Edgar Filing: GRAN TIERRA ENERGY INC.

GTE - 2015.03.31 - 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 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 May 1, 2015, the following number of shares of the registrant’s capital stock were outstanding: 277,210,589 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 5,542,618 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

Three Months Ended March 31, 2015

Table of contents



		Page
PART I	Financial Information
Item 1.	Financial Statements	8
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	42

PART II	Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 6.	Exhibits	59
SIGNATURES		59
EXHIBIT INDEX		61

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	Mcf	thousand cubic feet
Mbbl	thousand barrels	MMcf	million cubic feet
MMbbl	million barrels	Bcf	billion cubic feet
bopd	barrels of oil per day	MMBtu	million British thermal units
BOE	barrels of oil equivalent	NGL	natural gas liquids
MMBOE	million barrels of oil equivalent	NAR	net after royalty
BOEPD	barrels of oil equivalent per day

Production represents production volumes NAR adjusted for inventory changes and losses. Our oil and gas reserves are also reported NAR.

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.

In the discussion that follows we discuss our interests in wells and/or acres in gross and net terms. Gross oil and natural gas wells or acres refer to the total number of wells or acres in which we own a working interest. Net oil and natural gas wells or acres are determined by multiplying gross wells or acres by the working interest that we own in such wells or acres. Working interest refers to the interest we own in a property, which entitles us to receive a specified percentage of the proceeds of the sale of oil and natural gas, and also requires us to bear a specified percentage of the cost to explore for, develop and produce that oil and natural gas. A working interest owner that owns a portion of the working interest may participate either as operator, or by voting its percentage interest to approve or disapprove the appointment of an operator, in drilling and other major activities in connection with the development of a property.

We also refer to royalties and farm-in or farm-out transactions. Royalties include payments to governments on the production of oil and gas, either in kind or in cash. Royalties also include overriding royalties paid to third parties. Our reserves, production volumes and sales are reported net after deduction of royalties. As noted above, production volumes are also reported net of inventory adjustments and losses. Farm-in or farm-out transactions refer to transactions in which a portion of a working interest is sold by an owner of an oil and gas property. The transaction is labeled a farm-in by the purchaser of the

working interest and a farm-out by the seller of the working interest. Payment in a farm-in or farm-out transaction can be in cash or in kind by committing to perform and/or pay for certain work obligations.

In the petroleum industry, geologic settings with proven petroleum source rocks, migration pathways, reservoir rocks and traps are referred to as petroleum systems.

Several items that relate to oil and gas operations, including aeromagnetic and aerogravity surveys, seismic operations and several kinds of drilling and other well operations, are also discussed in this document.

Aeromagnetic and aerogravity surveys are a remote sensing process by which data is gathered about the subsurface of the earth. An airplane is equipped with extremely sensitive instruments that measure changes in the earth's gravitational and magnetic field. Variations as small as 1/1,000th in the gravitational and magnetic field strength and direction can indicate structural changes below the ground surface. These structural changes may influence the trapping of hydrocarbons. These surveys are an efficient way of gathering data over large regions.

Seismic data is used by oil and natural gas companies as the principal source of information to locate oil and natural gas deposits, both for exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computer software applications are then used to process the raw data to develop an image of underground formations. 2-D seismic is the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data. 3-D seismic data is collected using a grid of energy sources, which are generally spread over several square miles. A 3-D seismic survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is generally considered a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated.

Wells drilled are classified as exploration, development, injector or stratigraphic. An exploration well is a well drilled in search of a previously undiscovered hydrocarbon-bearing reservoir. A development well is a well drilled to develop a hydrocarbon-bearing reservoir that is already discovered. Exploration and development wells are tested during and after the drilling process to determine if they have oil or natural gas that can be produced economically in commercial quantities. If they do, the well will be completed for production, which could involve a variety of equipment, the specifics of which depend on a number of technical geological and engineering considerations. If there is no oil or natural gas (a “dry” well), or there is oil and natural gas but the quantities are too small and/or too difficult to produce, the well will be abandoned. Abandonment is a completion operation that involves closing or “plugging” the well and remediating the drilling site. An injector well is a development well that will be used to inject fluid into a reservoir to increase production from other wells. A stratigraphic well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. These wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if drilled in an unknown area or “development type” if drilled in a known area.

Workover is a term used to describe remedial operations on a previously completed well to clean, repair and/or maintain the well for the purpose of increasing or restoring production. It could include well deepening, plugging portions of the well, working with cementing, scale removal, acidizing, fracture stimulation, changing tubulars or installing/changing equipment to provide artificial lift.

The SEC definitions related to oil and natural gas reserves, per Regulation S-X, reflecting our use of deterministic reserve estimation methods, are as follows:

•

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.


•	Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and

government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.


i.	The area of the reservoir considered as proved includes:


A.	The area identified by drilling and limited by fluid contacts, if any; and


B.	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.


ii.	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.


iii.	Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.


iv.	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:


A.	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and


B.	The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.


•	Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.


i.	When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

ii.

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.


iii.	Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.


iv.	See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of section 210.4-10(a) of Regulations S-X.


•	Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.


i.	When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.


ii.	Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.


iii.	Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.


iv.	The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

vi.

Pursuant to paragraph (a)(22)(iii) of section 210.4-10(a) of Regulations S-X, where direct observation has defined a HKO elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

•

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery ("EUR") with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.


•	Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.


•	Probabilistic estimate. The method of estimating reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience, engineering or economic data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.


•	Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:


i.	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; and


ii.	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.


•	Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.


i.	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.


ii.	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

iii.

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of section 201.4-10(a) of Regulation S-X, or by other evidence using reliable technology establishing reasonable certainty.

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 March 31,
	2015			2014
REVENUE AND OTHER INCOME
Oil and natural gas sales	$	76,231		$	151,105
Interest income	421			750
	76,652			151,855
EXPENSES
Operating	31,434			21,866
Depletion, depreciation, accretion and impairment	86,154			44,264
General and administrative	7,294			12,863
Severance (Note 11)	4,378			—
Equity tax (Note 8)	3,769			—
Foreign exchange gain	(11,538		)	(4,210		)
Financial instruments gain (Note 10)	(42		)	(2,409		)
	121,449			72,374

(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(44,797		)	79,481
Income tax expense (Note 8)	(69		)	(29,709		)
(LOSS) INCOME FROM CONTINUING OPERATIONS	(44,866		)	49,772
Loss from discontinued operations, net of income taxes (Note 3)	—			(4,643		)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)	(44,866		)	45,129
RETAINED EARNINGS, BEGINNING OF PERIOD	239,622			410,961
RETAINED EARNINGS, END OF PERIOD	$	194,756		$	456,090

(LOSS) INCOME PER SHARE
BASIC
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.16	)	$	0.18
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			(0.02		)
NET INCOME (LOSS)	$	(0.16	)	$	0.16
DILUTED
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.16	)	$	0.18
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			(0.02		)
NET INCOME (LOSS)	$	(0.16	)	$	0.16
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)	286,194,315			283,235,202
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)	286,194,315			288,636,904

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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



	March 31,		December 31,
	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	203,460	$	331,848
Restricted cash	707		1,836
Accounts receivable	64,825		83,227
Marketable securities (Note 10)	7,998		7,586
Inventory (Note 5)	16,095		17,298
Taxes receivable	8,258		15,843
Prepaids	5,472		6,000
Deferred tax assets (Note 8)	420		1,552
Total Current Assets	307,235		465,190

Oil and Gas Properties (using the full cost method of accounting)
Proved	770,658		801,075
Unproved	334,613		316,856
Total Oil and Gas Properties	1,105,271		1,117,931
Other capital assets	10,890		11,013
Total Property, Plant and Equipment (Note 5)	1,116,161		1,128,944

Other Long-Term Assets
Restricted cash	3,664		2,037
Deferred tax assets (Note 8)	568		601
Taxes receivable	15,035		9,684
Other long-term assets	4,394		5,013
Goodwill	102,581		102,581
Total Other Long-Term Assets	126,242		119,916
Total Assets	$	1,549,638	$	1,714,050
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	44,402	$	112,401
Accrued liabilities	60,330		75,430
Foreign currency derivative (Note 10)	1,070		3,057
Taxes payable	8,844		25,412
Deferred tax liabilities (Note 8)	1,622		1,040
Asset retirement obligation (Note 7)	9,717		8,026
Total Current Liabilities	125,985		225,366

Long-Term Liabilities
Deferred tax liabilities (Note 8)	158,932		175,324
Asset retirement obligation (Note 7)	25,458		27,786
Other long-term liabilities	7,364		8,889
Total Long-Term Liabilities	191,754		211,999

Contingencies (Note 9)
Shareholders’ Equity
Common Stock (Note 6) (277,210,589 and 276,072,351 shares of Common Stock and 9,181,507 and 10,119,745 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2015, and December 31, 2014, respectively)	10,190		10,190
Additional paid in capital	1,026,953		1,026,873
Retained earnings	194,756		239,622
Total Shareholders’ Equity	1,231,899		1,276,685
Total Liabilities and Shareholders’ Equity	$	1,549,638	$	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)



	Three Months Ended March 31,
	2015			2014
Operating Activities
Net income (loss)	$	(44,866	)	$	45,129
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)	—			4,643
Depletion, depreciation, accretion and impairment	86,154			44,264
Deferred tax recovery (Note 8)	(2,356		)	(2,260		)
Non-cash stock-based compensation	(513		)	1,480
Unrealized foreign exchange gain	(9,037		)	(4,178		)
Unrealized financial instruments gain	(2,399		)	(2,409		)
Cash settlement of asset retirement obligation (Note 7)	(1,425		)	—
Net change in assets and liabilities from operating activities of continuing operations
Accounts receivable and other long-term assets	13,484			(53,396		)
Inventory	2,159			(574		)
Prepaids	528			551
Accounts payable and accrued and other long-term liabilities	(22,369		)	(16,812		)
Taxes receivable and payable	(19,983		)	18,461
Net cash (used in) provided by operating activities of continuing operations	(623		)	34,899
Net cash provided by operating activities of discontinued operations	—			1,265
Net cash (used in) provided by operating activities	(623		)	36,164

Investing Activities
(Increase) decrease in restricted cash	(497		)	507
Additions to property, plant and equipment	(127,770		)	(68,159		)
Net cash used in investing activities of continuing operations	(128,267		)	(67,652		)
Net cash used in investing activities of discontinued operations	—			(6,987		)
Net cash used in investing activities	(128,267		)	(74,639		)

Financing Activities
Proceeds from issuance of shares of Common Stock (Note 6)	502			628
Net cash provided by financing activities	502			628

Net decrease in cash and cash equivalents	(128,388		)	(37,847		)
Cash and cash equivalents, beginning of period	331,848			428,800
Cash and cash equivalents, end of period	$	203,460		$	390,953

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	55,335		$	87,859

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Three Months Ended March 31,			Year Ended December 31,
	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)	502			11,137
Stock-based compensation (Note 6)	(422		)	6,976
Balance, end of period	1,026,953			1,026,873

Retained Earnings
Balance, beginning of period	239,622			410,961
Net loss	(44,866		)	(171,339		)
Balance, end of period	194,756			239,622

Total Shareholders’ Equity	$	1,231,899		$	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. Until June 25, 2014, the Company also had business activities in Argentina.

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.

3. Discontinued Operations

On June 25, 2014, the Company, through several of its indirect subsidiaries (the “Selling 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.

The sale was made pursuant to agreements entered into by the Selling Subsidiaries (the “Agreements”); specifically, pursuant to the Agreements: (1) Madalena agreed to acquire from Gran Tierra Argentina Holdings ULC, an Alberta corporation (“GTE ULC”), and PCESA Petroleros Canadienses de Ecuador S.A., an Ecuador corporation (“PCESA”), both indirect subsidiaries of the Company, all of the outstanding shares of the Company’s indirect subsidiaries Gran Tierra Energy Argentina S.R.L. (“GTE Argentina”) and P.E.T.J.A. S.A, and agreed to acquire certain debt owed by GTE Argentina, for (a) approximately $44.8 million in cash, plus certain other adjustments and interest, and (b) shares of Madalena stock valued at $13.9 million; and (2) Madalena agreed to acquire from Gran Tierra Petroco Inc., an Alberta corporation (“Petroco”), an indirect subsidiary of the Company, all of the outstanding shares of the Company’s indirect subsidiary Petrolifera Petroleum Limited (“PPL”), and agreed to acquire certain debt owed by PPL , for approximately $10.6 million in cash, plus certain other adjustments and interest. Collectively, GTE Argentina, P.E.T.J.A. S.A., PPL and PPL’s subsidiaries held all of the assets of Gran Tierra's Argentina business unit.

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 months ended March 31, 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 three months ended March 31, 2014, as cash provided by or used in operating and investing activities of discontinued operations. Amounts for 2014 have been reclassified to conform to the discontinued operations presentation. The reclassifications had no effect on net income (loss).

Revenue and other income and loss from discontinued operations, net of income taxes, for the three months ended March 31, 2014, were as follows:



	Three Months Ended March 31,
(Thousands of U.S. Dollars)		2014
Revenue and other income		$	17,824

Loss from operations of discontinued operations before income taxes		$	(4,172	)
Income tax expense		(471		)
Loss from discontinued operations, net of income taxes		$	(4,643	)

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 March 31, 2015
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Peru			Brazil			All Other			Total
Oil and natural gas sales	$	74,067	$	—		$	2,164		$	—		$	76,231
Interest income	67		—			140			214			421
Depletion, depreciation, accretion and impairment	46,255		32,948			6,594			357			86,154
Depletion, depreciation, accretion and impairment - per unit of production	27.41		—			112.50			—			49.35
Income (loss) from continuing operations before income taxes	2,928		(35,442		)	(6,881		)	(5,402		)	(44,797		)
Segment capital expenditures	21,367		38,034			13,901			719			74,021
	Three Months Ended March 31, 2014
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Peru			Brazil			All Other			Total
Oil and natural gas sales	$	144,935	$	—		$	6,170		$	—		$	151,105
Interest income	137		—			425			188			750
Depletion, depreciation, accretion and impairment	41,250		208			2,579			227			44,264
Depletion, depreciation, accretion and impairment - per unit of production	25.44		—			38.89			—			26.23
Income (loss) from continuing operations before income taxes	86,011		(2,058		)	1,950			(6,422		)	79,481
Segment capital expenditures	50,543		20,893			10,366			299			82,101



	As at March 31, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	863,087	$	92,194	$	155,880	$	5,000	$	1,116,161
Goodwill	102,581		—		—		—		102,581
All other assets	146,540		27,002		8,587		148,767		330,896
Total Assets	$	1,112,208	$	119,196	$	164,467	$	153,767	$	1,549,638

	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 months ended March 31, 2015, the Company had one significant customer in Colombia: Ecopetrol S.A. ("Ecopetrol") which accounted for 79% of the Company's consolidated oil and natural gas sales from continuing operations. In the three months ended March 31, 2014, sales to Ecopetrol accounted for 48% of the Company's consolidated oil and natural gas sales from continuing operations and sales to one other significant customer accounted for 41% of the Company's consolidated oil and natural gas sales from continuing operations.

5. Property, Plant and Equipment and Inventory

Property, Plant and Equipment



	As at March 31, 2015							As at December 31, 2014
(Thousands of U.S. Dollars)	Cost		Accumulated depletion, depreciation and impairment			Net book value		Cost		Accumulated depletion, depreciation and impairment			Net book value
Oil and natural gas properties
Proved	$	1,898,962	$	(1,128,304	)	$	770,658	$	1,876,371	$	(1,075,296	)	$	801,075
Unproved	334,613		—			334,613		316,856		—			316,856
	2,233,575		(1,128,304		)	1,105,271		2,193,227		(1,075,296		)	1,117,931
Furniture and fixtures and leasehold improvements	11,355		(8,236		)	3,119		11,177		(8,421		)	2,756
Computer equipment	15,246		(8,220		)	7,026		14,323		(7,461		)	6,862
Automobiles	1,569		(824		)	745		1,787		(392		)	1,395
Total Property, Plant and Equipment	$	2,261,745	$	(1,145,584	)	$	1,116,161	$	2,220,514	$	(1,091,570	)	$	1,128,944

On February 19, 2015, the Company made the decision to cease all further development expenditures on the Bretaña field on Block 95 in Peru other than what is necessary to maintain tangible asset integrity and security. As a result, in the year ended December 31, 2014, the Company recorded an impairment loss in the Company’s Peru cost center of $265.1 million. This impairment charge related to costs incurred to December 31, 2014, on Block 95. In the three months ended March 31, 2015, the Company recorded an additional impairment loss in its Peru cost center of $32.7 million relating to costs incurred in the first quarter of 2015, on Block 95. Costs incurred in Peru on Block 95 in the three months ended March 31, 2015, comprised: $14.0 million of drilling costs for the Bretaña Sur 95-3-4-1X appraisal well; $6.2 million for the construction of the long-term test facilities, $5.0 million relating to contract termination fees associated with the decision not to proceed with the long-term test,

and $7.5 million of other costs including restocking fees and the front end engineering design study. Total contract termination and restocking fees were $8.7 million.

Depletion and depreciation expense from continuing operations on property, plant and equipment for the three months ended March 31, 2015, was $49.8 million (three months ended March 31, 2014 - $44.3 million). A portion of depletion and depreciation expense was recorded as inventory in each period and adjusted for inventory changes.

In the three months ended March 31, 2015, we recorded a $4.3 million impairment loss in our Brazil cost center related to lower oil prices.

Unproved oil and natural gas properties consist of exploration lands held in Colombia, Peru and Brazil. As at March 31, 2015, the Company had $173.0 million (December 31, 2014 - $170.5 million) of unproved assets in Colombia, $90.8 million (December 31, 2014 - $85.7 million) of unproved assets in Peru, and $70.8 million (December 31, 2014 - $60.7 million) of unproved assets in Brazil for a total of $334.6 million (December 31, 2014 - $316.9 million). Unproved oil and natural gas properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration warrants whether or not future areas will be developed.

Inventory

At March 31, 2015, oil and supplies inventories were $14.5 million and $1.6 million, respectively (December 31, 2014 - $15.2 million and $2.1 million, respectively).

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.

As at March 31, 2015, outstanding share capital consists of 277,210,589 shares of Common Stock of the Company, 5,542,618 exchangeable shares of Gran Tierra Exchangeco Inc., (the "Exchangeco exchangeable shares") and 3,638,889 exchangeable shares of Gran Tierra Goldstrike Inc. (the "Goldstrike exchangeable shares"). The redemption date for the Exchangeco exchangeable shares and the Goldstrike exchangeable shares is a date to be established by the applicable Board of Directors. During the three months ended March 31, 2015, 200,000 shares of Common Stock were issued upon the exercise of stock options, 52,500 shares of Common Stock were issued upon the exchange of the Exchangeco exchangeable shares and 885,738 shares of Common Stock were issued upon the exchange of the Goldstrike exchangeable shares.

The holders of shares of Common Stock are entitled to one vote for each share on all matters submitted to a stockholder vote and are entitled to share in all dividends that the Company’s Board of Directors, in its discretion, declares from legally available funds. The holders of Common Stock have no pre-emptive rights, no conversion rights, and there are no redemption provisions applicable to the shares. Holders of exchangeable shares have substantially the same rights as holders of shares of Common Stock. Each exchangeable share is exchangeable into one share of Common Stock of the Company.

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 three months ended March 31, 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	826,450		2,193,260		2.75
Exercised	(377,254	)	(200,000	)	(2.51	)
Forfeited	(412,893	)	(986,308	)	(6.82	)
Expired	—		(380,665	)	(6.05	)
Balance, March 31, 2015	1,273,266		14,416,507		5.46

For the three months ended March 31, 2015, 200,000 shares of Common Stock were issued for cash proceeds of $0.5 million upon the exercise of stock options (three months ended March 31, 2014 - $0.6 million).

The weighted average grant date fair value for options granted in the three months ended March 31, 2015, was $1.10 (three months ended March 31, 2014 - $2.52).

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



(Thousands of U.S. Dollars)	Three Months Ended March 31,
	2015			2014
Compensation (recovery) costs for stock options	$	(422	)	$	2,016
Compensation (recovery) costs for RSUs	(60		)	1,244
	(482		)	3,260
Less: Stock-based compensation costs capitalized	(31		)	(783		)
Stock-based compensation costs (recovery) expense	$	(513	)	$	2,477

For the three months ended March 31, 2015, stock-based compensation was a recovery of $0.5 million due to the reversal of stock-based compensation expense for unvested options of terminated employees and a decrease in the Company's share price since December 31, 2014. The stock-based compensation recovery for the three months ended March 31, 2015, was primarily recorded in general and administrative ("G&A") expenses. Of the total stock-based compensation expense for the three months ended March 31, 2014, $2.1 million was recorded in G&A expenses, $0.1 million was recorded in operating expenses and $0.3 million was recorded in loss from discontinued operations.

At March 31, 2015, there was $6.1 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 1.7 years.

Income (loss) per share

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



	Three Months Ended March 31,
	2015	2014
Weighted average number of common and exchangeable shares outstanding	286,194,315	283,235,202
Weighted average shares issuable pursuant to stock options	—	14,553,754
Weighted average shares assumed to be purchased from proceeds of stock options	—	(9,152,052	)
Weighted average number of diluted common and exchangeable shares outstanding	286,194,315	288,636,904

For the three months ended March 31, 2015, 13,742,502 options, on a weighted average basis, (three months ended March 31, 2014 - 3,175,152 options) were excluded from the diluted income per share calculation as the options were anti-dilutive.

7. Asset Retirement Obligation

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



	Three Months Ended			Year Ended
(Thousands of U.S. Dollars)	March 31, 2015			December 31, 2014
Balance, beginning of period	$	35,812		$	21,973
Settlements	(1,425		)	(1,137		)
Liability incurred	432			11,956
Liabilities associated with the Argentina business unit sold (Note 3)	—			(10,170		)
Foreign exchange	—			(53		)
Accretion	304			1,406
Revisions in estimated liability	52			11,837
Balance, end of period	$	35,175		$	35,812

Asset retirement obligation - current	$	9,717		$	8,026
Asset retirement obligation - long-term	25,458			27,786
Balance, end of period	$	35,175		$	35,812

Revisions to estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling the asset retirement obligation. At March 31, 2015, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $3.2 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 income tax expense reported differs from the amount computed by applying the U.S. statutory rate to income from continuing operations before income taxes for the following reasons:



	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2015			2014
(Loss) income from continuing operations before income taxes
United States	$	(2,068	)	$	(5,078	)
Foreign	(42,729		)	84,559
	(44,797		)	79,481
	35		%	35		%
Income tax (recovery) expense from continuing operations expected	(15,679		)	27,818
Foreign currency translation adjustments	(1,043		)	(1,714		)
Impact of foreign taxes	334			(921		)
Other local taxes	1,597			842
Stock-based compensation	194			736
Increase in valuation allowance	12,674			3,190
Non-deductible third party royalty in Colombia	927			2,223
Other permanent differences	1,065			(2,465		)
Total income tax expense from continuing operations	$	69		$	29,709

Current income tax expense from continuing operations
United States	$	225		$	357
Foreign	2,200			31,612
	2,425			31,969
Deferred income tax recovery from continuing operations
Foreign	(2,356		)	(2,260		)
Total income tax expense from continuing operations	$	69		$	29,709



	As at
(Thousands of U.S. Dollars)	March 31, 2015			December 31, 2014
Deferred Tax Assets
Tax benefit of operating loss carryforwards	$	49,447		$	51,248
Tax basis in excess of book basis	121,340			108,120
Foreign tax credits and other accruals	19,179			20,369
Tax benefit of capital loss carryforwards	29,445			29,984
Deferred tax assets before valuation allowance	219,411			209,721
Valuation allowance	(218,423		)	(207,568		)
	$	988		$	2,153

Deferred tax assets - current	$	420		$	1,552
Deferred tax assets - long-term	568			601
	988			2,153
Deferred tax liabilities - current	(1,622		)	(1,040		)
Deferred tax liabilities - long-term	(158,932		)	(175,324		)
	(160,554		)	(176,364		)
Net Deferred Tax Liabilities	$	(159,566	)	$	(174,211	)

As at March 31, 2015, the Company had operating loss carryforwards of $163.9 million (December 31, 2014 - $167.0 million) and capital loss carryforwards of $230.6 million (December 31, 2014 – $232.2 million) before valuation allowance. Of these operating loss and capital loss carryforwards, $353.3 million (December 31, 2014 - $356.1 million) were losses generated by the foreign subsidiaries of the Company. In certain jurisdictions, the operating loss carryforwards expire between 2015 and

2035 and the capital loss carryforwards expire between 2016 and 2020, while certain other jurisdictions allow operating and capital losses to be carried forward indefinitely.

As at March 31, 2015, the total amount of Gran Tierra’s unrecognized tax benefit related to continuing operations was $3.2 million (December 31, 2014 - $3.3 million), which if recognized would affect the Company’s effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the interim unaudited condensed consolidated statement of operations.

Changes in the Company's unrecognized tax benefit relating to continuing operations are as follows:



	Three Months Ended March 31,
	2015			2014
(Thousands of U.S. Dollars)
Unrecognized tax benefit relating to continuing operations at beginning of period	$	3,300		$	2,900
Decreases for positions relating to prior year	(100		)	(100		)
Increases for positions relating to prior year	—			500
Unrecognized tax benefit relating to continuing operations at end of period	$	3,200		$	3,300

The Company and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and certain other foreign jurisdictions. The Company is potentially subject to income tax examinations for the tax years 2007 through 2014 in certain jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefit disclosed above within the next twelve months.

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 has 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 March 31, 2015, accounts payable included the unpaid balance of equity tax liability of $3.5 million (December 31, 2014 - $nil) which will be paid in May and September 2015.

As of March 31, 2015, the Company expects to make cash payments of $35.2 million for income and equity taxes in Colombia for the remainder of 2015. Of this amount, $15.8 million was paid in April 2015, $1.8 million is due in May 2015, $15.8 million is due in June 2015 and $1.8 million is due 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. As at March 31, 2015, total cumulative production from the Moqueta Exploitation Area was 4.8 MMbbl. The estimated compensation which would be payable on cumulative production to that date if the ANH's claims are accepted in the arbitration is $65.6 million plus related interest of $21.3 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 $4.2 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 $41.2 million as at March 31, 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 March 31, 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 March 31, 2015, the Company had provided promissory notes totaling $79.4 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 March 31, 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, foreign currency derivatives included in current assets and liabilities and contingent consideration included in other long-term liabilities.

Fair Value Measurement

The fair value of the 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 is determined in accordance with accepted valuation methods.

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



	As at
(Thousands of U.S. Dollars)	March 31, 2015		December 31, 2014
Trading securities	$	7,998	$	7,586

Foreign currency derivative liability	$	1,070	$	3,057
Contingent consideration liability	1,061		1,061
	$	2,131	$	4,118

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



(Thousands of U.S. Dollars)	Three Months Ended March 31,
	2015			2014
Trading securities gain	$	(412	)	$	—
Foreign currency derivatives loss (gain)	370			(2,409		)
	$	(42	)	$	(2,409	)

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 three months ended March 31, 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 March 31, 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 March 31, 2015, and December 31, 2014, the fair value of the foreign currency derivatives was determined using Level 2 inputs. At March 31, 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 is 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 $62,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

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. 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.

At March 31, 2015, the Company had the following open foreign currency derivative positions:



Forward Contracts
Currency	Contract Type	Notional (Millions of Colombian Pesos)	Weighted Average Fixed Rate Received (Colombian Pesos - U.S. Dollars)	Expiration
Colombian pesos	Buy	12,468.2	2,116	April 2015

For the three months ended March 31, 2015, 97% (three months ended March 31, 2014 - 96%) 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 March 31, 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 primarily 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. This was substantially completed at March 31, 2015. Employee termination benefits were recorded as incurred based on existing employee contracts, statutory requirements, completed negotiations and Company policy.

Severance costs for the Company’s reportable segments and other activities for the three months ended March 31, 2015, were as follows:



	Three Months Ended March 31, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Severance expenses	$	1,166	$	523	$	109	$	2,580	$	4,378

The amounts in the above table also represent cumulative costs incurred to date.

At March 31, 2015, accounts payable and accrued liabilities included $2.5 million in relation to these actions which are expected to be settled within the six months ending September 30, 2015. Changes in the severance cost related liability were as follows:



(Thousands of U.S. Dollars)	Three Months Ended March 31, 2015
Balance, beginning of period	$	—
Liability incurred	4,378
Settlements	(1,858		)
Balance, end of period	$	2,520

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 ended March 31, 2015, largely as a result of the current low commodity price environment, we reevaluated our business strategy with a renewed focus on balancing the return and risk of our exploration and development projects. As a result, on February 19, 2015, we made the decision to cease all further development expenditures on the Bretaña field on Block 95 in Peru other than what is necessary to maintain tangible asset integrity and security. The high capital investment, associated debt financing and long-term payout horizon of this project does not align with our shift in strategy as announced on February 2, 2015.

As a result of this decision, all probable and possible reserves associated with the field were reclassified as contingent resources in a report with an effective date of January 31, 2015. Further, $265.1 million of unproved properties relating to Block 95 were impaired at December 31, 2014. An additional impairment loss of $32.7 million relating to the remaining drilling costs for the Bretaña Sur 95-3-4-1X appraisal well and other costs related to Block 95, which were incurred in the first quarter of 2015, was recognized in the three months ended March 31, 2015. These other costs included costs associated with construction of the long-term test facilities, contract termination and restocking fees and a front end engineering design ("FEED") study.

In March 2015, we announced cost reductions in line with our strategy to preserve our strong balance sheet and maximize potential for future growth. In addition to reductions in 2015 capital expenditures, we focused on reductions to our operating and general and administrative expenses, including lower service and transportation costs. In March 2015, we reduced the number of our full-time employees by 20% from previous staffing levels. Additionally, we are in ongoing negotiations with suppliers and service providers to achieve further savings.

On June 25, 2014, we sold our 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. As such, the results of operations for our Argentina business unit are reflected as loss from discontinued operations, net of income taxes and discussed further in Note 3, "Discontinued Operations," of our interim unaudited condensed consolidated financial statements for the three months ended March 31, 2015.

For the three months ended March 31, 2015, 97% (three months ended March 31, 2014 - 96%) of our revenue and other income from continuing operations was generated in Colombia.

The price of oil is a critical factor to our business, has historically been volatile and has fallen dramatically in December 2014 through March 2015. Sustained periods of low oil prices have been detrimental to our financial performance. During three months ended March 31, 2015, the average price realized for our oil was $43.79 per barrel (three months ended March 31, 2014 - $89.89). Average Brent oil prices for the three months ended March 31, 2015, were $53.91 per bbl compared with $108.17 per bbl in the three months ended March 31, 2014. West Texas Intermediate ("WTI") oil prices for the three months ended March 31, 2015, were $48.63 per bbl compared with $98.68 per bbl in three months ended March 31, 2014.

Highlights



	Three Months Ended March 31,
	2015			2014			% Change
Production (BOEPD) (1)(2)	19,399			18,753			3

Prices Realized - per BOE (1)	$	43.66		$	89.53		(51	)

Revenue and Other Income ($000s) (1)	$	76,652		$	151,855		(50	)

(Loss) Income from Continuing Operations ($000s) (1)	$	(44,866	)	$	49,772		(190	)
Loss from Discontinued Operations, Net of Income Taxes ($000s)	—			(4,643		)	100
Net Income (Loss) ($000s)	$	(44,866	)	$	45,129		(199	)

(Loss) Income Per Share - Basic
(Loss) Income from Continuing Operations (1)	$	(0.16	)	$	0.18		(189	)
Loss from Discontinued Operations, Net of Income Taxes	—			(0.02		)	100
Net Income (Loss)	$	(0.16	)	$	0.16		(200	)

(Loss) Income Per Share - Diluted
(Loss) Income from Continuing Operations (1)	$	(0.16	)	$	0.18		(189	)
Loss from Discontinued Operations, Net of Income Taxes	—			(0.02		)	100
Net Income (Loss)	$	(0.16	)	$	0.16		(200	)

Funds Flow from Continuing Operations ($000s) (1)(3)	$	25,558		$	86,669		(71	)

Capital Expenditures for Continuing Operations ($000s) (1)	$	74,021		$	82,101		(10	)



	As at
	March 31, 2015		December 31, 2014		% Change
Cash & Cash Equivalents ($000s)	$	203,460	$	331,848	(39	)

Working Capital (including Cash & Cash Equivalents) ($000s)	$	181,250	$	239,824	(24	)

Property, Plant & Equipment ($000s)	$	1,116,161	$	1,128,944	(1	)

(1) Excludes amounts relating to discontinued operations. Oil and gas production, NAR and adjusted for inventory changes and losses, associated with discontinued operations was nil BOEPD for the three months ended March 31, 2015, and 3,066 BOEPD for the corresponding period in 2014.

(2) Production represents production volumes NAR adjusted for inventory changes and losses.

(3) 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 operating 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 operating 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, depletion, depreciation, accretion and impairment (“DD&A”) expenses, deferred tax recovery, non-cash stock-based

compensation, unrealized foreign exchange and financial instruments gains 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 March 31,
Funds Flow From Continuing Operations - Non-GAAP Measure ($000s)	2015			2014
Net income (loss)	$	(44,866	)	$	45,129
Adjustments to reconcile net income (loss) to funds flow from continuing operations
Loss from discontinued operations, net of income taxes	—			4,643
DD&A expenses	86,154			44,264
Deferred tax recovery	(2,356		)	(2,260		)
Non-cash stock-based compensation	(513		)	1,480
Unrealized foreign exchange gain	(9,037		)	(4,178		)
Unrealized financial instruments gain	(2,399		)	(2,409		)
Cash settlement of asset retirement obligation	(1,425		)	—
Funds flow from continuing operations	$	25,558		$	86,669

•

Oil and gas production, NAR before inventory adjustments and losses, was 20,140 BOEPD for the three months ended March 31, 2015, compared with 19,029 BOEPD in the corresponding period in 2014. In the three months ended March 31, 2015, production from new wells in the Moqueta field in the Chaza Block in Colombia had a positive effect on production. Production from the Costayaco field in the Chaza Block was consistent with the comparable period. Production in the three months ended March 31, 2015, was 86% from the Chaza Block in Colombia.

•

Oil and gas production, NAR and adjusted for inventory changes and losses, increased by 3% to 19,399 BOEPD for the three months ended March 31, 2015, compared with 18,753 BOEPD in the corresponding period in 2014. During the three months ended March 31, 2015, an increase in oil inventory and losses ("oil inventory") accounted for 66,653 barrels or 741 bopd of reduced production compared with an oil inventory increase which accounted for 24,784 barrels or 276 bopd of reduced production in the corresponding period in 2014.


•	For the three months ended March 31, 2015, revenue and other income decreased by 50% to $76.7 million compared with $151.9 million in the corresponding period in 2014. The decrease was primarily due to the effect of lower realized prices. The average price realized per BOE decreased by 51% to $43.66 for the three months ended March 31, 2015, from $89.53 in the comparable period in 2014.

•

Loss from continuing operations for the three months ended March 31, 2015, was $44.9 million, or $0.16 per share basic and diluted, compared with income from continuing operations of $49.8 million, or $0.18 per share basic and diluted, in the corresponding period in 2014. In the three months ended March 31, 2015, we recorded impairment losses of $32.7 million in our Peru cost center relating to costs incurred on Block 95 and $4.3 million in our Brazil cost center due to lower oil prices. Additionally, loss from continuing operations was impacted by decreased oil and natural gas sales as a result of lower realized oil prices, higher operating, DD&A, severance and equity tax expenses and lower financial instrument gains which were partially offset by lower general and administrative ("G&A") expenses, increased foreign exchange gains and lower income tax expenses.


•	Net loss was $44.9 million, or $0.16 per share basic and diluted, for the three months ended March 31, 2015, compared with net income of $45.1 million, or $0.16 per share basic and diluted, in the corresponding period in 2014. In the three months ended March 31, 2015, we recorded impairment losses of $32.7 million and $4.3 million in our Peru and Brazil cost centers, respectively.

•

For the three months ended March 31, 2015, funds flow from continuing operations decreased by 71% to $25.6 million primarily due to decreased oil and natural gas sales as a result of lower oil realized prices, higher operating, severance and equity tax expenses, and higher realized financial instrument losses, partially offset by lower G&A expenses, higher realized foreign exchange gains and lower income tax expenses.

•

Cash and cash equivalents were $203.5 million at March 31, 2015, compared with $331.8 million at December 31, 2014. The decrease in cash and cash equivalents for the three months ended March 31, 2015, was primarily the result of capital expenditures incurred during the quarter of $74.0 million ($21.4 million in Colombia, $38.0 million in Peru, $13.9 million in Brazil and $0.7 million Corporate), $53.8 million of net cash outflows related to changes in assets and liabilities associated with investing activities ($45.1 million outflow in Colombia, $9.4 million outflow in Peru, and a

$0.7 million inflow in Brazil and Corporate), a $26.1 million change in assets and liabilities from operating activities of continuing operations, a $0.5 million increase in restricted cash, partially offset by funds flow from continuing operations of $25.6 million, and proceeds from the issuance of shares of common stock of $0.5 million.

•

Working capital (including cash and cash equivalents) was $181.3 million at March 31, 2015, a $58.6 million decrease from December 31, 2014. The decrease in working capital was primarily a result of a $128.3 million decrease in cash and cash equivalents, an $18.4 million decrease in accounts receivable primarily due to lower revenues, a $1.2 million decrease in inventory, a $1.7 million increase in the current portion of asset retirement obligation and a $1.7 million increase in net deferred tax liabilities, partially offset by a $83.1 million decrease in accounts payable and accrued liabilities due to lower drilling activity and lower accruals for royalties due to lower oil prices, a $2.0 million decrease in the foreign currency derivative and a $9.0 million decrease in net taxes payable primarily due to lower current income taxes for 2015 in Colombia.


•	Property, plant and equipment at March 31, 2015, was $1.1 billion, a decrease of $12.8 million from December 31, 2014, as a result of $74.0 million of capital expenditures, which were more than offset by $86.8 million of depletion, depreciation and impairment expenses, including an impairment losses of $32.7 million and $4.3 million in our Peru and Brazil cost centers, respectively.


•	Capital expenditures for continuing operations for the three months ended March 31, 2015, were $74.0 million compared with $82.1 million for the three months ended March 31, 2014. In 2015, these capital expenditures included drilling of $32.7 million, geological and geophysical (“G&G”) of $21.8 million, facilities of $16.9 million and other expenditures of $2.6 million.

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.

We believe that our current operations and 2015 capital expenditure program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including additional pipeline delivery restrictions in Colombia or 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. 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.

Consolidated Results of Operations



	Three Months Ended March 31,
	2015			2014			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales (1)	$	76,231		$	151,105		(50	)
Interest income (1)	421			750			(44	)
	76,652			151,855			(50	)

Operating expenses (1)	31,434			21,866			44
DD&A expenses (1)	86,154			44,264			95
G&A expenses (1)	7,294			12,863			(43	)
Severance expenses (1)	4,378			—			—
Equity tax (1)	3,769			—			—
Foreign exchange gain (1)	(11,538		)	(4,210		)	(174	)
Financial instruments gain (1)	(42		)	(2,409		)	98
	121,449			72,374			68

(Loss) income from continuing operations before income taxes (1)	(44,797		)	79,481			(156	)
Income tax expense (1)	(69		)	(29,709		)	(100	)
(Loss) income from continuing operations (1)	(44,866		)	49,772			(190	)
Loss from discontinued operations, net of income taxes	—			(4,643		)	100
Net income (loss)	$	(44,866	)	$	45,129		(199	)

Production (1)(2)

Oil and NGL's, bbl	1,734,898			1,676,977			3
Natural gas, Mcf	66,026			64,779			2
Total production, BOE	1,745,902			1,687,774			3

Average Prices (1)

Oil and NGL's per bbl	$	43.79		$	89.89		(51	)
Natural gas per Mcf	$	3.87		$	5.48		(29	)

Consolidated Results of Operations per BOE

Oil and natural gas sales (1)	$	43.66		$	89.53		(51	)
Interest income (1)	0.24			0.44			(45	)
	43.90			89.97			(51	)

Operating expenses (1)	18.00			12.96			39
DD&A expenses (1)	49.35			26.23			88
G&A expenses (1)	4.18			7.62			(45	)
Severance expenses (1)	2.51			—			—
Equity tax (1)	2.16			—			—
Foreign exchange gain (1)	(6.61		)	(2.49		)	(165	)
Financial instruments gain (1)	(0.02		)	(1.43		)	99
	69.57			42.89			62

(Loss) income from continuing operations before income taxes (1)	(25.67		)	47.08			(155	)
Income tax expense (1)	(0.04		)	(17.60		)	(100	)
(Loss) income from continuing operations (1)	$	(25.71	)	$	29.48		(187	)

(2) Production represents production volumes NAR adjusted for inventory changes and losses.

Net loss for the three months ended March 31, 2015, was $44.9 million compared with net income of $45.1 million in the comparable period in 2014. On a per share basis, net loss was $0.16 per share basic and diluted for the three months ended March 31, 2015, compared with net income of $0.16 per share basic and diluted in the corresponding period in 2014. In the three months ended March 31, 2015, we recorded impairment losses of $32.7 million and $4.3 million in our Peru and Brazil cost centers, respectively.

Loss from continuing operations was $44.9 million, or $0.16 per share basic and diluted, for the three months ended March 31, 2015, compared with income from continuing operations of $49.8 million, or $0.18 per share basic and diluted, in the corresponding period in 2014. In the three months ended March 31, 2015, we recorded impairment losses of $32.7 million in our Peru cost center relating to costs incurred on Block 95 and $4.3 million in our Brazil cost center due to lower oil prices. Additionally, decreased oil and natural gas sales as a result of lower realized oil prices, higher operating, DD&A, severance and equity tax expenses and lower financial instrument gains were partially offset by lower G&A expenses, increased foreign exchange gains and lower income tax expenses.

Loss from discontinued operations, net of income taxes, was $nil for the three months ended March 31, 2015, compared with $4.6 million, or $0.02 per share basic and diluted, in the corresponding period in 2014. We sold our Argentina business unit on June 25, 2014.

Oil and NGL production, NAR before inventory adjustments and losses, for the three months ended March 31, 2015, increased to 20,017 bopd compared with 18,909 bopd in the corresponding period in 2014. In the three months ended March 31, 2015, production from new wells in the Moqueta field in the Chaza Block in Colombia had a positive effect on production. Production from the Costayaco field in the Chaza Block was consistent with the comparable period.

Oil and NGL production, NAR after inventory adjustments and losses, for the three months ended March 31, 2015, increased by 3% to 19,276 bopd compared with 18,633 bopd in the corresponding period in 2014. During the three months ended March 31, 2015, an oil inventory increase accounted for 0.1 MMbbl or 741 bopd of reduced production compared with an oil inventory increase which accounted for 24,784 barrels or 276 bopd of reduced production in the corresponding period in 2014.

Average realized oil prices decreased by 51% to $43.79 per bbl for the three months ended March 31, 2015, from $89.89 per bbl in the comparable period in 2014, primarily due to decreases in the benchmark prices. Average Brent oil prices for the three months ended March 31, 2015, were $53.91 per bbl, compared with $108.17 per bbl in the corresponding period in 2014. Average WTI oil prices for the three months ended March 31, 2015, were $48.63 per bbl compared with $98.68 per bbl 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. During the three months ended March 31, 2015, 20% of our oil volumes sold in Colombia, were through these transportation alternatives compared with 59% in the corresponding period in 2014. These sales have varying effects on our realized prices and transportation costs.

Revenue and other income for the three months ended March 31, 2015, decreased to $76.7 million from $151.9 million in the comparable period in 2014 primarily due to the effect of decreased realized oil prices.

Operating expenses increased by 44% to $31.4 million for the three months ended March 31, 2015, compared with the corresponding period in 2014. For the three months ended March 31, 2015, the increase in operating expenses was primarily due to an increase in the operating cost per BOE. On a per BOE basis, operating expenses increased by 39% to $18.00 for the three months ended March 31, 2015, from $12.96 in the comparable period in 2014. The increase in operating expenses per BOE in 2015 was primarily due to higher transportation costs of $2.59 per BOE 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, and increased workover expenses of $2.70 per BOE.

DD&A expenses for the three months ended March 31, 2015, increased to $86.2 million from $44.3 million in the comparable period in 2014. As previously discussed, DD&A expenses in the three months ended March 31, 2015, included $32.7 million of impairment charges in our Peru cost center. Additionally, in the three months ended March 31, 2015, we recorded a $4.3 million ceiling test impairment loss in our Brazil cost center related to lower oil prices. On a per BOE basis, the depletion rate increased by 88% to $49.35 from $26.23 primarily due to the 2015 impairment charges.

G&A expenses for the three months ended March 31, 2015, decreased by 43% to $7.3 million ($4.18 per BOE) from $12.9 million ($7.62 per BOE) in the corresponding period in 2014. The decrease was mainly due to the effect of the strengthening of the U.S. dollar against the Colombian peso which resulted in significant savings for costs denominated in local currency and a 20% reduction in the number of our full-time employees in March 2015 as part of our cost saving measures and focus on reductions to our other G&A expenses. G&A expenses in the three months ended March 31, 2015, are net of a credit of $1.7 million ($0.97 per BOE) relating to the reversal of stock-based compensation expense for unvested options and restricted stock units ("RSUs") on employee terminations. G&A expenses per BOE in the three months ended March 31, 2015, of $4.18 were 45% lower compared with $7.62 in the corresponding period in 2014 for the same reasons.

Severance expenses for the three months ended March 31, 2015, were $4.4 million compared with $nil in the corresponding period in 2014. As noted above, in March 2015, we reduced the number of our full-time employees by 20%.

Equity tax expense for the three months ended March 31, 2015, 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.

For the three months ended March 31, 2015, the foreign exchange gain was $11.5 million, comprising a realized foreign exchange gain of $2.5 million and an unrealized non-cash foreign exchange gain of $9.0 million. For the three months ended March 31, 2014, there was a foreign exchange gain of $4.2 million, which was primarily a $4.2 million unrealized non-cash foreign exchange gain. Unrealized foreign exchange gains were primarily a result of a net monetary liability position in Colombia and the weakening of Colombian peso versus U.S. dollar.

In the three months ended March 31, 2015, financial instruments gains included $2.4 million of unrealized financial instruments gains which were offset by $2.4 million of realized financial instrument losses. In the three months ended March 31, 2015, we had a $0.4 million financial instrument loss on our Colombian peso non-deliverable forward contracts, comprising a $2.4 million realized loss and a $2.0 million unrealized gain. We purchased these contracts for purposes of fixing the exchange rate at which we will purchase or sell Colombian pesos to settle our income tax installments and payments. Financial instrument gains for the three months ended March 31, 2015, also included a $0.4 million unrealized gain on the Madalena shares we received in connection with the sale of our Argentina business unit. In the three months ended March 31, 2014, we had an unrealized gain of $2.4 million related to our Colombian peso non-deliverable forward contracts.

Income tax expense related to continuing operations was $0.1 million for the three months ended March 31, 2015, compared with $29.7 million in the comparable period in 2014. The decrease was primarily due to lower taxable income. The effective tax rate was 0.2% in the three months ended March 31, 2015, compared with 37% in the comparable period in 2014. The decrease in the effective tax rate was primarily due to losses before income taxes caused by the 2015 impairment losses and changes in stock-based compensation and the non-deductible third party royalty in Colombia, partially offset by changes in foreign currency translation adjustments, impact of foreign taxes, other local taxes, an increase in the valuation allowance, and other permanent differences.

For the three months ended March 31, 2015, the difference between the effective tax rate of 0.2% and the 35% U.S. statutory rate was primarily a result of a loss before income taxes caused by the 2015 impairment losses which was fully offset by an increase in the valuation allowance. Other factors that affected the effective tax rate in the three months ended March 31, 2015, were other local taxes, a non-deductible third party royalty in Colombia and other permanent differences, partially offset by foreign currency translation adjustments. The variance from the 35% U.S. statutory rate for the three months ended March 31, 2014, was primarily attributable to other local taxes, stock-based compensation, an increase in the valuation allowance and the non-deductible third party royalty in Colombia, partially offset by foreign currency translation adjustments, the impact of foreign taxes and other permanent differences.

2015 Capital Program

Our 2015 planned capital program has remained at $140 million. This includes $60 million for Colombia, $55 million for Peru, $24 million for Brazil and $1 million associated with corporate activities. The capital spending program allocates $45 million for drilling, $49 million for facilities, pipelines and other and $46 million for G&G expenditures. Approximately $35 million of the capital program is dedicated to the maintenance of existing production while $21 million is dedicated to drilling in Colombia.

The increase in the Peru capital program compared with the budget we released on February 9, 2015, is mainly due to increased costs to complete the seismic program on Block 107, increased drilling costs related to the Bretaña Sur 95-3-4-1X appraisal well, finalization of costs for decommissioning assets related to the long-term test facilities and other activities previously planned on the Bretaña field.

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.

Segmented Results from Continuing Operations – Colombia



	Three Months Ended March 31,
	2015			2014			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	74,067		$	144,935		(49	)
Interest income	67			137			(51	)
	74,134			145,072			(49	)

Operating expenses	29,974			20,205			48
DD&A expenses	46,255			41,250			12
G&A expenses	2,716			4,383			(38	)
Severance expenses	1,166			—			—
Equity tax	3,769			—			—
Foreign exchange gain	(13,043		)	(4,368		)	(199	)
Financial instruments loss (gain)	369			(2,409		)	115
	71,206			59,061			21

Income from continuing operations before income taxes	$	2,928		$	86,011		(97	)

Production (1)

Oil and NGL's, bbl	1,676,287			1,610,655			4
Natural gas, Mcf	66,026			64,779			2
Total production, BOE	1,687,291			1,621,452			4

Average Prices

Oil and NGL's per bbl	$	44.03		$	89.73		(51	)
Natural gas per Mcf	$	3.87		$	6.34		(39	)

Segmented Results of Operations per BOE

Oil and natural gas sales	$	43.90		$	89.39		(51	)
Interest income