Edgar Filing: GRAN TIERRA ENERGY, INC.

form10q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2012

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 number)

300, 625 11 Avenue S.W. Calgary, Alberta, Canada		T2R 0E1
(Address of principal executive offices)		(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 x NO o

Indicate by check mark whether the registrant submitted electronically and posted on its corporate Web site, 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 x 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 x

On May 1, 2012, the following numbers of shares of the registrant’s capital stock were outstanding: 266,474,815 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 6,223,810 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 8,188,780 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, 2012

Table of contents

		Page

PART I

Item 1.	Financial Statements	5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	32

PART II

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 5	Other Information	41

Item 6.	Exhibits	41

SIGNATURES		41

EXHIBIT INDEX		42

Table of Contents

STATEMENT 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 (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	BOPD	barrels of oil per day
Mbbl	thousand barrels	Mcf	thousand cubic feet
MMbbl	million barrels	MMcf	million cubic feet
BOE	barrels of oil equivalent	Bcf	billion cubic feet
MMBOE	million barrels of oil equivalent	NGL	natural gas liquids
BOEPD	barrels of oil equivalent per day	NAR	net after royalty

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 are paid 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. Production volumes are also reported net of inventory adjustments. 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 inexpensive way of gathering data over large regions.

Seismic data is used by oil and natural gas companies as their 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 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.

Table of Contents

Workover is a term used to describe remedial operations on a previously completed well to clean, repair and/or maintain the well for the purposes 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:

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

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 (LKH) 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:

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.

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

(v)

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.

●

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.

Table of Contents

PART 1

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,
	2012			2011

REVENUE AND OTHER INCOME
Oil and natural gas sales	$	155,248		$	122,296
Interest income		703			223
		155,951			122,519
EXPENSES
Operating		24,487			16,396
Depletion, depreciation, accretion and impairment (Note 5)		60,367			63,357
General and administrative		15,899			13,638
Equity tax (Note 8)		-			8,050
Financial instruments gain (Notes 3 and 6)		-			(230	)
Gain on acquisition (Note 3)		-			(24,300	)
Foreign exchange loss		24,375			5,199
		125,128			82,110

INCOME BEFORE INCOME TAXES		30,823			40,409
Income tax expense (Note 8)		(31,136	)		(26,696	)
NET (LOSS) INCOME AND COMPREHENSIVE (LOSS) INCOME		(313	)		13,713
RETAINED EARNINGS, BEGINNING OF PERIOD		185,014			58,097
RETAINED EARNINGS, END OF PERIOD	$	184,701		$	71,810

NET (LOSS) INCOME PER SHARE — BASIC	$	(0.00	)	$	0.05
NET (LOSS) INCOME PER SHARE — DILUTED	$	(0.00	)	$	0.05
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)		278,734,280			260,930,753
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)		278,734,280			267,819,800

(See notes to the condensed consolidated financial statements)

Table of Contents

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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

	March 31,		December 31,
	2012		2011

ASSETS
Current Assets
Cash and cash equivalents	$	230,076	$	351,685
Restricted cash		2,880		1,655
Accounts receivable		145,606		69,362
Inventory (Note 5)		14,339		7,116
Taxes receivable		19,501		21,485
Prepaids		4,215		3,597
Deferred tax assets (Note 8)		3,229		3,029
Total Current Assets		419,846		457,929

Oil and Gas Properties (using the full cost method of accounting)
Proved		627,620		618,982
Unproved		433,530		417,868
Total Oil and Gas Properties		1,061,150		1,036,850
Other capital assets		8,441		7,992
Total Property, Plant and Equipment (Note 5)		1,069,591		1,044,842

Other Long-Term Assets
Restricted cash		43,039		13,227
Deferred tax assets (Note 8)		6,462		4,747
Other long-term assets		4,994		3,454
Goodwill		102,581		102,581
Total Other Long-Term Assets		157,076		124,009
Total Assets	$	1,646,513	$	1,626,780

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	37,775	$	82,189
Accrued liabilities		90,238		66,832
Taxes payable		120,328		95,482
Asset retirement obligation (Note 7)		-		326
Total Current Liabilities		248,341		244,829

Long-Term Liabilities
Deferred tax liability (Note 8)		198,505		186,799
Equity tax payable (Note 8)		7,029		6,484
Asset retirement obligation (Note 7)		12,124		12,343
Other long-term liabilities		2,187		2,007
Total Long-Term Liabilities		219,845		207,633

Commitments and Contingencies (Note 9)

Shareholders’ Equity
Common shares (Note 6) (264,256,159 and 262,304,249 common shares and 14,717,917 and 16,323,819 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2012 and December 31, 2011, respectively)		7,983		7,510
Additional paid in capital		983,919		980,014
Warrants (Note 6)		1,724		1,780
Retained earnings		184,701		185,014
Total Shareholders’ Equity		1,178,327		1,174,318
Total Liabilities and Shareholders’ Equity	$	1,646,513	$	1,626,780

(See notes to the condensed consolidated financial statements)

Table of Contents

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)

	Three Months Ended March 31,
	2012				2011

Operating Activities
Net (loss) income		$	(313	)		$	13,713
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depletion, depreciation, accretion and impairment			60,367				63,357
Deferred taxes (Note 8)			(5,250	)			(187	)
Stock-based compensation (Note 6)			3,192				3,453
Gain on financial instruments (Note 3)			-				(62	)
Unrealized foreign exchange loss			21,351				4,458
Settlement of asset retirement obligation (Note 7)			(404	)			(4	)
Equity tax			-				6,132
Gain on acquisition (Note 3)			-				(24,300	)
Net change in assets and liabilities from operating activities
Accounts receivable			(72,865	)			(83,036	)
Inventory			(4,500	)			736
Prepaids			(618	)			(831	)
Accounts payable and accrued and other liabilities			(34,035	)			(22,756	)
Taxes receivable and payable			19,595				8,101

Net cash used in operating activities			(13,480	)			(31,226	)

Investing Activities
Increase in restricted cash			(31,037	)			(5,600	)
Additions to property, plant and equipment			(77,983	)			(77,516	)
Proceeds from disposition of oil and gas property (Note 5)			-				3,253
Cash acquired on acquisition (Note 3)			-				7,747
Proceeds on sale of asset-backed commercial paper (Note 3)			-				22,679

Net cash used in investing activities			(109,020	)			(49,437	)

Financing Activities
Settlement of bank debt (Notes 3 and 11)			-				(22,853	)
Proceeds from issuance of common shares			891				1,989

Net cash provided by (used in) financing activities			891				(20,864	)

Net decrease in cash and cash equivalents			(121,609	)			(101,527	)
Cash and cash equivalents, beginning of period			351,685				355,428

Cash and cash equivalents, end of period		$	230,076			$	253,901

Cash		$	148,035			$	243,399
Term deposits			82,041				10,502
Cash and cash equivalents, end of period		$	230,076			$	253,901

Supplemental cash flow disclosures:
Cash paid for interest		$	-			$	668
Cash paid for income taxes		$	13,733			$	9,693
Non-cash investing activities:
Non-cash working capital related to property, plant and equipment, end of period		$	53,090			$	42,698

(See notes to the condensed consolidated financial statements)

Table of Contents

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)

	Three Months Ended				Year Ended
	March 31, 2012				December 31, 2011

Share Capital
Balance, beginning of period		$	7,510			$	4,797
Issue of common shares			473				2,713

Balance, end of period			7,983				7,510


Additional Paid in Capital
Balance, beginning of period			980,014				821,781
Issue of common shares			105				142,109
Exercise of warrants (Note 6)			56				411
Exercise of stock options (Note 6)			313				1,990
Stock-based compensation (Note 6)			3,431				13,723

Balance, end of period			983,919				980,014


Warrants
Balance, beginning of period			1,780				2,191
Exercise of warrants (Note 6)			(56	)			(411	)

Balance, end of period			1,724				1,780

Retained Earnings
Balance, beginning of period			185,014				58,097
Net (loss) income			(313	)			126,917

Balance, end of period			184,701				185,014

Total Shareholders’ Equity		$	1,178,327			$	1,174,318

(See notes to the condensed consolidated financial statements)

Table of Contents

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

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, Argentina, Peru and Brazil.

2. Significant Accounting Policies

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

The note disclosure requirements of annual consolidated financial statements provide additional disclosures to that required for interim unaudited condensed consolidated financial statements. Accordingly, these interim unaudited condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements as at and for the year ended December 31, 2011 included in the Company’s 2011 Annual Report on Form 10-K, filed with the Securities and Exchange Commission (“SEC”) on February 27, 2012.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2011 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as disclosed below. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

Revenue recognition

Revenue from the production of oil and natural gas is recognized when title passes to the customer and when collection of the revenue is reasonably assured. On February 1, 2012, the sales point for the Company’s Colombian oil sales in the Putumayo basin changed. Gran Tierra’s customer now takes title at the Port of Tumaco on the Pacific coast of Colombia rather than at the entry into the Ecopetrol-operated Trans-Andean oil pipeline (“the OTA pipeline”) at the Orito station in the Putumayo basin.

Adopted accounting pronouncements

Goodwill

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-08, "Intangibles – Goodwill and Other (Topic 350)." The update is intended to simplify how entities test goodwill for impairment. The update permits entities to assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether it is necessary to perform the two-step goodwill impairment test. This ASU was effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations or cash flows.

Recently issued accounting pronouncements

Disclosure about Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11, "Balance Sheet – Disclosure about Offsetting Assets and Liabilities (Topic 210)." The update requires an entity to disclose information about offsetting assets and liabilities and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after January 1, 2013. The implementation of this update is not expected to materially impact the Company’s disclosure.

3. Business Combination

On March 18, 2011 (the “Acquisition Date”), Gran Tierra completed its acquisition of all the issued and outstanding common shares and warrants of Petrolifera Petroleum Limited (“Petrolifera”), a Canadian corporation, pursuant to the terms and conditions of an arrangement agreement dated January 17, 2011 (the “Arrangement”). Petrolifera is a Calgary based oil, natural gas and natural gas liquids exploration, development and production company active in Argentina, Colombia and Peru. The transaction contemplated by the Arrangement was effected through a court approved plan of arrangement in Canada. The Arrangement was approved at a special meeting of Petrolifera shareholders on March 17, 2011 and by the Court of Queen's Bench of Alberta on March 18, 2011.

Under the Arrangement, Petrolifera shareholders received, for each Petrolifera share held, 0.1241 of a share of Gran Tierra common stock, and Petrolifera warrant holders received, for each Petrolifera warrant held, 0.1241 of a Replacement Warrant to purchase a share of Gran Tierra common stock at an exercise price of $9.67 Canadian (“CDN”) dollars per share. The Replacement Warrants expired unexercised on August 28, 2011.

Gran Tierra acquired all the issued and outstanding Petrolifera shares and warrants through the issuance of 18,075,247 Gran Tierra common shares, par value $0.001, and 4,125,036 Replacement Warrants. Upon completion of the transaction on the Acquisition Date, Petrolifera became an indirect wholly-owned subsidiary of Gran Tierra. On a diluted basis, upon the closing of the Arrangement, Petrolifera and Gran Tierra security holders owned approximately 6.6% and 93.4% of the Company, respectively, immediately following the transaction. The total consideration for the transaction was approximately $143 million.

The fair value of Gran Tierra’s common shares was determined as the closing price of the common shares of Gran Tierra as at the Acquisition Date.

Table of Contents

The fair value of the Replacement Warrants was estimated on the Acquisition Date using the Black-Scholes option pricing model with the following assumptions:

Exercise price (CDN dollars per warrant)	$	9.67
Risk-free interest rate		1.3	%
Expected life	0.45 Years
Volatility		44	%
Expected annual dividend per share	Nil
Estimated fair value per warrant (CDN dollars)	$	0.32

The acquisition is accounted for using the acquisition method, with Gran Tierra being the acquirer, whereby Petrolifera’s assets acquired and liabilities assumed are recognized at their fair values as at the Acquisition Date and the results of Petrolifera have been consolidated with those of Gran Tierra from that date.

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

(Thousands of U.S. Dollars)
Consideration Transferred:
Common shares issued net of share issue costs	$	141,690
Replacement warrants		1,354
	$	143,044

Allocation of Consideration Transferred:
Oil and gas properties
Proved	$	58,457
Unproved		161,278
Other long-term assets		4,417
Net working capital (including cash acquired of $7.7 million and accounts receivable of $6.4 million)		(17,223	)
Asset retirement obligation		(4,901	)
Bank debt		(22,853	)
Other long-term liabilities		(14,432	)
Gain on acquisition		(21,699	)
	$	143,044

As shown above, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration transferred. Consequently, Gran Tierra reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, Gran Tierra initially recognized a gain of $24.3 million, which was reported as “Gain on acquisition”, in the consolidated statement of operations for the three months ended March 31, 2011. Subsequent to the initial allocation of the consideration in the first quarter of 2011, further assessments of Petrolifera’s tax position resulted in a reduction of the gain on acquisition to $21.7 million. The gain reflects the impact on Petrolifera’s pre-acquisition market value of a lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects.

As part of the assets acquired and included in the net working capital in the allocation of the consideration transferred, the Company assigned $22.5 million in fair value to investments in notes that Petrolifera received in exchange for asset-backed commercial paper (“ABCP”) with a face value of $31.3 million. On March 28, 2011, these notes were sold to an unrelated party for proceeds of $22.7 million after the associated line of credit was settled resulting in a financial instruments gain for the three months ended March 31, 2011 of $0.2 million.

The associated ABCP line of credit that Gran Tierra assumed was with a Canadian Chartered Bank, to a maximum of CDN$23.2 million with an initial expiry in April 2012. Gran Tierra settled this line of credit immediately after the completion of the acquisition of Petrolifera for the face value of CDN$22.5 million in borrowings plus accrued interest.

Also upon the acquisition of Petrolifera, Gran Tierra assumed a second line of credit agreement (“Second ABCP line of credit”) with the same Canadian chartered bank to a maximum of CDN$5.0 million, which was fully drawn as at the Acquisition Date. This Second ABCP line of credit, which expired on April 8, 2011, was secured by ineligible master asset vehicles Classes 1 & 2 (“MAV IA 1 & 2”) notes with a face value of $6.6 million. Gran Tierra retained the option to settle the Second ABCP line of credit of CDN$5.0 million through delivery to the lender of the MAV IA 1 & 2 notes. Subsequent to the acquisition, Gran Tierra elected to record this second line of credit at fair value and planned at that time to settle the debt through delivery of the MAV IA 1 & 2 notes. Accordingly, a value of $nil was recorded for the debt upon its acquisition. Gran Tierra settled such borrowings by delivery of the MAV IA 1 & 2 notes on April 8, 2011.

Gran Tierra also assumed a reserve-backed credit facility upon the Petrolifera acquisition with an outstanding balance of $31.3 million. The amount outstanding under this credit facility was included as part of net working capital in the allocation of consideration transferred. The credit facility bore interest at LIBOR plus 8.25% and was partially secured by the pledge of the shares of Petrolifera’s subsidiaries. The outstanding balance was repaid when the Argentine restriction preventing its repayment expired on August 5, 2011.

Table of Contents

Pro forma results for the three months ended March 31, 2011 are shown below, as if the acquisition had occurred on January 1, 2010. Pro forma results are not indicative of actual results or future performance.

	Three Months Ended March 31,
(Thousands of U.S. Dollars except per share amounts)	2011
Revenue and other income	$	131,714
Net loss	$	(21,711	)
Net loss per share - basic	$	(0.08	)
Net loss per share - diluted	$	(0.08	)

The supplemental pro forma earnings of Gran Tierra for the three months ended March 31, 2011 were adjusted to exclude $4.4 million of acquisition costs recorded in general and administrative (“G&A”) expenses and the $24.3 million gain on acquisition because they are not expected to have a continuing impact on Gran Tierra’s results of operations. Petrolifera’s oil and natural gas sales and results of operations between the Acquisition Date and March 31, 2011 were not significant and therefore are not separately disclosed.

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, Argentina and Peru based on a geographic organization. The Company’s operations in Brazil are not a reportable segment because the level of activity in Brazil was not significant at March 31, 2012 or December 31, 2011. The All Other category represents the Company’s corporate activities and operations in Brazil.

The accounting policies of the reportable segments are the same as those described in Note 2. The Company evaluates segment performance based on income or loss before income taxes. The segmented results include the operations of Petrolifera subsequent to March 18, 2011, the date of acquisition of Petrolifera (Note 3).

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

(Thousands of U.S. Dollars except per unit of production amounts)	Three Months Ended March 31, 2012
	Colombia		Argentina			Peru			All Other			Total
Oil and natural gas sales	$	138,633	$	15,369		$	-		$	1,246		$	155,248
Interest income		204		47			15			437			703
Depletion, depreciation, accretion and impairment		32,286		5,925			115			22,041			60,367
Depletion, depreciation, accretion and impairment - per unit of production		25.80		22.80			-			1,741.47			39.62
Income (loss) before income taxes		60,120		(477	)		(727	)		(28,093	)		30,823
Segment capital expenditures	$	20,349	$	14,105		$	16,655		$	36,482		$	87,591

	Three Months Ended March 31, 2011
(Thousands of U.S. Dollars except per unit of production amounts)	Colombia		Argentina			Peru			All Other			Total
Oil and natural gas sales	$	117,304	$	4,992		$	-		$	-		$	122,296
Interest income		87		-			-			136			223
Depletion, depreciation, accretion and impairment		30,036		1,147			31,933			241			63,357
Depletion, depreciation, accretion and impairment - per unit of production		24.77		11.90			-			-			48.39
Income (loss) before income taxes		57,886		(430	)		(32,625	)		15,578			40,409
Segment capital expenditures (1)	$	42,264	$	11,622		$	14,287		$	930		$	69,103

(1) Net of proceeds from the farm out of a 50% interest in the Santa Victoria Block in Argentina in March 2011 (see Note 5).

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.

Table of Contents

In the three months ended March 31, 2012 and 2011, the Company had one significant customer for its Colombian oil, Ecopetrol S.A. (“Ecopetrol”). Sales to Ecopetrol accounted for 85% and 96% of the Company’s revenues for the three months ended March 31, 2012 and 2011, respectively. In the three months ended March 31, 2012, the Company had two significant customers in Argentina, Shell C.A.P.S.A. (“Shell”) and Refineria del Norte S.A. (“Refiner”). Sales to Shell and Refiner accounted for 4% and 3%, respectively, of the Company’s oil and natural gas sales for the three months ended March 31, 2012. In the three months ended March 31, 2011, Refiner was the Company’s only significant customer in Argentina.

(Thousands of U.S. Dollars)	As at March 31, 2012
	Colombia		Argentina		Peru		All Other		Total
Property, plant and equipment	$	801,810		137,414		50,845		79,522	$	1,069,591
Goodwill		102,581		-		-		-		102,581
Other assets		269,744		38,103		8,602		157,892		474,341
Total Assets	$	1,174,135	$	175,517	$	59,447	$	237,414	$	1,646,513

	As at December 31, 2011
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		All Other		Total
Property, plant and equipment	$	816,396		129,072		34,305		65,069	$	1,044,842
Goodwill		102,581		-		-		-		102,581
Other assets		269,843		34,672		9,597		165,245		479,357
Total Assets	$	1,188,820	$	163,744	$	43,902	$	230,314	$	1,626,780

5. Property, Plant and Equipment and Inventory

Property, Plant and Equipment

	As at March 31, 2012							As at December 31, 2011
(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	$	1,252,252		(624,632	)		627,620	$	1,181,503	$	(562,521	)	$	618,982
Unproved		433,530		-			433,530		417,868		-			417,868
		1,685,782		(624,632	)		1,061,150		1,599,371		(562,521	)		1,036,850
Furniture and fixtures and leasehold improvements		7,226		(4,457	)		2,769		6,973		(4,002	)		2,971
Computer equipment		9,370		(4,422	)		4,948		8,443		(4,174	)		4,269
Automobiles		1,295		(571	)		724		1,295		(543	)		752
Total Property, Plant and Equipment	$	1,703,673	$	(634,082	)	$	1,069,591	$	1,616,082	$	(571,240	)	$	1,044,842

Depletion and depreciation expense on property, plant and equipment for the three months ended March 31, 2012 was $42.6 million (three months ended March 31, 2011 - $32.1 million). A portion of depletion and depreciation expense was capitalized as inventory during the period.

In September 2011, the Company announced two farmout agreements with Statoil do Brasil Ltda. ("Statoil") in a joint venture with PetróleoBrasileiro S.A., in Brazil’s deepwater offshore Camamu-Almada Basin, pursuant to which, the Company would receive an assignment of a non-operated 10% working interest in Block BM-CAL-7 and a non-operated 15% working interest in Block BM-CAL-10. Both blocks are located in the Camamu Basin, offshore Bahia, Brazil.

On February 17, 2012, in accordance with the terms of the farmout agreement for BM-CAL-10, the Company gave notice to Statoil that it would not enter into and assume its share of the work obligations of the second exploration period of the block. As a result, the farmout agreement has terminated and the Company will not receive any interest in the block. Pursuant to the farmout agreement, the Company was obligated to make payment for a certain percentage of the costs relating to Block BM-CAL-10, which relate primarily to a well that was drilled during the term of the farmout agreement. The notice of withdrawal was a trigger for payment of amounts that would otherwise have been due if the farmout agreement had closed and the Company had acquired a participating interest. In the three months ended March 31, 2012, the Company recorded a ceiling test impairment loss in the Company’s Brazil cost center of $20.2 million. This impairment charge resulted from the recognition of $23.8 million of capital expenditures in relation to the Block BM-CAL-10 farmout agreement in the first quarter of 2012.

Table of Contents

During the first quarter of 2012, the Company received regulatory approval from Agência Nacional de Petróleo, Gás Natural e Biocombustíveis ("ANP") for the Block BM-CAL-7 farmout agreement. Purchase consideration of $0.7 million was paid and the assignment became effective on April 3, 2012. The block is an unproved property.

In the three months ended March 31, 2011, the Company recorded ceiling test impairment loss in the Company’s Peru cost center of $31.9 million. This impairment charge related to seismic and drilling costs from a dry well.

In March 2011, the Company recorded proceeds of $3.3 million from the farmout of a 50% interest in the Santa Victoria Block in Argentina to Apache Corporation.

The amounts capitalized in each of the Company's cost centers during the three months ended March 31, 2012 and 2011 were as follows:

	Three Months Ended March 31, 2012
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock-based compensation	$	1,852	$	1,080	$	927	$	1,068	$	4,927
Capitalized stock-based compensation	$	114	$	66	$	-	$	59	$	239


	Three Months Ended March 31, 2011
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock-based compensation	$	1,815	$	410	$	294	$	-	$	2,519
Capitalized stock-based compensation	$	76	$	47	$	-	$	-	$	123

Unproved oil and natural gas properties consist of exploration lands held in Colombia, Argentina, Peru and Brazil. As at March 31, 2012, the Company had $274.3 million (December 31, 2011 - $274.8 million) of unproved assets in Colombia, $52.9 million (December 31, 2011 - $57.0 million) of unproved assets in Argentina, $50.2 million (December 31, 2011 - $33.7 million) of unproved assets in Peru and $56.1 million (December 31, 2011 - $52.4 million) of unproved assets in Brazil for a total of $433.5 million (December 31, 2011 - $417.9 million). These 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 dictates whether or not future areas will be developed.

Inventories

As at March 31, 2012, oil and supplies inventories were $12.1 million and $2.2 million, respectively (December 31, 2011 - $4.7 million and $2.4 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, 2012, outstanding share capital consists of 264,256,159 common voting shares of the Company, 8,494,107 exchangeable shares of Gran Tierra Exchange Co., automatically exchangeable on November 14, 2013, and 6,223,810 exchangeable shares of Goldstrike Exchange Co., automatically exchangeable on November 10, 2012. The exchangeable shares of Gran Tierra Exchange Co., were issued upon acquisition of Solana Resources Limited (“Solana”). The exchangeable shares of Gran Tierra Goldstrike Inc. were issued upon the business combination between Gran Tierra Energy Inc., an Alberta corporation, and Goldstrike, Inc., which is now the Company. Each exchangeable share is exchangeable into one common voting share of the Company. The holders 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 common stock. Holders of exchangeable shares have substantially the same rights as holders of common voting shares.

Warrants

At March 31, 2012, the Company had 6,098,224 warrants outstanding to purchase 3,049,112 common shares for $1.05 per share, expiring between June 20, 2012 and June 30, 2012. For the three months ended March 31, 2012, 100,003 common shares were issued upon the exercise of 200,006 warrants (three months ended March 31, 2011, 210,000 common shares were issued upon the exercise of 420,000 warrants).

The Company issued 4,125, 036 Replacement Warrants in connection with its acquisition of Petrolifera during March 2011 (Note 3). The Replacement Warrants expired unexercised during August 2011.The fair value of the Replacement Warrants as of March 31, 2011 was determined using the Black-Scholes option pricing model with the following assumptions:

Exercise price (CDN dollars per warrant)	$	9.67
Risk-free interest rate		1.3	%
Expected life	0.45 Years
Volatility		44	%
Expected annual dividend per share	Nil
Estimated fair value per warrant (CDN dollars)	$	0.32

During the three months ended March 31, 2011, a financial instruments gain resulting from the change in fair value of the Replacement Warrants of $32,075 was recorded.

Table of Contents

Stock Options

For the three months ended March 31, 2012, the stock-based compensation expense was $3.4 million (three months ended March 31, 2011 - $3.6 million) of which $2.9 million (three months ended March 31, 2011 - $3.2 million) was recorded in G&A expenses, $0.3 million was recorded in operating expense (three months ended March 31, 2011 – $0.3 million) and $0.2 million of stock-based compensation was capitalized as part of exploration and development costs (three months ended March 31, 2011 – $0.1 million).

At March 31, 2012, there was $18.3 million (December 31, 2011 - $11.7 million) of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next three years.

The following table provides information about stock option activity for the three months ended March 31, 2012:

	Number of Outstanding Options			Weighted Average Exercise Price $/Option
Balance, December 31, 2011		12,864,002		$	4.90
Granted in 2012		3,213,150			5.81
Exercised in 2012		(246,005	)		(3.20	)
Forfeited in 2012		(136,646	)		(7.05	)
Balance, March 31, 2012		15,694,501		$	5.10

The weighted average grant date fair value for options granted in the three months ended March 31, 2012 was $3.37 (three months ended March 31, 2011 - $5.20). The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table.

	Three Months Ended March 31,
	2012

Dividend yield (per share)	$	nil
Volatility		75	%
Risk-free interest rate		0.4	%
Expected term	4-6 years

Weighted average shares outstanding

	Three Months Ended March 31,
	2012		2011
Weighted average number of common and exchangeable shares outstanding		278,734,280		260,930,753
Shares issuable pursuant to warrants		-		3,203,257
Shares issuable pursuant to stock options		-		5,894,518
Shares to be purchased from proceeds of stock options		-		(2,208,728	)
Weighted average number of diluted common and exchangeable shares outstanding		278,734,280		267,819,800

Net (loss) income per share

For the three month period ended March 31, 2012, 15,694,501 options and 6,098,224 warrants to purchase 3,049,112 common shares were excluded from the diluted income per share calculation as the instruments were anti-dilutive. For the three months ended March 31, 2011, 4,125,036 Replacement Warrants were excluded from the diluted income per share calculation as the instruments were anti-dilutive.

7. Asset Retirement Obligation

As at March 31, 2012, the Company’s asset retirement obligation was comprised of a Colombian obligation in the amount of $5.6 million (December 31, 2011 - $5.5 million), an Argentine obligation in the amount of $6.0 million (December 31, 2011 - $6.7 million) and a Brazilian obligation in the amount of $0.5 million (December 31, 2011 - $0.5 million). As at March 31, 2012, the undiscounted asset retirement obligation was $29.2 million (December 31, 2011 - $29.9 million). 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. Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:

Table of Contents

	Three Months Ended			Year Ended
(Thousands of U.S. Dollars)	March 31, 2012			December 31, 2011
Balance, beginning of period	$	12,669		$	4,807
Settlements		(404	)		(345	)
Disposal		-			(172	)
Liability incurred		193			867
Liability assumed in a business combination (Note 3)		-			4,901
Foreign exchange		35			17
Accretion		247			673
Revisions in estimated liability		(616	)		1,921
Balance, end of period	$	12,124		$	12,669

Asset retirement obligation - current	$	-		$	326
Asset retirement obligation – long-term		12,124			12,343
Balance, end of period	$	12,124		$	12,669

8. Taxes

The income tax expense reported differs from the amount computed by applying the U.S. statutory rate to income before income taxes for the following reasons:

	Three Months Ended March 31,
(Thousands of U.S. Dollars)	2012			2011
Income before income taxes	$	30,823			$	40,409
		35	%			35	%
Income tax expense expected		10,788				14,143
Foreign currency translation adjustments		8,718				1,981
Impact of foreign taxes		(631	)			(1,598	)
Stock-based compensation		1,003				1,143
Increase in valuation allowance		10,145				15,288
Branch and other foreign loss pick-up in the United States and Canada		(622	)			(1,619	)
Non-deductible third party royalty in Colombia		1,943				1,820
Non-taxable gain on acquisition		-				(8,527	)
Other permanent differences		(208	)			4,065
Total income tax expense	$	31,136			$	26,696

Current income tax		36,384				26,677
Deferred tax recovery		(5,248	)			19
Total income tax expense	$	31,136			$	26,696

	As at
(Thousands of U.S. Dollars)	March 31, 2012			December 31, 2011
Deferred Tax Assets
Tax benefit of loss carryforwards	$	73,645			$	63,910
Tax basis in excess of book basis		15,732				17,065
Foreign tax credits and other accruals		27,224				27,164
Capital losses		2,494				2,433
Deferred tax assets before valuation allowance		119,095				110,572
Valuation allowance		(109,404	)			(102,796	)
	$	9,691			$	7,776

Deferred tax assets - current	$	3,229			$	3,029
Deferred tax assets - long-term		6,462				4,747
		9,691				7,776

Deferred Tax Liabilities
Long-term - book value in excess of tax basis		(198,505	)			(186,799	)

Net Deferred Tax Liabilities	$	(188,814	)		$	(179,023	)

Table of Contents

As at March 31, 2012, the Company had operating loss carryforwards of $388.5 million (December 31, 2011 - $361.6 million) and capital losses of $13.9 million (December 31, 2011 – $13.7 million). Of these losses, $368.4 million (December 31, 2011 - $339.8 million) were losses generated by the foreign subsidiaries of the Company. In certain jurisdictions, the net operating loss carryforwards expire between 2012 and 2031 and the capital losses expire between 2012 and 2016, while certain other jurisdictions allow net operating losses to be carried forward indefinitely. Of the total net operating loss carryforwards, $4.0 million will begin to expire by 2013.

As at March 31, 2012, the total amount of Gran Tierra’s unrecognized tax benefits was approximately $20.5 million (December 31, 2011 - $20.5 million), a portion of 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 consolidated statement of operations. As at March 31, 2012, the amount of interest and penalties on unrecognized tax benefits included in current income tax liabilities in the interim unaudited consolidated balance sheet was approximately $1.6 million (December 31, 2011 - $1.6 million). The Company had no material interest or penalties included in the interim unaudited consolidated statement of operations for the three months ended March 31, 2012 and 2011.

Changes in the Company's unrecognized tax benefit are as follows:

	Three Months Ended March 31,
	2012		2011
(Thousands of U.S. Dollars)
Unrecognized tax benefit at January 1	$	20,500	$	4,175
Changes for positions relating to prior year		-		70
Additions to tax position related to the current year		-		12,364
Unrecognized tax benefit at March 31	$	20,500	$	16,609

The Company and its subsidiaries file income tax returns in the U.S. federal and state jurisdictions and certain other foreign jurisdictions. The Company is subject to income tax examinations for the calendar tax years ended 2005 through 2011 in most jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefits disclosed above within the next twelve months.

Equity tax for the three months ended March 31, 2011 of $8.1 million represented a Colombian tax of 6% on a legislated measure which is based on the Company’s Colombian segment’s balance sheet equity at January 1, 2011. The equity tax is assessed every four years. The tax is payable in eight semi-annual installments over four years, but was expensed in the first quarter of 2011 at the commencement of the four-year period. The equity tax liability at March 31, 2012 and December 31, 2011 also partially related to an equity tax liability assumed upon the acquisition of Petrolifera.

9. Commitments and Contingencies

Purchase Obligations, Firm Agreements and Leases

The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancellable lease terms in excess of one year as of March 31, 2012:

	As at March 31, 2012
	Payments Due in Period
	Total		Less than 1 Year		1 to 3 years		3 to 5 years		More than 5 years
(Thousands of U.S. Dollars)
Oil transportation services	$	36,922	$	13,072	$	7,100	$	7,100	$	9,650
Drilling and geological and geophysical		58,336		47,086		11,250		-		-
Completions		24,821		19,201		5,620		-		-
Facility construction		41,389		24,557		16,832		-		-
Operating leases		7,661		3,085		3,142		1,434		-
Software and telecommunication		4,790		3,811		979		-		-
Consulting		1,989		1,989		-		-		-
Total	$	175,908		112,801		44,923		8,534		9,650

Table of Contents

Indemnities

Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated.

The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid.

Letters of credit

At March 31, 2012, the Company had provided promissory notes totalling $24.5 million (December 31, 2011 - $20.7 million) as security for letters of credit relating to work commitment guarantees contained in exploration contracts.

Contingencies

Ecopetrol and Gran Tierra Energy Colombia Ltd. (“Gran Tierra Colombia”), 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. There is a material difference in the interpretation of the procedure established in Clause 3.5 of Attachment-B of the Guayuyaco Association Contract. Ecopetrol interprets the contract to provide that the extended test production up to a value equal to 30% of the direct exploration costs of the wells is for Ecopetrol’s account only and serves as reimbursement of its 30% back-in to the Guayuyaco discovery. Gran Tierra Colombia’s contention is that this amount is merely the recovery of 30% of the direct exploration costs of the wells and not exclusively for the benefit of Ecopetrol. There has been no agreement between the parties, and Ecopetrol has filed a lawsuit in the Contravention Administrative Court in the District of Cauca regarding this matter. Gran Tierra Colombia filed a response on April 29, 2008 in which it refuted all of Ecopetrol’s claims and requested a change of venue to the courts in Bogota. At this time no amount has been accrued in the financial statements as the Company does not consider it probable that a loss will be incurred. Ecopetrol is claiming damages of approximately $5.8 million.

Gran Tierra is subject to a third party 10% net profits interest on 50% of the Company’s production from the Costayaco field that arises from the original acquisition in 2006 of 50% of Gran Tierra’s interest in the Chaza Block Contract. There is currently a disagreement between Gran Tierra and the third party as to the calculation of the net profits interest. Gran Tierra and the third party agreed to resolve this issue through an arbitration which was heard in Texas, in accordance with the rules of the American Arbitration Association, in the fourth quarter of 2011. The Company now expects to receive the arbitrator’s decision in the second quarter of 2012. At this time no amount has been accrued in the financial statements as the Company does not consider it probable that a loss will be incurred. The disputed amount at March 31, 2012 is $10.9 million (December 31, 2011 - $9.6 million).

Gran Tierra’s production from the Costayaco field is subject to an additional royalty that applies when cumulative gross production from a commercial field is greater than five million barrels. This additional royalty is calculated on the difference between a trigger price defined by the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) and the sales price. The ANH has requested that the additional compensation be paid with respect to production from wells relating to the Moqueta discovery and has initiated a non-compliance procedure under the Chaza Contract. The Moqueta discovery is not located in the Costayaco Exploitation Area. Further, Gran Tierra views the Costayaco field and the Moqueta discovery as two clearly separate and independent hydrocarbon accumulations. Therefore, it is Gran Tierra’s view that it is clear that, pursuant to the Chaza Contract, the additional compensation payments are only to be paid with respect to production from the Moqueta wells when the accumulated oil production from any new Exploitation Area created with respect to the Moqueta discovery exceeds five million barrels. As at March 31, 2012, total cumulative production from the Moqueta field was 0.4 MMbbl. The estimated compensation which would be payable on cumulative production to date if the ANH’s interpretation is successful is $7.4 million. At this time no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

Gran Tierra has several lawsuits and claims pending for which the Company currently cannot determine the ultimate result. Gran Tierra records costs as they are incurred or become probable and determinable. 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.

10. Financial Instruments, Fair Value Measurements and Credit Risk

At March 31, 2012, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable and accounts payable and accrued liabilities. 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.

Table of Contents

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, 2012, the Company did not have any financial assets or liabilities measured at fair value on the balance sheet and held no derivative instruments. The Company does not use derivative financial instruments for speculative purposes. The fair value of financial instruments at March 31, 2012 as disclosed above was determined using Level 3 inputs.

At March 31, 2011, the Replacement Warrants (Note 3) met the definition of a derivative. Because the exercise price of the Replacement Warrants was denominated in Canadian dollars, which is different from Gran Tierra’s functional currency, the Replacement Warrants were not considered indexed to Gran Tierra’s common shares and the Replacement Warrants could not be classified within equity. Therefore the Replacement Warrants were classified as a current liability on Gran Tierra’s condensed consolidated balance sheet. Furthermore, these derivative instruments did not qualify as fair value hedges or cash flow hedges, and accordingly, changes in their fair value were recognized as income or expense in the consolidated statement of operations and retained earnings with a corresponding adjustment to the fair value of derivative instruments recognized on the balance sheet. The fair value of the Replacement Warrants at March 31, 2011 was determined using Level 3 inputs (Note 6).

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

At March 31, 2012, 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 governments and financial institutions with strong investment grade ratings, or the equivalent in the Company’s operating areas. Any foreign currency transactions are conducted on a spot basis, with major financial institutions in the Company’s operating areas.

Most of the Company’s accounts receivable relate to uncollateralized sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues 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. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. For the three months ended March 31, 2012, the Company had one significant customer for its Colombian oil, Ecopetrol, and in Argentina the Company had two significant customers, Shell and Refiner.

Additionally, foreign exchange gains and losses mainly result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, monetary liabilities, which are mainly denominated in the local currency of the Colombian foreign 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 $104,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

11. Bank Debt and Credit Facilities

Effective July 30, 2010, a subsidiary of Gran Tierra, Solana, established a credit facility with BNP Paribas for a three-year term which may be extended or amended by agreement between the parties. This reserve-based facility has a maximum borrowing base up to $100 million and is supported by the present value of the petroleum reserves of two of the Company’s subsidiaries with operating branches in Colombia – Gran Tierra Colombia and Solana Petroleum Exploration (Colombia) Ltd. The initial committed borrowing base is $20 million. Amounts drawn down under the facility bear interest at the U.S. dollar LIBOR rate plus 3.5%. In addition, a stand-by fee of 1.5% per annum is charged on the unutilized balance of the committed borrowing base and is included in G&A expenses. Under the terms of the facility, the Company is required to maintain and was in compliance with certain financial and operating covenants. As at March 31, 2012 and December 31, 2011, the Company had not drawn down any amounts under this facility. In February 2012, BNP Paribas announced the sale of its North American reserve-based lending business to Wells Fargo Bank National Association. Solana’s credit facility is expected to be part of that sale. Closing documents are being processed, and the sale is expected to be finalized in the second quarter of 2012.

12. Related Party Transactions

On January 12, 2011, the Company entered into an agreement to sublease office space to a company of which Gran Tierra’s President and Chief Executive Officer serves as an independent director. The term of the sublease runs from February 1, 2011 to January 30, 2013 and the sublease payment is $4,400 per month plus approximately $5,600 of operating and other expense.

On August 3, 2010, Gran Tierra entered into a contract related to the Peru drilling program with a company for which one of Gran Tierra’s directors is a shareholder and director. For the three months ended March 31, 2012, $nil million was incurred and capitalized under this contract (three months ended March 31, 2011 - $2.0 million) and at March 31, 2012, $nil was included in accounts payable related to this contract (December 31, 2011 - $nil).

On February 1, 2009, the Company entered into a sublease for office space with a company, of which one of Gran Tierra’s directors is a shareholder and director. The term of the sublease ran from February 1, 2009 to August 31, 2011 and the sublease payment was $8,000 per month plus approximately $4,700 for operating and other expenses.

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 Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K, filed with the U.S. Securities and Exchange Commission (“SEC”) on February 27, 2012.

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, Argentina, Peru, and Brazil, and we are headquartered in Calgary, Alberta, Canada. Our reportable segments are Colombia, Argentina and Peru. Brazil is not a reportable segment because the level of activity in Brazil is not significant at this time. For the three months ended March 31, 2012, 89% (three months ended March 31, 2011 - 96%) of our revenue and other income was generated in Colombia.

Table of Contents

Highlights

	Three Months Ended March 31,
	2012			2011		% Change

Production (BOEPD) (1)		16,742			14,546		15

Prices Realized - per BOE	$	101.90		$	93.41		9

Revenue and Other Income ($000s)	$	155,951		$	122,519		27

Net (Loss) Income ($000s)	$	(313	)	$	13,713		(102	)

Net (Loss) Income Per Share - Basic	$	(0.00	)	$	0.05		(100	)

Net (Loss) Income Per Share - Diluted	$	(0.00	)	$	0.05		(100	)

Funds Flow From Operations ($000s) (2)	$	78,943		$	66,560		19

Capital Expenditures ($000s)	$	87,591		$	69,103		27

	As at
	March 31, 2012		December 31, 2011		% Change

Cash & Cash Equivalents ($000s)	$	230,076	$	351,685		(35	)

Working Capital (including cash & cash equivalents) ($000s)	$	171,505	$	213,100		(20	)

Property, Plant & Equipment ($000s)	$	1,069,591	$	1,044,842		2

(1) Production represents production volumes NAR adjusted for inventory changes. 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, which rate is not necessarily indicative of the relationship of oil and gas prices.

(2) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under generally accepted accounting principles in the United States of America (“GAAP”). Management uses this financial measure to analyze operating performance and the income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is also useful supplemental information for investors to analyze operating performance and our financial results. Investors should be cautioned that this measure should not be construed as an alternative to net income 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 operations, as presented, is net (loss) income adjusted for depletion, depreciation, accretion and impairment (“DD&A”) expenses, deferred taxes, stock-based compensation, gain on financial instruments, unrealized foreign exchange loss, settlement of asset retirement obligation, equity tax and gain on acquisition. A reconciliation from funds flow from operations to net (loss) income is as follows:

Table of Contents

	Three Months Ended March 31,
Funds Flow From Operations - Non-GAAP Measure ($000s)	2012			2011

Net (loss) income	$	(313	)	$	13,713
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses		60,367			63,357
Deferred taxes		(5,250	)		(187	)
Stock-based compensation		3,192			3,453
Gain on financial instruments		-			(62	)
Unrealized foreign exchange loss		21,351			4,458
Settlement of asset retirement obligation		(404	)		(4	)
Equity tax		-			6,132
Gain on acquisition		-			(24,300	)
Funds flows from operations	$	78,943		$	66,560

Operational Highlights

In the first quarter of 2012, oil and natural gas production, NAR and adjusted for inventory changes, averaged 16,742 BOEPD, an increase of 15% over the first quarter of 2011. The increase was due to increased production from the Moqueta and Jilguero fields in Colombia and the Neuquen Basin in Argentina, partially offset by the impact of pipeline disruptions and an increase in pipeline inventory as a result of the change in the sales point in Colombia.

In Colombia, the Ramiriqui-1 oil exploration well reached total depth at 19,519 feet measured depth (“MD”) in basement. Along with our operating partner Compania Espanola de Petroleos, S.A.U. (“CEPSA”), we completed initial testing on the well with natural flow rates, without pumps, of up to 2,525 BOPD gross over 32.5 hours with a 28/64 inch choke and a 0.12% watercut with 26°API gravity oil from the Mirador formation. The Ramiriqui-1 well flowed at a restricted rate due to gas flaring limitations. We are awaiting approval from the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) of the transfer of our 45% working interest in this Block.

In Colombia, we completed the Moqueta 3D seismic program with interpretation ongoing to assist in full field development planning.

In Argentina, we completed drilling and testing the Proa -2 appraisal well, the second well in the Proa oil field. The well went on production in the second quarter of 2012 at a constrained rate of approximately 2,000 BOPD gross to further analyze reservoir performance while additional transportation capacity is evaluated.

In Brazil, the 3-GTE-03D-BA appraisal well reached a total depth of 2,273 meters MD during the first quarter of 2012 and oil bearing reservoir intervals were encountered. Additionally, a second appraisal well, 3-GTE-4DPA-BA, encountered the Agua Grande formation at 2,065 meters MD and the Sergi formation at 2,182 meters MD.

In September 2011, we announced two farmout agreements with Statoil do Brasil Ltda. ("Statoil") in a joint venture with PetróleoBrasileiro S.A. ("Petrobras"), in Brazil’s deepwater offshore Camamu-Almada Basin, pursuant to which, we would receive an assignment of a non-operated 10% working interest in Block BM-CAL-7 and a non-operated 15% working interest in Block BM-CAL-10. On February 17, 2012, in accordance with the terms of the farmout agreement, we gave notice to Statoil that we would not enter into and assume our share of the work obligations of the second exploration period of Block BM-CAL-10. As a result, the farmout agreement has terminated and we will not receive any interest in the block. We paid $23.8 million in the second quarter of 2012 related to our obligation on this farmout agreement.

During the first quarter of 2012, we received regulatory approval from the ANP in Brazil for the Block BM-CAL-7 farmout agreement and the assignment became effective on April 3, 2012.

On January 20, 2012, we entered into a purchase and sale agreement to acquire the remaining 30% participating interest in Blocks 129, 142, 155 and 224 in the Recôncavo Basin in Brazil from our partner. The completion of the purchase is subject to ANP approval.

Financial Highlights

●

Revenue and other income increased by 27% to $156.0 million in the first quarter of 2012 compared with $122.5 million in the first quarter of 2011 due to increased production and higher oil prices. Average oil and NGL prices realized per bbl in the first quarter of 2012 were $105.36, an increase of 12% compared with $94.31 in the first quarter of 2011.

●

We incurred a net loss of $0.3 million in the first quarter of 2012, representing basic and diluted net loss per share of $nil. This compares with net income of $13.7 million, or $0.05 per share basic and diluted in the first quarter of 2011. In the first quarter of 2012, increased oil and natural gas sales, reduced impairment charges and no Colombian equity tax expense were more than offset by a $24.4 million foreign exchange loss, the absence of the comparative period gain on acquisition, increased operating, depletion, depreciation and accretion and general and administrative ("G&A") expenses and increased income taxes. Net income in the comparable quarter in 2011 included a gain on the acquisition of Petrolifera Petroleum Limited (“Petrolifera”) of $24.3 million and Colombian equity tax of $8.1 million. The Colombian equity tax is assessed every four years.

●

Funds flow from operations increased by 19% to $78.9 million in the first quarter of 2012 from $66.6 million in the first quarter of 2011. The increase was primarily due to increased oil and natural gas sales and no Colombian equity tax expense, partially offset by increased operating and G&A expenses.

●

Cash and cash equivalents was $230.1 million at March 31, 2012 compared with $351.7 million at December 31, 2011. The change in cash and cash equivalents during the first quarter of 2012 was primarily the result of funds flow from operations of $78.9 million and proceeds from issuance of common shares of $0.9 million being more than offset by an increase in net assets from operating activities of $92.4 million, $78.0 million of capital expenditures and a $31.0 million increase in restricted cash during the first quarter of 2012.

Table of Contents

●

Working capital (including cash and cash equivalents) was $171.5 million at March 31, 2012, a $41.6 million decrease from December 31, 2011.The decrease is a result of a $121.6 million decrease in cash and cash equivalents and a $24.8 million increase in taxes payable due to increased taxable income in Colombia, partially offset by a $76.2 million increase in accounts receivable due to increased sales and the timing of collection of receivables, a $7.2 million increase in inventory due to the new transportation agreement in Colombia and a $21.0 million decrease in accounts payable and accrued liabilities. The decrease in accounts payable and accrued liabilities was primarily the result of a $19.0 million reduction in royalties payable due to the timing of royalty payments and a $13.7 million reduction in VAT payable, partially offset by a $12.0 million increase in capital expenditure related liabilities. Capital expenditure related accounts payable included $23.8 million related to the Block BM-CAL-10 at March 31, 2012.

●

Property, plant and equipment at March 31, 2012 was $1.1 billion, an increase of $24.7 million from December 31, 2011, as a result of $87.6 million of capital expenditures, partially offset by $62.9 million of depletion, depreciation and impairment expenses.

Business combination

On March 18, 2011, we completed the acquisition of all the issued and outstanding common shares and warrants of Petrolifera pursuant to the terms and conditions of an arrangement agreement dated January 17, 2011. Petrolifera is a Calgary-based oil, natural gas and NGL exploration, development and production company active in Argentina, Colombia and Peru. For further details reference should be made to Note 3 of the consolidated financial statements.

The acquisition was accounted for using the acquisition method, with Gran Tierra being the acquirer, whereby Petrolifera’s assets acquired and liabilities assumed were recorded at their fair values as at the acquisition date and the results of Petrolifera were consolidated with those of Gran Tierra from that date.

As indicated in the allocation of the consideration transferred, the fair value of identifiable assets acquired and liabilities assumed exceeded the fair value of the consideration transferred. Consequently, we reassessed the recognition and measurement of identifiable assets acquired and liabilities assumed and concluded that all acquired assets and assumed liabilities were recognized and that the valuation procedures and resulting measures were appropriate. As a result, we recognized a gain on acquisition of $24.3 million in the consolidated statement of operations for the three months ended March 31, 2011. Subsequent to the initial allocation of the consideration in the first quarter of 2011, further assessments of Petrolifera’s tax position resulted in a reduction of the gain on acquisition to $21.7 million. The gain reflects the impact on Petrolifera’s pre-acquisition market value resulting from their lack of liquidity and capital resources required to maintain current production and reserves and further develop and explore their inventory of prospects.

Business Environment Outlook

Our revenues have been significantly affected by the continuing fluctuations in oil prices. Oil prices are volatile and unpredictable and are influenced by concerns about financial markets and the impact of the worldwide economy on oil demand growth. However, based on projected production, prices, costs and our current liquidity position, we believe that our current operations and 2012 capital expenditure program can be maintained from cash flow from existing operations and cash on hand, barring unforeseen events or a downturn in oil and gas prices. Should our operating cash flow decline, we would examine measures such as reducing our capital expenditure program, possible periodic draws from our revolving credit facility, issuance of debt, disposition of assets, or issuance of equity. The continuing uncertainty regarding the Middle East and continued economic instability in the United States and Europe is having an impact on world markets, and we are unable to determine the impact, if any, these events may have on oil prices and demand.

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 our common stock. If the price of our common stock declines, our ability to utilize our stock to raise capital may be negatively affected. Also, raising funds by issuing stock or other equity securities would further dilute our existing shareholders, and this dilution would be exacerbated by a decline in our stock 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 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.

Table of Contents

Consolidated Results of Operations

	Three Months Ended March 31,
	2012			2011			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	155,248		$	122,296			27
Interest income		703			223			215
		155,951			122,519			27

Operating expenses		24,487			16,396			49
DD&A expenses		60,367			63,357			(5	)
G&A expenses		15,899			13,638			17
Equity tax		-			8,050			-
Financial instruments gain		-			(230	)		-
Gain on acquisition		-			(24,300	)		-
Foreign exchange loss		24,375			5,199			369
		125,128			82,110			52

Income before income taxes		30,823			40,409			(24	)
Income tax expense		(31,136	)		(26,696	)		17
Net (loss) income	$	(313	)	$	13,713			(102	)

Production

Oil and NGL's, bbl		1,461,404			1,293,453			13
Natural gas, Mcf		372,947			94,317			295
Total production, BOE (1)		1,523,562			1,309,173			16

Average Prices

Oil and NGL's, per bbl	$	105.36		$	94.31			12
Natural gas, per Mcf	$	3.42		$	3.35			2

Consolidated Results of Operations (per BOE)

Oil and natural gas sales	$	101.90		$	93.41			9
Interest income		0.46			0.17			171
		102.36			93.58			9

Operating expenses		16.07			12.52			28
DD&A expenses		39.62			48.39			(18	)
G&A expenses		10.44			10.42			-
Equity tax		-			6.15			-
Financial instruments gain		-			(0.18	)		-
Gain on acquisition		-			(18.56	)		-
Foreign exchange loss		16.00			3.97			303
		82.13			62.71			31

Income before income taxes		20.23			30.87			(34	)
Income tax expense		(20.44	)		(20.39	)		-
Net (loss) income	$	(0.21	)	$	10.48			(102	)

Net loss was $0.3 million, or $nil per share basic and diluted, for the first quarter of 2012 compared with net income of $13.7 million, or $0.05 per share basic and diluted, for the comparable quarter in 2011. In the first quarter of 2012, increased oil and natural gas sales due to increased production and higher realized oil prices, reduced impairment charges and no Colombian equity tax expense were more than offset by a $24.4 million foreign exchange loss, the absence of the comparative period gain on acquisition, increased operating, depletion, depreciation and accretion and G&A expenses and increased income taxes. The Colombian equity tax is assessed every four years. Net income in the comparable quarter in 2011 included a gain on the acquisition of Petrolifera of $24.3 million.

Oil and NGL production, NAR and adjusted for inventory changes, for the first quarter of 2012 increased to 1.5 MMbbl compared with 1.3 MMbbl for the comparable quarter in 2011 primarily due to increased production from the Moqueta and Jilguero fields in Colombia and the addition of the Neuquen Basin in Argentina, from the acquisition of Petrolifera in March 2011. Production during the first quarter of 2012 reflects approximately 26 days of oil delivery restrictions due to three separate disruptions in the Ecopetrol-operated Trans-Andean oil pipeline (“the OTA pipeline”) in Colombia. We continued production at a reduced rate while the OTA pipeline was down, selling a portion of our oil through trucking and storing excess oil, resulting in a reduction in oil production, NAR and adjusted for inventory changes, of approximately 800 BOPD for the first quarter of 2012.

Also, as a result of entering into new oil sales and transportation agreements with Ecopetrol as of February 1, 2012, which changed the sales point of oil from Orito station to Tumaco Port, our reported oil inventory increased representing ownership of oil in the OTA pipeline and associated Ecopetrol owned facilities. This change in sales point and the increase in pipeline inventory had a corresponding one-time reduction in oil production, NAR and adjusted for inventory changes, of approximately 1,040 BOPD for the first quarter of 2012.

Production during the first quarter of 2011 was adversely affected by a maintenance program at the Tumaco Port offloading terminal between December 28, 2010 and February 7, 2011 which reduced sales through the OTA pipeline.

Table of Contents

Average realized oil prices in the first quarter of 2012 increased by 12% to $105.36 per bbl from $94.31 per bbl in 2011 reflecting higher oil prices. The average West Texas Intermediate (“WTI”) oil price for the first quarter of 2012 was $102.89 per bbl compared with $93.95 per bbl in the comparable quarter in 2011. Average Brent oil price for the first quarter of 2012 was $118.56 per bbl.

Increased production and higher oil prices resulted in a 27% increase in revenue and other income to $156.0 million for the first quarter of 2012 compared with $122.5 million in the comparable quarter in 2011.

Operating expenses for the first quarter of 2012 amounted to $24.5 million, or $16.07 per BOE, compared with $16.4 million, or $12.52 per BOE, in the comparable quarter in 2011. The increase in operating expenses was due to an increase of $3.7 million in Colombia, $3.8 million in Argentina and $0.6 million in Brazil.

DD&A expenses for the first quarter of 2012 decreased to $60.4 million compared with $63.4 million for the comparable quarter in 2011. DD&A expenses for the first quarter of 2012 included a $20.2 million ceiling test impairment in our Brazil cost center. The impairment loss related to seismic and drilling costs on Block BM-CAL-10. The farmout agreement for that block terminated during the first quarter of 2012 when we provided notice that we would not enter into the second exploration period. DD&A expenses for the comparable quarter in 2011 included a $31.9 million ceiling test impairment in our Peru cost center relating to seismic and drilling costs from a dry well.

The remaining increase in DD&A expenses was due to higher production levels and increased future development costs included in the depletable base, partially offset by an increase in reserves. On a BOE basis, DD&A expenses in 2012 were $39.62 compared with $48.39 for 2011, representing an 18% decrease. Excluding the effects of impairment charges, DD&A expenses were $26.36 per BOE in the first quarter of 2012, compared with $24.02 per BOE in the comparable period in 2011.

G&A expenses of $15.9 million for the first quarter of 2012 increased by 17% from $13.6 million in the comparable quarter in 2011 primarily due to a full quarter of Petrolifera G&A expenses and increased employee related costs reflecting the expanded operations in all business segments, partially offset by the absence of $1.2 million of expenses associated with the acquisition of Petrolifera recorded in the first quarter of 2011. G&A expenses per BOE were comparable with the first quarter in 2011 at $10.44 per BOE.

Equity tax in the three months ended March 31, 2011 represents a Colombian tax of 6% on a legislated measure which is based on our Colombian segment’s balance sheet equity at January 1, 2011. The equity tax is assessed every four years.

Gain on acquisition of $24.3 million in the three months ended March 31, 2011 related to the Petrolifera acquisition. This gain reflects the impact on Petrolifera’s pre-acquisition market value of its lack of liquidity and capital resources required to maintain production and reserves and further develop and explore its inventory of prospects.

Foreign exchange loss of $24.4 million for the first quarter of 2012, of which $21.4 million was an unrealized non-cash foreign exchange loss, primarily represents a foreign exchange loss resulting from the translation of current and deferred tax liabilities in Colombia. In the first quarter of 2011, the foreign exchange loss was $5.2 million, of which $4.5 million was an unrealized non-cash foreign exchange loss. Under GAAP, deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation results in the recognition of unrealized exchange losses or gains. The Colombian Peso strengthened by 8% and 2% against the U.S. dollar in the three months ended March 31, 2012 and 2011, respectively.

Income tax expense for the first quarter of 2012 was $31.1 million compared with $26.7 million recorded in the comparable quarter in 2011. The increase was primarily due to higher income. For the three months ended March 31, 2012, the effective tax rate was 101% compared with 66% in the comparable quarter in 2011. The change was primarily due to a non-taxable gain on acquisition being recorded in 2011 and an increase in the non-deductible unrealized foreign currency translation loss in 2012. The variance from the 35% U.S. statutory rate for the first quarter of 2012 results from non-deductible foreign currency translation losses and an increase in valuation allowances taken on losses incurred in the U.S., Canada, Argentina, Peru and Brazil. The variance from the 35% U.S. statutory rate for the first quarter of 2011 was primarily attributable to non-deductible foreign currency translation losses as described above and an increase in valuation allowances taken on losses incurred in the U.S., Canada, Argentina, Peru and Brazil, offset partially by the inclusion of the non-taxable gain on acquisition.

2012 Work Program and Capital Expenditure Program

Our capital expenditures during the first quarter of 2012 were $87.6 million (including changes in non-cash working capital) compared with $69.1 million in the comparable quarter in 2011. In 2012, capital expenditures included drilling and acquisition expenditures of $60.7 million, geological and geophysical (“G&G”) expenditures of $22.2 million, facilities expenditures of $2.3 million and other expenditures of $2.4 million.

Our capital program for 2012 has been revised to $444 million from $367 million. This includes $196 million for Colombia, an increase of $14 million due primarily to additional facilities costs on the Garibay and Chaza Blocks and testing of the successful Ramiriqui-1 oil exploration well; $122 million for Brazil, an increase of $54 million due primarily to the acquisition of the remaining 30% working interest in four onshore blocks and associated proportional increase in work program; $47 million for Argentina, a $7 million decrease primarily due to the deferral of drilling in the Santa Victoria block into the first quarter of 2013; and $78 million for Peru, a $16 million increase primarily due to the acquisition costs of an over-riding royalty interest in Block 107; and $1 million associated with corporate activities. Of this, $294 million is for drilling and acquisitions, $58 million is for facilities and pipelines and $92 million is for G&G expenditures. Of the $294 million allocated to drilling and acquisitions, approximately $140 million is for exploration, $43 million is for acquisitions and the balance is for delineation and development drilling.

Our 2012 work program is intended to create both growth and value through strategic acquisitions of working interests, by leveraging existing assets to increase reserves and production levels and through the construction of pipelines and facilities in the areas with proved reserves. We are financing our capital program through cash flows from operations and cash on hand, while retaining financial flexibility with a strong cash position and no debt, so that we can be positioned 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 will be expended as set forth in our 2012 work program, there may be circumstances where, for sound business reasons, actual expenditures may in fact differ.

Excluding potential exploration success, average production in 2012 is expected to range between 20,000 and 21,000 BOEPD NAR.

Table of Contents

Segmented Results – Colombia

	Three Months Ended March 31,
	2012		2011		% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	138,633	$	117,304		18
Interest income		204		87		134
		138,837		117,391		18

Operating expenses		16,474		12,785		29
DD&A expenses		32,286