenses, severance and equity tax expenses and realized financial instruments losses and a $47.3 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 $23.7 million primarily due to lower oil and gas sales; inventory increased by $7.7 million primarily due to higher inventory volumes as a result of the timing of revenue recognition; accounts payable and accrued liabilities decreased by $21.1 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 $44.3 million primarily due to lower current income taxes for 2015 in Colombia.

Cash used in investing activities in the six months ended June 30, 2015, included capital expenditures incurred during the six months ended June 30, 2015, of $91.8 million ($29.5 million in Colombia, $44.9 million in Peru, and $16.4 million in Brazil and $1.0 million Corporate), $76.6 million of net cash outflows related to changes in assets and liabilities associated with

investing activities ($56.2 million outflow in Colombia, $18.6 million outflow in Peru, and a $1.8 million outflow in Brazil and Corporate), and an increase in restricted cash of $0.3 million. Cash used in investing activities of continuing operations in the six months ended June 30, 2014, included capital expenditures incurred of $173.4 million, partially offset by $15.3 million of net cash inflows related to changes in assets and liabilities associated with investing activities and a decrease in restricted cash of $0.4 million.

Cash provided by financing activities in the six months ended June 30, 2015 and 2014, related to proceeds from issuance of shares of our Common Stock upon the exercise of stock options.

Off-Balance Sheet Arrangements

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

Contractual Obligations

As at June 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.

Holding all factors constant, it is reasonably likely that we will experience ceiling test impairment losses in our Brazil and Colombia cost centers in the third and fourth quarters 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, reserve additions, and tax attributes.

Holding all other factors constant other than benchmark oil prices, a $1.00 per bbl change in benchmark oil prices would result in changes to after tax cash flows of approximately $12.0 million and $1.6 million, respectively, in Colombia and Brazil. 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 and the income tax calculation. In Brazil, foreign exchange rates can materially impact operating costs and the income tax calculation.

Holding all factors constant, we do not expect any downward adjustment to our consolidated NAR reserve volumes during 2015. The exploitation periods for our major fields exceed the reserve life of the properties which allows the reserves to be developed prior to contract expiry, even in the case of a short to medium term deferral of development expenditures. Furthermore, as disclosed in our press release on June 24, 2015, we increased our planned 2015 capital budget in Colombia by $55 million and the 2015 capital investment is expected to be consistent with the proposed capital investment included in our reserve report dated December 31, 2014 (the “2014 Reserves Report”). In Brazil, the 2015 facilities capital budgeted included in the 2014 Reserves Report, has already been incurred. Additionally, in Colombia, the effect of prolonged low oil prices on NAR reserves is to increase reserves due to the lower rate at which cash royalties are levied in low oil price environments. In a continued low oil price environment, we expect that a loss of less than one 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.

In accordance with the transportation agreement with the pipeline operator, fees are negotiated every six months, and negotiations are currently ongoing. However, negotiations have not yet progressed to a stage such that we can predict the outcome of these negotiations and, as a result, it is impractical to provide a quantitative analysis of the effects of potential changes in these estimates. Depending upon the magnitude and what transportation strategy we would ultimately choose as a result, a fee increase could potentially increase ceiling test impairments in future periods.

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 and many other market factors outside of our control. Oil prices started falling in September 2014 and have

fallen dramatically during the period December 2014 to March 2015, remaining at relatively low levels through June 30, 2015. 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 $60,000 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 June 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 Energy Inc. ("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 $9.7 million at June 30, 2015, and represented approximately 5.5% of Madalena's outstanding shares

at June 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 June 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 June 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 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, and Part I, Item 2 above regarding proposed pipeline tariff increases. The risks facing our company have not changed substantively 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, except as set forth in Part I, Item 2 above regarding proposed pipeline tariff increases.

Item 6. Exhibits

See Index to Exhibits at the end of this Report, 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: August 4, 2015		/s/ Gary Guidry
		By: Gary Guidry
		President and Chief Executive Officer
		(Principal Executive Officer)



Date: August 4, 2015		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

EXHIBIT INDEX



Exhibit No.	Description	Reference
2.1	Arrangement Agreement, dated as of July 28, 2008, by and among Gran Tierra Energy Inc., Solana Resources Limited and Gran Tierra Exchangeco Inc.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on August 1, 2008 (SEC File No. 001-34018).

2.2	Amendment No. 2 to Arrangement Agreement, which supersedes Amendment No. 1 thereto and includes the Plan of Arrangement, including appendices.	Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form S-3, filed with the SEC on October 10, 2008 (SEC File No. 333-153376).

2.3	Arrangement Agreement, dated January 17, 2011, by and between Gran Tierra Energy Inc. and Petrolifera Petroleum Limited. +	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on January 21, 2011 (SEC File No. 001-34018).

2.4	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).

2.5	Share Purchase and Sale Offer, dated May 29, 2014, by Gran Tierra Energy Inc., an Alberta corporation, 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	Amended and Restated Articles of Incorporation.	Incorporated by reference to Exhibit 3.1 to the Annual Report on Form 10-K, filed with the SEC on February 26, 2014 (SEC File No. 001-34018).

3.2	Amended and Restated Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on February 26, 2014 (SEC File No. 001-34018).

4.1	Reference is made to Exhibits 3.1 to 3.2.

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

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

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

10.1	Amendment to Executive Employment Agreement dated May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Jeffrey Scott	Filed herewith.

10.2	Amendment to Executive Employment Agreement dated May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Duncan Nightingale	Filed herewith.

10.3	Amendment to Executive Employment Agreement dated May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and James Rozon	Filed herewith.

10.4	Amendment to Executive Employment Agreement dated May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and David Hardy	Filed herewith.



10.5	Description of terms of employment with Gary Guidry and Ryan Ellson	Incorporated by reference to Item 5.02 of the Current Report on Form 8-K, filed with the SEC on May 13, 2015 (SEC File No. 001-34018).]

10.6	Settlement Agreement, dated May 7, 2015, between Gran Tierra Energy Inc. and West Face SPV (Cayman) I, L.P.	Filed herewith.

10.7	Form of Indemnity Agreement for use with Directors and Executive Officers	Filed herewith.

31.1	Certification of Principal Executive Officer.	Filed herewith.

31.2	Certification of Principal Financial Officer.	Filed herewith.

32.1	Section 1350 Certifications.	Filed 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.