Edgar Filing: GRAN TIERRA ENERGY INC.

GTE - 2014.03.31 - 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2014



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

For the transition period from __________ to __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)



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

300, 625 11 Avenue S.W. Calgary, Alberta, Canada T2R 0E1
(Address of principal executive offices, including zip code)

(403) 265-3221

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý

On May 1, 2014, the following number of shares of the registrant’s capital stock were outstanding: 272,948,937 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 4,534,127 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 5,980,993 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, 2014

Table of contents



		Page
PART I	Financial Information
Item 1.	Financial Statements	8
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	40

PART II	Other Information
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	41
Item 6.	Exhibits	56
SIGNATURES		56
EXHIBIT INDEX		57

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q, particularly in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including without limitation statements in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “objective”, “should”, or similar expressions or variations on these expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct or that, even if correct, intervening circumstances will not occur to cause actual results to be different than expected. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, those set out in Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q. The information included herein is given as of the filing date of this Form 10-Q with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

In this document, the abbreviations set forth below have the following meanings:



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

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

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

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

We also refer to royalties and farm-in or farm-out transactions. Royalties include payments to governments on the production of oil and gas, either in kind or in cash. Royalties also include overriding royalties paid to third parties. Our reserves, production volumes and sales are reported net after deduction of royalties. 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 efficient way of gathering data over large regions.

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

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

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

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

•

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


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

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


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


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


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


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


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


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


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


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

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


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


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

ii.

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


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


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


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


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


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


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


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

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

vi.

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

•

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


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


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


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


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


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


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


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


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

iii.

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

PART I - Financial Information

Item 1. Financial Statements

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Operations and Retained Earnings (Unaudited)

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



	Three Months Ended March 31,
	2014			2013
REVENUE AND OTHER INCOME
Oil and natural gas sales	$	168,525		$	204,780
Interest income	1,154			591
	169,679			205,371
EXPENSES
Operating	28,293			41,015
Depletion, depreciation, accretion and impairment	53,157			58,412
General and administrative	15,204			11,421
Foreign exchange loss (gain)	126			(5,229		)
Financial instruments gain (Note 9)	(2,409		)	—
Other loss (Notes 8 and 9)	—			4,400
	94,371			110,019

INCOME BEFORE INCOME TAXES	75,308			95,352
Income tax expense (Note 7)	(30,179		)	(37,439		)
NET INCOME AND COMPREHENSIVE INCOME	45,129			57,913
RETAINED EARNINGS, BEGINNING OF PERIOD	410,961			284,673
RETAINED EARNINGS, END OF PERIOD	$	456,090		$	342,586

NET INCOME PER SHARE — BASIC	$	0.16		$	0.21
NET INCOME PER SHARE — DILUTED	$	0.16		$	0.20
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)	283,235,202			282,138,525
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)	288,636,904			285,026,183

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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



	March 31,		December 31,
	2014		2013
ASSETS
Current Assets
Cash and cash equivalents	$	390,953	$	428,800
Restricted cash	394		1,478
Accounts receivable	106,517		49,703
Other financial instruments (Note 9)	2,409		—
Inventory (Note 4)	14,407		13,725
Taxes receivable	13,921		9,980
Prepaids	7,025		6,450
Deferred tax assets (Note 7)	770		2,256
Total Current Assets	536,396		512,392

Oil and Gas Properties (using the full cost method of accounting)
Proved	795,830		794,069
Unproved	489,817		456,001
Total Oil and Gas Properties	1,285,647		1,250,070
Other capital assets	10,059		10,102
Total Property, Plant and Equipment (Note 4)	1,295,706		1,260,172

Other Long-Term Assets
Restricted cash	2,876		2,300
Deferred tax assets (Note 7)	1,375		1,407
Taxes receivable	14,246		18,535
Other long-term assets	6,815		7,163
Goodwill	102,581		102,581
Total Other Long-Term Assets	127,893		131,986
Total Assets	$	1,959,995	$	1,904,550
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	51,734	$	72,400
Accrued liabilities	103,692		89,567
Taxes payable	121,877		102,887
Deferred tax liabilities (Note 7)	1,265		1,193
Asset retirement obligation (Note 6)	518		518
Total Current Liabilities	279,086		266,565

Long-Term Liabilities
Deferred tax liabilities (Note 7)	169,798		177,082
Asset retirement obligation (Note 6)	22,654		21,455
Other long-term liabilities	10,776		9,540
Total Long-Term Liabilities	203,228		208,077

Contingencies (Note 8)
Shareholders’ Equity
Common Stock (Note 5) (272,792,843 and 272,327,810 shares of Common Stock and 10,528,740 and 10,882,440 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2014, and December 31, 2013, respectively)	10,187		10,187
Additional paid in capital	1,011,404		1,008,760
Retained earnings	456,090		410,961
Total Shareholders’ Equity	1,477,681		1,429,908
Total Liabilities and Shareholders’ Equity	$	1,959,995	$	1,904,550

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Three Months Ended March 31,
	2014			2013
Operating Activities
Net income	$	45,129		$	57,913
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, accretion and impairment	53,157			58,412
Deferred tax recovery (Note 7)	(2,260		)	(7,450		)
Stock-based compensation	1,591			2,067
Unrealized foreign exchange gain	(4,178		)	(6,744		)
Unrealized financial instrument gain (Note 9)	(2,409		)	—
Other loss (Notes 8 and 9)	—			4,400
Net change in assets and liabilities from operating activities
Accounts receivable and other long-term assets	(54,728		)	(29,387		)
Inventory	(318		)	11,643
Prepaids	(575		)	(258		)
Accounts payable and accrued and other liabilities	(19,259		)	(14,731		)
Taxes receivable and payable	20,014			33,926
Net cash provided by operating activities	36,164			109,791

Investing Activities
Decrease (increase) in restricted cash	507			(738		)
Additions to property, plant and equipment	(75,146		)	(87,378		)
Net cash used in investing activities	(74,639		)	(88,116		)

Financing Activities
Proceeds from issuance of shares of Common Stock (Note 5)	628			1,611
Net cash provided by financing activities	628			1,611

Net (decrease) increase in cash and cash equivalents	(37,847		)	23,286
Cash and cash equivalents, beginning of period	428,800			212,624
Cash and cash equivalents, end of period	$	390,953		$	235,910

Cash	$	368,142		$	230,767
Term deposits	22,811			5,143
Cash and cash equivalents, end of period	$	390,953		$	235,910

Supplemental cash flow disclosures:
Cash paid for income taxes	$	7,453		$	13,103

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of period	$	87,859		$	66,536

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Three Months Ended March 31,		Year Ended December 31,
	2014		2013
Share Capital
Balance, beginning of period	$	10,187	$	7,986
Issue of shares of Common Stock (Note 5)	—		2,201
Balance, end of period	10,187		10,187

Additional Paid in Capital
Balance, beginning of period	1,008,760		998,772
Exercise of stock options (Note 5)	628		1,570
Stock-based compensation (Note 5)	2,016		8,418
Balance, end of period	1,011,404		1,008,760

Retained Earnings
Balance, beginning of period	410,961		284,673
Net income	45,129		126,288
Balance, end of period	456,090		410,961

Total Shareholders’ Equity	$	1,477,681	$	1,429,908

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Notes to the Condensed Consolidated Financial Statements (Unaudited)

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

1. Description of Business

Gran Tierra Energy Inc., a Nevada corporation (the “Company” or “Gran Tierra”), is a publicly traded oil and gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties. The Company’s principal business activities are in Colombia, 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, 2013, included in the Company’s 2013 Annual Report on Form 10-K, filed with the Securities and Exchange Commission (“SEC”) on February 26, 2014.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2013 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.

Foreign Currency Derivatives

In February 2014, the Company purchased Colombian peso non-deliverable forward contracts for purposes of fixing the exchange rate at which it will purchase Colombian pesos to settle its income tax installment payments due in April and June 2014 (Note 9). The Company does not intend to issue or hold derivative financial instruments for speculative trading purposes.

The Company records derivative instruments on the balance sheet as either an asset or liability measured at fair value. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Generally because of the short-term nature of the contracts and their limited use, the Company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in net income as financial instrument gains or losses in the condensed consolidated statement of operations. Cash settlements of the Company's derivative arrangements are classified as operating cash flows.

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

Recently Adopted Accounting Pronouncements

Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is fixed at the Reporting Date

In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013- 04, “Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is fixed at the Reporting Date”. The ASU provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. The ASU was effective for fiscal years, and interim periods within those years, beginning after

December 15, 2013. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations, cash flows or disclosure.

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

In July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists". The ASU provides guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The implementation of this update did not materially impact the Company’s consolidated financial position, results of operations, cash flows, or disclosure.

3. 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, Peru and Brazil based on geographic organization. The level of activity in Brazil was not significant at March 31, 2014, or December 31, 2013; however, the Company has separately disclosed its results of operations in Brazil as a reportable segment. The All Other category represents the Company’s corporate activities. The Company evaluates reportable segment performance based on income or loss before income taxes.

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



	Three Months Ended March 31, 2014
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	144,935	$	17,420		$	—		$	6,170		$	—		$	168,525
Interest income	137		404			—			425			188			1,154
Depletion, depreciation, accretion and impairment	41,250		8,893			208			2,579			227			53,157
Depletion, depreciation, accretion and impairment - per unit of production	25.44		32.23			—			38.89			—			27.07
Income (loss) before income taxes	86,011		(4,152		)	(2,058		)	1,950			(6,443		)	75,308
Segment capital expenditures	50,543		6,536			20,893			10,366			299			88,637
	Three Months Ended March 31, 2013
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	180,003	$	18,540		$	—		$	6,237		$	—		$	204,780
Interest income	161		243			14			9			164			591
Depletion, depreciation, accretion and impairment	45,956		7,950			62			4,171			273			58,412
Depletion, depreciation, accretion and impairment - per unit of production	26.32		26.68			—			65.34			—			27.71
Income (loss) before income taxes	101,668		(1,636		)	(1,227		)	(439		)	(3,014		)	95,352
Segment capital expenditures	30,407		4,805			29,247			14,539			11			79,009

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

In the three months ended March 31, 2014, the Company had two significant customers in Colombia: Ecopetrol S.A. ("Ecopetrol") and one other customer, which accounted for 43% and 37%, respectively, of the Company's consolidated oil and natural gas sales. In the three months ended March 31, 2013, the Company had three significant customers in Colombia, Ecopetrol and two other customers, which accounted for 54%, 21% and 11%, respectively, of the Company's consolidated oil and natural gas sales.



	As at March 31, 2014
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		All Other		Total
Property, plant and equipment	$	859,500	$	92,103	$	199,216	$	141,773	$	3,114	$	1,295,706
Goodwill	102,581		—		—		—		—		102,581
All other assets	262,269		35,646		27,850		24,336		211,607		561,708
Total Assets	$	1,224,350	$	127,749	$	227,066	$	166,109	$	214,721	$	1,959,995

	As at December 31, 2013
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		All Other		Total
Property, plant and equipment	$	850,359	$	94,366	$	178,531	$	133,874	$	3,042	$	1,260,172
Goodwill	102,581		—		—		—		—		102,581
All other assets	233,336		39,209		24,240		24,477		220,535		541,797
Total Assets	$	1,186,276	$	133,575	$	202,771	$	158,351	$	223,577	$	1,904,550

4. Property, Plant and Equipment and Inventory

Property, Plant and Equipment



	As at March 31, 2014							As at December 31, 2013
(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	$	1,853,547	$	(1,057,717	)	$	795,830	$	1,799,544	$	(1,005,475	)	$	794,069
Unproved	489,817		—			489,817		456,001		—			456,001
	2,343,364		(1,057,717		)	1,285,647		2,255,545		(1,005,475		)	1,250,070
Furniture and fixtures and leasehold improvements	9,182		(6,989		)	2,193		8,919		(6,568		)	2,351
Computer equipment	15,297		(8,019		)	7,278		14,786		(7,605		)	7,181
Automobiles	1,425		(837		)	588		1,381		(811		)	570
Total Property, Plant and Equipment	$	2,369,268	$	(1,073,562	)	$	1,295,706	$	2,280,631	$	(1,020,459	)	$	1,260,172

Depletion and depreciation expense on property, plant and equipment for the three months ended March 31, 2014, was $53.1 million (three months ended March 31, 2013 - $54.6 million). A portion of depletion and depreciation expense was recorded as inventory in each period and adjusted for inventory changes.

In Brazil, the exploration phase of the concession agreements on Blocks REC-T-129, REC-T-142 and REC-T-155 were each due to expire on November 24, 2013, and the exploration phase of the concession agreement on Block REC-T-224 was due to expire on December 11, 2013; however, under the concession agreements the Company was able and did submit applications to the Agência Nacional de Petróleo, Gás Natural e Biocombustíveis ("ANP") for extensions or suspensions of the exploration phases of these blocks. The Company has not yet received a decision from the ANP regarding these extension or suspension applications. At March 31, 2014, unproved properties included $71.9 million relating to exploration expenditures on these four blocks. Management assessed these blocks for impairment at March 31, 2014, and concluded no impairment had occurred.

In Argentina, Rio Negro Province has enacted legislation that changes the royalty regime associated with concession agreement extensions. The Company is negotiating concession agreement extensions and royalty rates for its Puesto Morales, Puesto Morales Este, Rinconada Norte and Rinconada Sur Blocks and expects that royalty rates in Rio Negro Province will likely increase and a bonus payment, not determinable at this time, may be payable for the concession agreement extensions.

Unproved oil and natural gas properties consist of exploration lands held in Colombia, Argentina, Peru and Brazil. As at March 31, 2014, the Company had $184.0 million (December 31, 2013 - $176.1 million) of unproved assets in Colombia, $17.7 million (December 31, 2013 - $18.2 million) of unproved assets in Argentina, $198.1 million (December 31, 2013 - $177.5 million) of unproved assets in Peru, and $90.0 million (December 31, 2013 - $84.2 million) of unproved assets in Brazil for a total of $489.8 million (December 31, 2013 - $456.0 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 warrants whether or not future areas will be developed.

Inventory

At March 31, 2014, oil and supplies inventories were $12.1 million and $2.3 million, respectively (December 31, 2013 - $11.7 million and $2.0 million, respectively).

5. 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, 2014, outstanding share capital consists of 272,792,843 shares of Common Stock of the Company, 5,994,613 exchangeable shares of Gran Tierra Exchangeco Inc., (the "Exchangeco exchangeable shares") and 4,534,127 exchangeable shares of Gran Tierra Goldstrike Inc. (the "Goldstrike exchangeable shares"). The redemption date for the Exchangeco exchangeable shares and the Goldstrike exchangeable shares is a date to be established by the applicable Board of Directors. During the three months ended March 31, 2014, 111,333 shares of Common Stock were issued upon the exercise of stock options and 353,700 shares of Common Stock were issued upon the exchange of the Exchangeco exchangeable shares.

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

Restricted Stock Units and Stock Options

The Company grants time-vested restricted stock units ("RSUs") to certain officers, employees and consultants. Additionally, the Company grants options to purchase shares of Common Stock to certain directors, officers, employees and consultants. The following table provides information about RSU and stock option activity for the three months ended March 31, 2014:



	RSUs		Options
	Number of Outstanding Share Units		Number of Outstanding Options		Weighted Average Exercise Price $/Option
Balance, December 31, 2013	922,045		15,668,458		5.41
Granted	835,490		2,237,630		7.09
Exercised	(292,608	)	(111,333	)	(5.64	)
Forfeited	(17,984	)	(84,156	)	(6.57	)
Expired	—		(67,668	)	(6.81	)
Balance, March 31, 2014	1,446,943		17,642,931		5.61

For the three months ended March 31, 2014, 111,333 shares of Common Stock were issued for cash proceeds of $0.6 million upon the exercise of 111,333 stock options (three months ended March 31, 2013 - $1.6 million).

The weighted average grant date fair value for options granted in the three months ended March 31, 2014, was $2.52 (three months ended March 31, 2013 - $3.33).

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



(Thousands of U.S. Dollars)	Three Months Ended March 31,
	2014			2013
Compensation costs for stock options	$	2,016		$	2,231
Compensation costs for RSUs	1,244			—
	3,260			2,231
Less: stock-based compensation costs capitalized	(783		)	(182		)
Stock-based compensation costs expensed	$	2,477		$	2,049

Of the total compensation expense for the three months ended March 31, 2014, $2.2 million (three months ended March 31, 2013 – $1.8 million) was recorded in general and administrative expenses and $0.3 million (three months ended March 31, 2013 – $0.2 million) was recorded in operating expenses.

At March 31, 2014, there was $16.1 million (December 31, 2013 - $8.1 million) of unrecognized compensation cost related to unvested stock options and RSUs which is expected to be recognized over a weighted average period of 2.2 years.

Net income per share

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



	Three Months Ended March 31,
	2014		2013
Weighted average number of common and exchangeable shares outstanding	283,235,202		282,138,525
Shares issuable pursuant to stock options	14,553,754		5,482,456
Shares assumed to be purchased from proceeds of stock options	(9,152,052	)	(2,594,798	)
Weighted average number of diluted common and exchangeable shares outstanding	288,636,904		285,026,183

For the three months ended March 31, 2014, 3,175,152 options (three months ended March 31, 2013 - 9,392,605 options) were excluded from the diluted income per share calculation as the options were anti-dilutive.

6. Asset Retirement Obligation

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



	Three Months Ended			Year Ended
(Thousands of U.S. Dollars)	March 31, 2014			December 31, 2013
Balance, beginning of year	$	21,973		$	18,292
Settlements	—			(2,068		)
Liability incurred	786			2,623
Foreign exchange	(5		)	(25		)
Accretion	418			1,279
Revisions in estimated liability	—			1,872
Balance, end of period	$	23,172		$	21,973

Asset retirement obligation - current	$	518		$	518
Asset retirement obligation - long-term	22,654			21,455
Balance, end of period	$	23,172		$	21,973

Revisions to estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling the asset retirement obligation. At March 31, 2014, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $2.0 million (December 31, 2013 - $1.9 million). These assets are included in restricted cash on the Company's balance sheet.

7. 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)	2014			2013
Income (loss) before income taxes
United States	$	(5,078	)	$	(2,091	)
Foreign	80,386			97,443
	75,308			95,352
	35		%	35		%
Income tax expense expected	26,358			33,373
Foreign currency translation adjustments	4,160			(1,878		)
Impact of foreign taxes	(1,093		)	(224		)
Stock-based compensation	760			686
(Decrease) increase in valuation allowance	(2,439		)	1,844
Branch and other foreign loss pick-up	254			(827		)
Non-deductible third party royalty in Colombia	2,223			3,547
Other permanent differences	(44		)	918
Total income tax expense	$	30,179		$	37,439

Current income tax expense
United States	$	357		$	306
Foreign	32,082			44,583
	32,439			44,889
Deferred income tax recovery
United States	—			—
Foreign	(2,260		)	(7,450		)
	(2,260		)	(7,450		)
Total income tax expense	$	30,179		$	37,439



	As at
(Thousands of U.S. Dollars)	March 31, 2014			December 31, 2013
Deferred Tax Assets
Tax benefit of operating loss carryforwards	$	45,630		$	47,154
Tax basis in excess of book basis	57,340			59,168
Foreign tax credits and other accruals	35,619			34,894
Tax benefit of capital loss carryforwards	4,838			4,769
Deferred tax assets before valuation allowance	143,427			145,985
Valuation allowance	(141,282		)	(142,322		)
	$	2,145		$	3,663

Deferred tax assets - current	$	770		$	2,256
Deferred tax assets - long-term	1,375			1,407
	2,145			3,663
Deferred tax liabilities - current	(1,265		)	(1,193		)
Deferred tax liabilities - long-term	(169,798		)	(177,082		)
	(171,063		)	(178,275		)
Net Deferred Tax Liabilities	$	(168,918	)	$	(174,612	)

As at March 31, 2014, the Company had operating loss carryforwards of $206.8 million (December 31, 2013 - $215.4 million) and capital loss carryforwards of $32.8 million (December 31, 2013 – $32.6 million) before valuation allowance. Of these operating loss carryforwards and capital loss carryforwards, $203.5 million (December 31, 2013 - $213.8 million) were losses generated by the foreign subsidiaries of the Company. In certain jurisdictions, the operating loss carryforwards expire between 2014 and 2033 and the capital loss carryforwards expire between 2016 and 2017, while certain other jurisdictions allow operating losses to be carried forward indefinitely.

As at March 31, 2014, the total amount of Gran Tierra’s unrecognized tax benefit was $22.5 million (December 31, 2013 - $22.1 million), approximately $12.8 million 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.

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



	Three Months Ended March 31,
	2014			2013
(Thousands of U.S. Dollars)
Unrecognized tax benefit at beginning of period	$	22,100		$	21,800
Decreases for positions relating to prior year	(1,100		)	—
Additions to tax position related to the current year	1,500			—
Unrecognized tax benefit at end of period	$	22,500		$	21,800

The Company and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and certain other foreign jurisdictions. The Company is potentially subject to income tax examinations for the tax years 2006 through 2013 in certain jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefit disclosed above within the next twelve months.

At March 31, 2014, and December 31, 2013, accounts payable included the remaining unpaid balance of equity tax liability,

a Colombian tax of 6% on a legislated measure calculated based on the Company’s Colombian segment’s balance sheet equity for tax purposes at January 1, 2011. 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 also partially related to an equity tax liability assumed upon an acquisition in 2011.

8. Contingencies

Gran Tierra Energy Colombia, Ltd. and Petrolifera Petroleum (Colombia) Ltd (collectively “GTEC”) and Ecopetrol, the contracting parties of the Guayuyaco Association Contract, are engaged in a dispute regarding the interpretation of the procedure for allocation of oil produced and sold during the long-term test of the Guayuyaco-1 and Guayuyaco-2 wells, prior to GTEC's purchase of the companies originally involved in the dispute. There has been no agreement between the parties, and Ecopetrol filed a lawsuit in the Contravention Administrative Tribunal in the District of Cauca (the "Tribunal") regarding this matter. During the first quarter of 2013, the Tribunal ruled in favor of Ecopetrol and awarded Ecopetrol 44,025 bbl of oil. GTEC has filed an appeal of the ruling to the Supreme Administrative Court (Consejo de Estado) in a second instance procedure. During the three months ended March 31, 2013, based on market oil prices in Colombia, Gran Tierra accrued $4.4 million in the condensed consolidated financial statements in relation to this dispute (Note 9).

Gran Tierra’s production from the Costayaco Exploitation Area is subject to an additional royalty (the "HPR royalty"), which applies when cumulative gross production from an Exploitation Area is greater than five MMbbl. The HPR royalty is calculated on the difference between a trigger price defined in the Chaza Block exploration and production contract (the "Chaza Contract") and the sales price. The Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) has interpreted the Chaza Contract as requiring that the HPR royalty must be paid with respect to all production from the Moqueta Exploitation Area and initiated a noncompliance procedure under the Chaza Contract, which was contested by Gran Tierra because the Moqueta Exploitation Area and the Costayaco Exploitation Area are separate Exploitation Areas. ANH did not proceed with that noncompliance procedure. Gran Tierra also believes that the evidence shows that the Costayaco and Moqueta fields are two clearly separate and independent hydrocarbon accumulations. Therefore, it is Gran Tierra’s view that, pursuant to the terms of the Chaza Contract, the HPR royalty is only to be paid with respect to production from the Moqueta Exploitation Area when the accumulated oil production from that Exploitation Area exceeds five MMbbl. Discussions with the ANH have not resolved this issue and Gran Tierra has initiated the dispute resolution process under the Chaza Contract and filed an arbitration claim seeking a decision that the HPR royalty is not payable until production from the Moqueta Exploitation Area exceeds five MMbbl. The ANH filed a response to the claim seeking a declaration that its interpretation is correct and a counterclaim seeking, amongst other remedies, declarations that Gran Tierra breached the Chaza Contract by not paying the disputed HPR royalty, that the amount of the alleged HPR royalty that is payable, and that the Chaza Contract be terminated. Gran Tierra filed a response to the ANH's counterclaim and filed its comments on the ANH's responses to Gran Tierra's claim. The ANH filed an amended counterclaim and Gran Tierra filed a response to the ANH's amended counterclaim. As at March 31, 2014, total cumulative production from the Moqueta Exploitation Area was 2.7 MMbbl. The estimated compensation which would be payable on cumulative production to that date if the ANH is successful in the arbitration is $44.9 million. At this time no amount has been accrued in the condensed consolidated financial statements nor deducted from the Company's reserves for the disputed HPR royalty as Gran Tierra does not consider it probable that a loss will be incurred.

Additionally, the ANH and Gran Tierra are engaged in discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Discussions with the ANH are ongoing. Based on the Company's understanding of the ANH's position, the estimated compensation which would be payable if the ANH’s interpretation is correct could be up to $31.7 million as at March 31, 2014. 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.

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

Letters of credit

At March 31, 2014, the Company had provided promissory notes totaling $52.5 million (December 31, 2013 - $52.5 million) as security for letters of credit relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.

9. Financial Instruments, Fair Value Measurements and Credit Risk

At March 31, 2014, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, foreign currency derivatives included in current assets and contingent consideration and contingent liability included in other long-term 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 value of foreign currency derivatives is based on the maturity value of foreign exchange non-deliverable forward contracts using applicable forward exchange rates. The most significant variable to the cash flow calculations is the estimation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are the net value of the contract.

Contingent consideration, which relates to the acquisition of the remaining 30% working interest in certain properties in Brazil, was recorded on the balance sheet at the acquisition date fair value based on the consideration expected to be transferred and discounted back to present value by applying an appropriate discount rate that reflected the risk factors associated with the payment streams. The discount rate used was determined at the time of measurement in accordance with accepted valuation methods.

The fair value of the contingent liability which relates to a dispute with Ecopetrol (Note 8) was estimated based on the fair value of the amount awarded using market oil prices in Colombia.

The fair value of the foreign currency derivatives, contingent consideration and contingent liability are being remeasured at the estimated fair value at each reporting period with the change in fair value recognized as financial instruments gains or losses in net income. The fair value of the foreign currency derivatives, contingent consideration and the contingent liability at March 31, 2014, and December 31, 2013, were as follows:



	As at
(Thousands of U.S. Dollars)	March 31, 2014		December 31, 2013
Foreign currency derivative asset	$	2,409	$	—
Contingent consideration	$	1,061	$	1,061
Contingent liability (Note 8)	$	4,400	$	4,400

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



(Thousands of U.S. Dollars)	Three Months Ended March 31,
	2014		2013
Foreign currency derivative gains	$	2,409	$	—

These gains are presented as financial instrument gain in the condensed consolidated statements of operations and cash flows.

The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities. At March 31, 2014, and December 31, 2013, the fair value of the contingent liability which relates to a dispute with Ecopetrol (Note 8) was determined using Level 1 inputs and the fair value of the contingent consideration payable in connection with the Brazil acquisition was determined using Level 3 inputs. At March 31, 2014, the fair value of the foreign currency derivatives was determined using Level 2 inputs. The disclosure in the paragraph above regarding the fair value of cash and restricted cash is based on Level 1 inputs.

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

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

At March 31, 2014, cash and cash equivalents and restricted cash included balances in savings and checking accounts, as well as term deposits and certificates of deposit, placed primarily with financial institutions with strong investment grade ratings or governments, or the equivalent in the Company’s operating areas. In February 2014, the Company purchased non-deliverable forward contracts for purposes of fixing the exchange rate at which it will purchase Colombian pesos to settle its income tax installment payments due in April and June 2014.With the exception of these foreign currency derivatives, any foreign currency transactions are conducted on a spot basis with major financial institutions in the Company’s operating areas.

At March 31, 2014, the Company had the following open foreign currency derivative position:



Forward contracts
Currency	Contract Type	Notional (Billions of Colombian Pesos)	Weighted Average Fixed Rate Received (Colombian Pesos - U.S. Dollars)	Expiration
Colombian pesos	Buy	109.3	2,037	April 2014
Colombian pesos	Buy	40.5	2,045	June 2014
		149.8

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, 2014, the Company had two customers which were significant to the Colombian segment, three customers which were significant to the Argentina segment and one customer which was significant to the Brazilian segment.

To reduce the concentration of exposure to any individual counterparty, the Company utilizes a group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its foreign currency derivative instruments.

For the three months ended March 31, 2014, 85% (three months ended March 31, 2013 - 88%) of the Company's revenue and other income was generated in Colombia.

The Argentina government has imposed a number of monetary and currency exchange control measures that include restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad, with certain exceptions for transfers related to foreign trade and other authorized transactions approved by the Argentina Central Bank. The Argentina Central Bank may require prior authorization and may or may not grant such authorization for Gran Tierra's Argentina subsidiaries to make dividends or loan payments to the Company. At March 31, 2014, $15.1 million, or 4%, of the Company's cash and cash equivalents was deposited with banks in Argentina in Argentina pesos. The Company expects to use

these funds for the Argentina work program and operations in 2014 and is exposed to foreign exchange gains and losses on its net monetary position.

Additionally, unrealized foreign exchange gains and losses result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, which are monetary liabilities mainly denominated in the local currency of the Colombian operations. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $87,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

In Colombia, the company receives 100% of its revenues in U.S. dollars and the majority of its capital expenditures are in U.S. dollars or are based on U.S. dollar prices. In Argentina and Brazil, prices for oil are in U.S. dollars, but revenues are received in local currency translated according to current exchange rates. The majority of the Company's capital expenditures within Argentina and Brazil are based on U.S. dollar prices, but are paid in local currency translated according to current exchange rates. In Peru, capital expenditures are based on U.S. dollar prices and may be paid in local currency or U.S. dollars.

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

This report, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Please see the cautionary language at the very beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements, as well as Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q.

The following discussion of our financial condition and results of operations should be read in conjunction with the "Financial Statements" as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q as well as the "Financial Statements and Supplementary Data" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in Part II, Items 8 and 7, respectively, of our Annual Report on Form 10-K, filed with the U.S. Securities and Exchange Commission (“SEC”) on February 26, 2014.

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 with business units in Colombia, Argentina, Peru and Brazil, and we are headquartered in Calgary, Alberta, Canada. For the three months ended March 31, 2014, 85% (three months ended March 31, 2013 - 88%) of our revenue and other income was generated in Colombia.

Highlights



	Three Months Ended March 31,
	2014		2013		% Change
Production (BOEPD) (1)	21,819		23,424		(7	)

Prices Realized - per BOE	$	85.82	$	97.14	(12	)

Revenue and Other Income ($000s)	$	169,679	$	205,371	(17	)

Net Income ($000s)	$	45,129	$	57,913	(22	)

Net Income Per Share - Basic	$	0.16	$	0.21	(24	)

Net Income Per Share - Diluted	$	0.16	$	0.20	(20	)

Funds Flow From Operations ($000s) (2)	$	91,030	$	108,598	(16	)

Capital Expenditures ($000s)	$	88,637	$	79,009	12



	As at
	March 31, 2014		December 31, 2013		% Change
Cash & Cash Equivalents ($000s)	$	390,953	$	428,800	(9	)

Working Capital (including cash & cash equivalents) ($000s)	$	257,310	$	245,827	5

Property, Plant & Equipment ($000s)	$	1,295,706	$	1,260,172	3

(1) Production represents production volumes NAR adjusted for inventory changes.

(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 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 income adjusted for depletion, depreciation, accretion and impairment (“DD&A”) expenses, deferred tax recovery, non-cash stock-based compensation, unrealized foreign exchange gain or loss, unrealized financial instrument gain or loss, and other loss. A reconciliation from net income to funds flow from operations is as follows:



	Three Months Ended March 31,
Funds Flow From Operations - Non-GAAP Measure ($000s)	2014			2013
Net income	$	45,129		$	57,913
Adjustments to reconcile net income to funds flow from operations
DD&A expenses	53,157			58,412
Deferred tax recovery	(2,260		)	(7,450		)
Stock-based compensation	1,591			2,067
Unrealized foreign exchange gain	(4,178		)	(6,744		)
Unrealized financial instrument gain	(2,409		)	—
Other loss	—			4,400
Funds flow from operations	$	91,030		$	108,598

•

For the three months ended March 31, 2014, oil and gas production NAR before inventory adjustments increased to 22,188 BOEPD compared with 21,869 BOEPD in the corresponding period in 2013. In 2014 in Colombia, production from new wells in the Moqueta field in the Chaza Block and the reduced impact of pipeline disruptions had a positive effect on production NAR before inventory adjustments in Colombia. In Argentina, increased gas production was more than offset by lower oil and NGL production in Argentina in the three months ended March 31, 2014, compared with 2013, due to expected production declines.

•

Oil and gas production, NAR and adjusted for inventory changes, decreased by 1,605 BOEPD or 7% to 21,819 BOEPD compared with the corresponding period in 2013. In this document unless otherwise stated production represents production volumes NAR adjusted for inventory changes. Production NAR adjusted for inventory changes in the first quarter of 2013 included 0.1 MMbbl or 1,556 bopd resulting from a net reduction in oil inventory during the quarter and production for the first quarter of 2014 was reduced by 0.03 MMbbl or 369 bopd due to an increase in oil inventory in the quarter. In the three months ended March 31, 2014, production was 71% from the Chaza Block in Colombia, 7% and 4% from the Puesto Morales and Surubi Blocks in Argentina and 3% from Block 155 in Brazil.

•

For the three months ended March 31, 2014, revenue and other income decreased by 17% to $169.7 million compared with $205.4 million in the corresponding period in 2013 due to lower production NAR after inventory adjustments and lower realized prices. The average price realized per BOE decreased by 12% to $85.82 for the three months ended March 31, 2014, from $97.14 in the comparable period in 2013.

•

Net income was $45.1 million, or $0.16 per share basic and diluted for the three months ended March 31, 2014, compared with $57.9 million, or $0.21 per share basic and $0.20 per share diluted in the corresponding period in 2013. For the three months ended March 31, 2014, lower operating, DD&A and income tax expenses, a financial instrument gain and the absence of other loss were more than offset by decreased oil and natural gas sales, increased general and administrative ("G&A") expenses and the absence of foreign exchange gains.


•	For the three months ended March 31, 2014, funds flow from operations decreased by 16% to $91.0 million. Lower operating and income tax expenses were more than offset by decreased oil and natural gas sales, increased G&A expenses and higher realized foreign exchange losses.

•

Cash and cash equivalents were $391.0 million at March 31, 2014, compared with $428.8 million at December 31, 2013. The decrease in cash and cash equivalents during the three months ended March 31, 2014, was primarily the result of cash capital expenditures of $75.1 million and a $54.9 million change in assets and liabilities from operating activities, partially offset by funds flow from operations of $91.0 million.


•	Working capital (including cash and cash equivalents) was $257.3 million at March 31, 2014, a $11.5 million increase from December 31, 2013.


•	Property, plant and equipment at March 31, 2014, was $1.3 billion, an increase of $35.5 million from December 31, 2013, as a result of $88.6 million of capital expenditures, partially offset by $53.1 million of depletion and depreciation expenses.


•	Capital expenditures for the three months ended March 31, 2014, were $88.6 million compared with $79.0 million for the three months ended March 31, 2013. In 2014, capital expenditures included drilling of $61.7 million, geological

and geophysical (“G&G”) expenditures of $15.0 million, facilities of $6.3 million and other expenditures of $5.6 million.

Business Environment Outlook

Our revenues are significantly affected by pipeline and other oil transportation disruptions in Colombia and 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 supply and demand.

We believe that our current operations and 2014 capital expenditure program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including additional pipeline delivery restrictions and other oil transportation disruptions in Colombia or a downturn in oil and gas prices, we would examine measures such as capital expenditure program reductions, use of our revolving credit facility, issuance of debt, disposition of assets, or issuance of equity. Continuing global social and political uncertainty, economic uncertainty in the United States, Europe and Asia and changes in global supply and infrastructure are 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. The timing and execution of our capital expenditure program are also affected by the availability of services from third party oil field contractors and our ability to obtain, sustain or renew necessary government licenses and permits on a timely basis to conduct exploration and development activities. Any delay may affect our ability to execute our capital expenditure program.

We have noted recently that in the Department of Putumayo in Colombia where we operate, additional efforts are being made by new ethnic groups to utilize the courts to require that they be consulted, and obtain benefits, despite a company's prior compliance with the legislated consultation process and the receipt of the necessary permits to drill and operate. See "Risk Factors: Our Business is Subject to Local Legal, Political and Economic Factors Which Are Beyond Our Control, Which Could Impair Our Ability to Expand Our Operations or Operate Profitably." For example, we recently received notice of an application to the court by a new ethnic group in the vicinity of our Moqueta field. We were given notice of the application by the court as a party that might be affected by a court’s order. The application is filed against the Ministry of the Interior of Colombia and seeks to compel the Ministry of Interior to conduct a visit to the area to determine whether the group is impacted by projects in the area and to require consultation in respect to some of our projects. We are closely monitoring this development in general, and this specific action, to try and avoid any adverse ramifications to our business.

Our future growth and acquisitions may depend on our ability to raise additional funds through equity and debt markets. Should we be required to raise debt or equity financing to fund capital expenditures or other acquisition and development opportunities, such funding may be affected by the market value of shares of our Common Stock. Also, raising funds by issuing shares or other equity securities would further dilute our existing shareholders, and this dilution would be exacerbated by a decline in our share price. Any securities we issue may have rights, preferences and privileges that are senior to our existing equity securities. Borrowing money may also involve further pledging of some or all of our assets, may require compliance with debt covenants and will expose us to interest rate risk. Depending on the currency used to borrow money, we may also be exposed to further foreign exchange risk. Our ability to borrow money and the interest rate we pay for any money we borrow will be affected by market conditions, and we cannot predict what price we may pay for any borrowed money.

Consolidated Results of Operations



	Three Months Ended March 31,
	2014			2013			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	168,525		$	204,780		(18	)
Interest income	1,154			591			95
	169,679			205,371			(17	)

Operating expenses	28,293			41,015			(31	)
DD&A expenses	53,157			58,412			(9	)
G&A expenses	15,204			11,421			33
Foreign exchange loss (gain)	126			(5,229		)	102
Financial instruments gain	(2,409		)	—			—
Other loss	—			4,400			(100	)
	94,371			110,019			(14	)

Income before income taxes	75,308			95,352			(21	)
Income tax expense	(30,179		)	(37,439		)	(19	)
Net income	$	45,129		$	57,913		(22	)

Production

Oil and NGL's, bbl	1,882,170			2,052,737			(8	)
Natural gas, Mcf	489,036			332,613			47
Total production, BOE (1)	1,963,677			2,108,173			(7	)

Average Prices

Oil and NGL's per bbl	$	88.45		$	99.17		(11	)
Natural gas per Mcf	$	4.20		$	3.61		16

Consolidated Results of Operations per BOE

Oil and natural gas sales	$	85.82		$	97.14		(12	)
Interest income	0.59			0.28			111
	86.41			97.42			(11	)

Operating expenses	14.41			19.46			(26	)
DD&A expenses	27.07			27.71			(2	)
G&A expenses	7.74			5.42			43
Foreign exchange loss (gain)	0.06			(2.48		)	102
Financial instruments gain	(1.23		)	—			—
Other loss	—			2.09			(100	)
	48.05			52.20			(8	)

Income before income taxes	38.36			45.22			(15	)
Income tax expense	(15.37		)	(17.76		)	(13	)
Net income	$	22.99		$	27.46		(16	)

(1) Production represents production volumes NAR adjusted for inventory changes.

Net income for the three months ended March 31, 2014, was $45.1 million compared with $57.9 million in the comparable period in 2013. On a per share basis, net income decreased to $0.16 per share basic and diluted for the three months ended March 31, 2014, from $0.21 per share basic and $0.20 per share diluted in the corresponding period in 2013.

For the three months ended March 31, 2014, lower operating, DD&A and income tax expenses, a financial instrument gain and the absence of other losses were more than offset by decreased oil and natural gas sales, increased G&A expenses and the absence of foreign exchange gains.

Oil and NGL production NAR before inventory adjustments for the three months ended March 31, 2014, was 21,282 bopd consistent with 21,252 bopd in the corresponding period in 2013. In 2014 in Colombia, production from new wells in the Moqueta field in the Chaza Block and the reduced impact of pipeline disruptions had a positive effect of 301 bopd production NAR before inventory adjustments. These increases were partially offset by a production decrease of 248 bopd in oil and NGL production in Argentina in the three months ended March 31, 2014, compared with 2013, due to expected production declines.

Oil and NGL production NAR after inventory changes for the three months ended March 31, 2014, decreased to 1.9 MMbbl compared with 2.1 MMbbl in the corresponding period in 2013. During the corresponding period in 2013 a net inventory reduction accounted for 0.1 MMbbl or 1,556 bopd of production. The oil inventory reduction in 2013 was due to a decrease in oil inventory in the Ecopetrol S.A. ("Ecopetrol")-operated Trans-Andean oil pipeline (the "OTA pipeline”) and associated Ecopetrol owned facilities in the Putumayo Basin and reduced oil inventory related to sales to a customer in Colombia with a protracted sales cycle whereby the transfer of ownership occurred upon export. In the three months ended March 31, 2014 and 2013, the impact of OTA pipeline disruptions on production was mitigated by selling a portion of our oil through trucking and an alternative pipeline.

Average realized oil prices decreased by 11% to $88.45 per bbl for the three months ended March 31, 2014, from $99.17 per bbl in the comparable period in 2013. Average Brent oil prices for the three months ended March 31, 2014, were $108.17 per bbl compared with $112.51 per bbl in the corresponding period in 2013. Average WTI oil prices for the three months ended March 31, 2014, were $98.68 per bbl compared with $94.40 per bbl in the corresponding period in 2013. During the three months ended March 31, 2014, 48% of our oil and gas volumes sold in Colombia were to a customer which takes delivery at the Costayaco battery and transports the oil by truck over a 1,500 km route to the Port of Barranquilla. The sales price for this customer is based on average WTI prices plus a Vasconia differential and premium, less trucking costs. For sales to this customer, the trucking costs are recorded as a reduction of the realized price and not as operating costs. Sales to this customer during the corresponding period in 2013 were 28% of our oil and gas volumes sold in Colombia

Revenue and other income for the three months ended March 31, 2014, decreased to $169.7 million from $205.4 million in the comparable period in 2013 as a result of lower production NAR after inventory adjustments and lower realized prices.

Operating expenses decreased by 31% to $28.3 million for the three months ended March 31, 2014, from 41.0 million in the comparable period in 2013. For the three months ended March 31, 2014, the decrease in operating expenses was primarily due to a decrease in the operating cost per BOE and lower production. On a per BOE basis, operating expenses decreased by 26% to $14.41 for the three months ended March 31, 2014 from $19.46 in the comparable period in 2013 primarily as a result of a decrease in transportation costs. The inventory volumes liquidated in the comparative three months ended March 31, 2013, carried high transportation costs due to the delivery point to which they were sold and to which we did not deliver in the current period. Furthermore, there were no transportation costs related to the portion of volumes subject to alternative transportation arrangements, whereby trucking costs related to a 1,500 km route are paid by the purchaser and netted to arrive at our realized price rather than recorded as transportation expenses. Operating expenses per BOE also decreased in 2014 as a result of deferred workover expenses, lower fuel consumption and lower training costs.

DD&A expenses for the three months ended March 31, 2014, decreased to $53.2 million from $58.4 million in the comparable period in 2013, primarily due to lower production. On a per BOE basis, the depletion rate of $27.07 was comparable with the depletion rate of $27.71 in the corresponding period. Increased costs in the depletable base were offset by increased reserves.

G&A expenses for the three months ended March 31, 2014, increased by 33% to $15.2 million from $11.4 million in the corresponding period in 2013. Increased employee related costs, higher consulting expenses associated with increased activity, expanded operations in Peru and higher stock-based compensation expense associated with restricted stock units ("RSUs") and stock options granted during the three months ended March 31, 2014. The annual grant to employees was not made until May 2013 in the prior year so no expense was recorded relating to the annual grant in the comparative period. These increases were partially offset by higher G&A allocations to operating expenses and capital projects within the business units. G&A expenses per BOE of $7.74 were 43% higher compared with $5.42 in 2013 due to lower production and increased costs as described above, partially offset by higher G&A allocations to operating expenses and capital projects within the business units.

For the three months ended March 31, 2014, the foreign exchange loss was $0.1 million, comprising an unrealized non-cash foreign exchange gain of $4.2 million and realized foreign exchange losses of $4.3 million. The unrealized foreign exchange gain was a result of a net monetary liability position in Colombia combined with the weakening of the Colombian peso. This

was partially offset by foreign exchange losses resulting from a net monetary asset position in Argentina and the weakening of the Argentina peso. For the three months ended March 31, 2013, there was a foreign exchange gain of $5.2 million, comprising a $6.7 million unrealized non-cash foreign exchange gain and realized foreign exchange losses of $1.5 million due to the same factors as in 2014.

Financial instruments gain of $2.4 million in the three months ended March 31, 2014, related to unrealized gains on our Colombia peso non-deliverable forward contracts. We purchased these contracts in February 2014 for purposes of fixing the exchange rate at which we will purchase Colombian pesos to settle our income tax installment payments due in April and June 2014.

Other loss of $4.4 million in the three months ended March 31, 2013, related to a contingent loss accrued in connection with a legal dispute in which we received an adverse legal judgment in the first quarter of 2013. We have filed an appeal against the judgment.

Income tax expense was $30.2 million for the three months ended March 31, 2014, compared with $37.4 million in the comparable period in 2013. The decrease was primarily due to lower taxable income in Colombia. The effective tax rate was 40% in the three months ended March 31, 2014, compared with 39% in the comparable period in 2013. The change in the effective tax rate from the comparable period in 2013 was primarily due to an increase in non-deductible foreign currency translation adjustments, partially offset by a decrease in the valuation allowance, other permanent differences,

foreign tax rate differential and the non-deductible third party royalty in Colombia.

For the three months ended March 31, 2014, the differential between the effective tax rate of 40% and the 35% U.S. statutory rate was primarily attributable to an increase in a non-deductible third party royalty in Colombia and non-deductible foreign currency translation adjustments which were partially offset by a decrease in valuation allowance and the impact of foreign taxes. The variance from the 35% U.S. statutory rate for the three months ended March 31, 2013, was primarily attributable to an increase from a non-deductible third party royalty in Colombia and valuation allowance, which was partially offset by a decrease in non-deductible foreign currency translation adjustments.

2014 Work Program and Capital Expenditure Program

Our 2014 capital program has been revised to $495 million from $467 million. This includes: $246 million for Colombia; $161 million for Peru; $48 million for Argentina; $38 million for Brazil; and $2 million associated with corporate activities. The increase in our capital spending is primarily due to the following: an increase in costs for the long-term test facilities on Block 95 in Peru as a result of a change in the scope of this project, and acceleration of the base camp construction on Block 107; additional Zapotero-1 and Corunta-1 exploratory well costs and 2013 budgeted costs carried forward to 2014 in Colombia; and additional workover costs and 2013 budgeted costs carried forward to 2014 in Brazil. The capital spending program allocates $267 million for drilling; $93 million for facilities, pipelines and other; $133 million for G&G expenditures; and $2 million for corporate activities. Of the $267 million allocated to drilling, approximately 28% is for exploration and the balance is for appraisal and development drilling.

Our 2014 work program is intended to create both growth and value by developing existing assets to increase reserves and

production levels, the construction of pipelines and facilities in the areas with proved reserves, and maturing our exploration prospects through seismic acquisition and drilling. We expect to finance our 2014 capital program through cash flows from operations and cash on hand, while retaining financial flexibility to undertake further development opportunities and pursue acquisitions. However, as a result of the nature of the oil and natural gas exploration, development and exploitation industry, budgets are regularly reviewed with respect to both the success of expenditures and other opportunities that become available. Accordingly, while we currently intend that funds be expended as set forth in our 2014 work program, there may be circumstances where, for sound business reasons, actual expenditures may in fact differ.

Segmented Results – Colombia



	Three Months Ended March 31,
	2014			2013			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	144,935		$	180,003		(19	)
Interest income	137			161			(15	)
	145,072			180,164			(19	)

Operating expenses	20,205			29,952			(33	)
DD&A expenses	41,250			45,956			(10	)
G&A expenses	4,383			4,636			(5	)
Foreign exchange gain	(4,368		)	(6,448		)	32
Financial instruments gain	(2,409		)	—			—
Other loss	—			4,400			(100	)
	59,061			78,496			(25	)

Income before income taxes	$	86,011		$	101,668		(15	)

Production

Oil and NGL's, bbl	1,610,655			1,746,326			(8	)
Natural gas, Mcf	64,779			—			—
Total production, BOE (1)	1,621,452			1,746,326			(7	)

Average Prices

Oil and NGL's per bbl	$	89.73		$	103.08		(13	)
Natural gas per Mcf	$	6.34		$	—		—

Segmented Results of Operations per BOE

Oil and natural gas sales	$	89.39		$	103.08		(13	)
Interest income	0.08			0.09			(11	)
	89.47			103.17			(13	)

Operating expenses	12.46			17.15			(27	)
DD&A expenses	25.44			26.32			(3	)
G&A expenses	2.70			2.65			2
Foreign exchange gain	(2.69		)	(3.69		)	27
Financial instruments gain	(1.49		)	—			—
Other loss	—			2.52			(100	)
	36.42			44.95			(19	)

Income before income taxes	$	53.05		$	58.22		(9	)


(1)	Production represents production volumes NAR adjusted for inventory changes.

For the three months ended March 31, 2014, income before income taxes was $86.0 million compared with $101.7 million in the comparable period in 2013. For the three months ended March 31, 2014, lower oil and natural gas sales and lower foreign

exchange gains were partially offset by decreased operating, DD&A and G&A expenses, a financial instrument gain and the absence of other losses.

Oil and NGL production NAR before inventory adjustments for the three months ended March 31, 2014, increased to 18,152 BOEPD compared with 17,851 BOEPD in the corresponding period in 2013. In 2014, production from new wells in the Moqueta field in the Chaza Block and the reduced impact of pipeline disruptions had a positive effect on production NAR before inventory adjustments.

Oil and NGL production NAR after inventory adjustments for the three months ended March 31, 2014, decreased to 1.6 MMbbl compared with 1.7 MMbbl in the comparable period in 2013. During the corresponding period in 2013 a net inventory reduction accounted for 0.1 MMbbl or 1,556 bopd of production. The oil inventory reduction in 2013 was due to a decrease in oil inventory in the OTA pipeline and associated Ecopetrol owned facilities in the Putumayo Basin and reduced oil inventory related to sales to a customer in Colombia with a protracted sales cycle whereby the transfer of ownership occurred upon export. Production during the three months ended March 31, 2014, reflected approximately 51 days of oil delivery restrictions in Colombia compared with 44 days of oil delivery restrictions in the comparable period in 2013.

Revenue and other income for the three months ended March 31, 2014, decreased by 19% to $145.1 million from $180.2 million in the comparable period in 2013.

For the three months ended March 31, 2014, the average realized price per bbl of oil decreased by 13% to $89.73 compared with $103.08 in the corresponding period in 2013. Average Brent oil price for the three months ended March 31, 2014, was $108.17 per bbl, compared with $112.51 per bbl in the corresponding period in 2013.

During the three months ended March 31, 2014, 48% of our oil and gas volumes sold were to a customer to which oil is delivered at the Costayaco battery and the sales price is based on average WTI prices plus a Vasconia differential and premium, adjusted for trucking costs related to a 1,500 km route. The effect on the Colombian realized price for the three months ended March 31, 2014, was a reduction of approximately $8.33 per BOE as compared with delivering all of our Colombian oil through the OTA pipeline. Sales to this customer during the corresponding period in 2013 were 28% of our oil and gas volumes sold in Colombia and the effect on the Colombian realized price was a reduction of approximately $5.39 per BOE.

Operating expenses decreased by 33% to $20.2 million for the three months ended March 31, 2014 from $30.0 million in

the comparable period in 2013. On a per BOE basis, operating expenses decreased by 27% to $12.46 for the three months ended March 31, 2014 from $17.15 in the comparable period in 2013. Operating expenses per BOE decreased primarily due to higher transportation costs associated with the liquidated inventory volumes in the comparative period. The inventory volumes liquidated in the comparative three months ended March 31, 2013 were primarily related to a delivery point which carried high transportation costs, and to which we did not deliver in the current period. Transportation costs were also lower due to the absence of pipeline charges and trucking costs relating to volumes sold at the Costayaco battery. The trucking costs associated with the volumes sold at the Costayaco battery were a reduction to our realized price rather than recorded as transportation expenses. The estimated net effect of OTA pipeline disruptions on Colombian transportation costs was $1.81 per BOE saving for the three months ended March 31, 2014, as compared with delivering all of our Colombian oil through the OTA pipeline and a saving of $1.24 per BOE in the corresponding period in 2013. Operating expenses per BOE also decreased in 2014 as a result of deferred workover expenses, lower fuel consumption and lower training costs.

DD&A expenses decreased by 10% to $41.3 million for the three months ended March 31, 2014 from $46.0 million in the comparable period in 2013. The decrease was due to lower production and a decrease in the per BOE depletion rate. On a per BOE basis, DD&A expenses decreased by 3% to $25.44 for the three months ended March 31, 2014, compared with the corresponding period in 2013. The decrease was primarily due to an increase in reserves, partially offset by increased costs in the depletable base.

G&A expenses of $4.4 million ($2.70 per BOE) were comparable with $4.6 million ($2.65 per BOE) in the comparable period in 2013.

For the three months ended March 31, 2014, the foreign exchange gain was $4.4 million, which included a $4.2 million unrealized non-cash foreign exchange gain. In the three months ended March 31, 2013, we had a foreign exchange gain of $6.4 million, which included a $6.7 million unrealized non-cash foreign exchange gain and a realized non-cash foreign exchange loss of $0.3 million. The Colombian peso weakened by 2% and 3% against the U.S. dollar in the three months ended March 31, 2014 and 2013, respectively. 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 is the main source of the unrealized foreign exchange losses or gains.

Financial instruments gain of $2.4 million in the three months ended March 31, 2014, related to an unrealized gain on our Colombian peso non-deliverable forward contracts. We purchased these contracts in February 2014 for purposes of fixing the exchange rate at which we will purchase Colombian pesos to settle our income tax installment payments due in April and June 2014.

Other loss of $4.4 million in the three months ended March 31, 2013, related to a contingent loss accrued in connection with a legal dispute in which we received an adverse legal judgment within the quarter. We have filed an appeal against the judgment.

Capital Program - Colombia

Capital expenditures in our Colombian segment during the three months ended March 31, 2014, were $50.5 million. The following table provides a breakdown of capital expenditures in 2014 and 2013:



	Three Months Ended March 31,
(Millions of U.S. Dollars)	2014		2013
Drilling and completions	$	30.6	$	14.9
G&G	11.1		5.3
Facilities and equipment	6.2		6.2
Other	2.6		4.0
	$	50.5	$	30.4

The significant elements of our first quarter 2014 capital program in Colombia were:

•

On the Chaza Block (100% working interest ("WI"), operated), we drilled and started completion work on the Costayaco-20 development well in the Costayaco field and commenced drilling the Costayaco-22 development well. The Costayaco-20 development well was completed as an oil producing well subsequent to the quarter-end. The Costayaco-20 development well was completed and the Costayaco-22 development well was spud subsequent to the quarter-end. We continued drilling the Zapotero-1 exploration well, a long-reach deviated well. but encountered drilling problems resulting in the initiation of sidetrack operations. We drilled the Corunta-1 exploration well, but encountered drilling problems prior to reaching the reservoir target on this long-reach deviated well, and the decision was made to abandon the well. The well location is expected to be drilled again in 2014 with a revised drilling plan.


•	We continued initial testing and evaluation of one gross exploration well, Miraflor Oeste, on the Guayuyaco Block (70% WI, operated).


•	We completed 2-D seismic acquisition on the Piedemonte Sur Block (100% WI, operated), continued 2-D seismic acquisition on the Cauca-7 Block (100% WI, operated) and 3-D seismic acquisition on the Putumayo-1 Block (55% WI, operated) and commenced an aerogravity and magnetic survey on the Sinu-1 (60% WI, operated) and Sinu-3 Blocks (51% WI, operated).


•	We also continued facilities work at the Costayaco and Moqueta fields on the Chaza Block and the Llanos-22 Block (45% WI, non-operated).

Outlook - Colombia

The 2014 capital program in Colombia is $246 million with $126 million allocated to drilling, $47 million to facilities and pipelines and $73 million for G&G expenditures.

Our planned work program for the remainder of 2014 in Colombia includes drilling three oil exploration wells on the Chaza Block, one gross exploration well on the Putumayo-1 Block, and completion of the Zapotero-1 exploration well. We also plan to drill five development wells on the Chaza Block (both Costayaco and Moqueta fields).

We also plan to complete the acquisition of 2-D seismic on the Cauca-6 and 7 Blocks and 3-D seismic on the Putumayo-1 Block and commence the acquisition of 2-D seismic on the Chaza, Guayuyaco, Sinu-1 and Sinu-3 Blocks. Facilities work is also planned for the Chaza, Garibay (50% WI, non-operated) and Llanos-22 Blocks.

Segmented Results – Argentina



	Three Months Ended March 31,
	2014			2013			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	17,420		$	18,540		(6	)
Interest income	404			243			66
	17,824			18,783			(5	)

Operating expenses	6,428			8,971			(28	)
DD&A expenses	8,893			7,950			12
G&A expenses	2,327			2,374			(2	)
Foreign exchange loss	4,328			1,124			285
	21,976			20,419			8

Loss before income taxes	$	(4,152	)	$	(1,636	)	154

Production

Oil and NGL's, bbl	205,193			242,577			(15	)
Natural gas, Mcf	424,257