Edgar Filing: GRAN TIERRA ENERGY INC.

GTE - 2013.09.30 - 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 September 30, 2013



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 November 6, 2013, the following number of shares of the registrant’s capital stock were outstanding: 272,193,233 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 6,424,391 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

Nine Months Ended September 30, 2013

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	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures	43

PART II	Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	44
Item 6.	Exhibits	59
SIGNATURES		59
EXHIBIT INDEX		60

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
BOE	barrels of oil equivalent	MMBtu	million British thermal units
MMBOE	million barrels of oil equivalent	NGL	natural gas liquids
BOEPD	barrels of oil equivalent per day	NAR	net after royalty
BOPD	barrels of oil per day

Production represents production volumes NAR adjusted for inventory changes. Our reserves and 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. A farm-in or farm-out transaction refers to a contractual agreement with an owner who holds a working interest in an oil and gas lease to assign all or part of that interest to another party in exchange for fulfilling contractually specified conditions. Payment in a farm-in or farm-out transaction can be in cash and/or in kind by committing to perform and/or pay for certain work obligations. A farm-out agreement often stipulates that the other party must drill a well to a certain depth, at a specified location, within a certain time

frame. 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.

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

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUE AND OTHER INCOME
Oil and natural gas sales	$	188,974		$	168,616		$	561,935		$	438,406
Interest income	684			317			1,904			1,628
	189,658			168,933			563,839			440,034
EXPENSES
Operating	35,588			36,295			108,505			88,115
Depletion, depreciation, accretion and impairment (Note 4)	58,875			45,044			180,309			137,982
General and administrative	14,673			12,896			37,840			46,394
Foreign exchange loss (gain)	1,880			(1,315		)	(15,329		)	27,867
Other loss (Note 8)	—			—			4,400			—
	111,016			92,920			315,725			300,358

INCOME BEFORE INCOME TAXES	78,642			76,013			248,114			139,676
Income tax expense (Note 7)	(45,585		)	(31,408		)	(109,361		)	(82,280		)
NET INCOME AND COMPREHENSIVE INCOME	33,057			44,605			138,753			57,396
RETAINED EARNINGS, BEGINNING OF PERIOD	390,369			197,805			284,673			185,014
RETAINED EARNINGS, END OF PERIOD	$	423,426		$	242,410		$	423,426		$	242,410

NET INCOME PER SHARE — BASIC	$	0.12		$	0.16		$	0.49		$	0.20
NET INCOME PER SHARE — DILUTED	$	0.12		$	0.16		$	0.49		$	0.20
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)	283,092,224			281,695,212			282,687,871			280,387,484
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)	286,026,519			284,605,162			285,820,007			283,968,384

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Balance Sheets (Unaudited)

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



	September 30,		December 31,
	2013		2012
ASSETS
Current Assets
Cash and cash equivalents	$	353,064	$	212,624
Restricted cash	3,819		1,404
Accounts receivable	143,915		119,844
Inventory (Note 4)	16,404		33,468
Taxes receivable	6,069		39,922
Prepaids	5,365		4,074
Deferred tax assets (Note 7)	2,090		2,517
Total Current Assets	530,726		413,853

Oil and Gas Properties (using the full cost method of accounting)
Proved	790,193		813,247
Unproved	435,082		383,414
Total Oil and Gas Properties	1,225,275		1,196,661
Other capital assets	9,101		8,765
Total Property, Plant and Equipment (Note 4)	1,234,376		1,205,426

Other Long-Term Assets
Restricted cash	3,305		1,619
Deferred tax assets (Note 7)	2,076		1,401
Taxes receivable	14,608		1,374
Other long-term assets	6,746		6,621
Goodwill	102,581		102,581
Total Other Long-Term Assets	129,316		113,596
Total Assets	$	1,894,418	$	1,732,875
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	70,783	$	102,263
Accrued liabilities	79,934		66,418
Taxes payable	88,757		22,339
Deferred tax liabilities (Note 7)	1,643		337
Asset retirement obligation (Note 6)	—		28
Total Current Liabilities	241,117		191,385

Long-Term Liabilities
Deferred tax liabilities (Note 7)	183,925		225,195
Equity tax payable (Note 7)	—		3,562
Asset retirement obligation (Note 6)	20,388		18,264
Other long-term liabilities	9,015		3,038
Total Long-Term Liabilities	213,328		250,059

Contingencies (Note 8)
Shareholders’ Equity
Common Stock (Note 5) (271,872,896 and 268,482,445 shares of Common Stock and 11,278,855 and 13,421,488 exchangeable shares, par value $0.001 per share, issued and outstanding as at September 30, 2013 and December 31, 2012, respectively)	10,020		7,986
Additional paid in capital	1,006,527		998,772
Retained earnings	423,426		284,673
Total Shareholders’ Equity	1,439,973		1,291,431
Total Liabilities and Shareholders’ Equity	$	1,894,418	$	1,732,875

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(Thousands of U.S. Dollars)



	Nine Months Ended September 30,
	2013			2012
Operating Activities
Net income	$	138,753		$	57,396
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, accretion and impairment	180,309			137,982
Deferred tax recovery (Note 7)	(23,791		)	(8,855		)
Stock-based compensation (Note 5)	6,113			9,854
Unrealized foreign exchange (gain) loss	(16,853		)	14,072
Cash settlement of asset retirement obligation	(927		)	(404		)
Equity tax	(3,345		)	(3,534		)
Other loss (Note 8)	4,400			—
Net change in assets and liabilities from operating activities
Accounts receivable and other long-term assets	(26,284		)	(96,656		)
Inventory	12,366			(9,769		)
Prepaids	(1,291		)	1,087
Accounts payable and accrued and other liabilities	(7,593		)	(25,960		)
Taxes receivable and payable	87,230			(59,281		)
Net cash provided by operating activities	349,087			15,932

Investing Activities
Increase in restricted cash	(4,101		)	(21,704		)
Additions to property, plant and equipment	(267,642		)	(222,119		)
Proceeds from oil and gas properties (Note 4)	59,621			—
Net cash used in investing activities	(212,122		)	(243,823		)

Financing Activities
Proceeds from issuance of shares of Common Stock (Note 5)	3,475			3,797
Net cash provided by financing activities	3,475			3,797

Net increase (decrease) in cash and cash equivalents	140,440			(224,094		)
Cash and cash equivalents, beginning of period	212,624			351,685
Cash and cash equivalents, end of period	$	353,064		$	127,591

Cash	$	296,520		$	99,442
Term deposits	56,544			28,149
Cash and cash equivalents, end of period	$	353,064		$	127,591

Supplemental cash flow disclosures:
Cash paid for income taxes	$	38,978		$	140,069

Non-cash investing activities:
Non-cash net assets and liabilities related to property, plant and equipment, end of period	$	65,645		$	33,961

(See notes to the condensed consolidated financial statements)

Gran Tierra Energy Inc.

Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)

(Thousands of U.S. Dollars)



	Nine Months Ended September 30,		Year Ended December 31,
	2013		2012
Share Capital
Balance, beginning of period	$	7,986	$	7,510
Issue of shares of Common Stock (Note 5)	2,034		476
Balance, end of period	10,020		7,986

Additional Paid in Capital
Balance, beginning of period	998,772		980,014
Issue of shares of Common Stock (Note 5)	—		2,902
Exercise of warrants	—		1,590
Expiry of warrants	—		190
Exercise of stock options (Note 5)	1,441		960
Stock-based compensation (Note 5)	6,314		13,116
Balance, end of period	1,006,527		998,772

Warrants
Balance, beginning of period	—		1,780
Exercise of warrants	—		(1,590		)
Expiry of warrants	—		(190		)
Balance, end of period	—		—

Retained Earnings
Balance, beginning of period	284,673		185,014
Net income	138,753		99,659
Balance, end of period	423,426		284,673

Total Shareholders’ Equity	$	1,439,973	$	1,291,431

(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, 2012, included in the Company’s 2012 Annual Report on Form 10-K, filed with the Securities and Exchange Commission (“SEC”) on February 26, 2013.

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2012 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.

Restricted Stock Units

In May 2013, the Company's Board of Directors determined that the Company will annually grant time-vested restricted stock units ("RSUs") to officers, employees and consultants. RSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company's Common Stock upon vesting of such shares or a cash payment equal to the value of the underlying shares. The Company expects its practice will be to settle RSUs in cash and, therefore, RSUs are accounted for as liability instruments. Compensation expense for RSUs granted is based on the estimated fair value, which is determined using the closing share price, at each reporting date, and the expense, net of estimated forfeitures, is recognized over the requisite service period using the accelerated method, with a corresponding change to liabilities. An adjustment is made to compensation expense for any difference between the estimated forfeitures and the actual forfeitures related to vested awards. Additionally, the Company will continue to grant options to purchase shares of Common Stock to certain directors, officers, employees and consultants. Stock-based compensation expense relating to RSUs and stock options is capitalized as part of oil and natural gas properties or expensed as part of operating expenses or general and administrative (“G&A”) expenses, as appropriate.

Recently Issued 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 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The implementation of this update is not expected to materially impact the Company’s consolidated financial position, results of operations or cash flows.

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 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The implementation of this update is not expected to materially impact the Company’s consolidated financial position, results of operations or cash flows.

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 Peru and Brazil was not significant at September 30, 2013, or December 31, 2012; however, the Company has separately disclosed its results of operations in Peru and Brazil as reportable segments. The All Other category represents the Company’s corporate activities.

The accounting policies of the reportable segments are the same as those described in Note 2. 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 September 30, 2013
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	164,241	$	18,149		$	—		$	6,584		$	—		$	188,974
Interest income	111		164			—			281			128			684
Depletion, depreciation, accretion and impairment	46,821		7,606			73			4,129			246			58,875
Depletion, depreciation, accretion and impairment - per unit of production	27.48		30.51			—			59.72			—			29.12
Income (loss) before income taxes	89,214		(4,164		)	(1,404		)	(337		)	(4,667		)	78,642
Segment capital expenditures (1)	$	39,608	$	8,159		$	11,063		$	(22,500	)	$	289		$	36,619
	Three Months Ended September 30, 2012
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	145,610	$	22,332		$	—		$	674		$	—		$	168,616
Interest income	171		10			—			40			96			317
Depletion, depreciation, accretion and impairment	35,255		9,165			68			305			251			45,044
Depletion, depreciation, accretion and impairment - per unit of production	24.46		26.60			—			40.35			—			25.12
Income (loss) before income taxes	79,915		1,777			(847		)	(1,170		)	(3,662		)	76,013
Segment capital expenditures	$	35,880	$	11,568		$	11,204		$	2,838		$	300		$	61,790
	Nine Months Ended September 30, 2013
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	488,577	$	54,620		$	—		$	18,738		$	—		$	561,935
Interest income	415		710			27			292			460			1,904
Depletion, depreciation, accretion and impairment	141,141		22,986			272			15,143			767			180,309
Depletion, depreciation, accretion and impairment - per unit of production	27.58		27.79			—			75.74			—			29.35
Income (loss) before income taxes	275,353		(6,183		)	(4,984		)	(3,663		)	(12,409		)	248,114
Segment capital expenditures (1)	$	118,758	$	12,424		$	59,911		$	12,021		$	528		$	203,642
	Nine Months Ended September 30, 2012
(Thousands of U.S. Dollars, except per unit of production amounts)	Colombia		Argentina			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	376,261	$	59,183		$	—		$	2,962		$	—		$	438,406
Interest income	598		96			15			607			312			1,628
Depletion, depreciation, accretion and impairment	90,625		23,080			1,174			22,379			724			137,982
Depletion, depreciation, accretion and impairment - per unit of production	24.96		24.54			—			708.76			—			29.98
Income (loss) before income taxes	182,516		2,568			(4,147		)	(24,467		)	(16,794		)	139,676
Segment capital expenditures	$	98,476	$	28,412		$	43,866		$	44,536		$	695		$	215,985

(1) In the third quarter of 2013, segment capital expenditures in Brazil are net of proceeds of $54.0 million relating to termination of a farm-in agreement. Additionally, segment capital expenditures for the nine months ended September 30, 2013, are net of proceeds of $4.1 million relating to the Company's assumption of the remaining 50% working interest in the Santa Victoria Block in Argentina and $1.5 million relating to the Company's sale of its 15% working interest in the Mecaya Block in Colombia (Note 4).



	As at September 30, 2013
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		All Other		Total
Property, plant and equipment	$	822,522	$	128,799	$	155,579	$	124,418	$	3,058	$	1,234,376
Goodwill	102,581		—		—		—		—		102,581
Other assets	267,186		37,320		18,285		50,555		184,115		557,461
Total Assets	$	1,192,289	$	166,119	$	173,864	$	174,973	$	187,173	$	1,894,418

	As at December 31, 2012
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		All Other		Total
Property, plant and equipment	$	840,027	$	138,768	$	95,940	$	127,394	$	3,297	$	1,205,426
Goodwill	102,581		—		—		—		—		102,581
Other assets	222,220		47,038		10,880		8,498		136,232		424,868
Total Assets	$	1,164,828	$	185,806	$	106,820	$	135,892	$	139,529	$	1,732,875

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 nine months ended September 30, 2013, the Company had two significant customers in Colombia: Ecopetrol S.A. ("Ecopetrol") and one other customer, which accounted for 52% and 29%, respectively, of the Company's consolidated oil and natural gas sales. For the three months ended September 30, 2013, these customers accounted for 56% and 28%, respectively, of the Company's consolidated oil and natural gas sales. In the nine months ended September 30, 2012, the Company had one significant customer in Colombia: Ecopetrol. For the three and nine months ended September 30, 2012, sales to Ecopetrol accounted for 71% and 77%, respectively, of the Company's consolidated oil and natural gas sales. For the three months ended September 30, 2012, the Company had an additional short-term significant customer , which accounted for 13% of the Company's revenues during the period.

4. Property, Plant and Equipment and Inventory

Property, Plant and Equipment



	As at September 30, 2013							As at December 31, 2012
(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	$	1,710,788	$	(920,595	)	$	790,193	$	1,562,477	$	(749,230	)	$	813,247
Unproved	435,082		—			435,082		383,414		—			383,414
	2,145,870		(920,595		)	1,225,275		1,945,891		(749,230		)	1,196,661
Furniture and fixtures and leasehold improvements	8,215		(6,203		)	2,012		7,575		(5,093		)	2,482
Computer equipment	14,018		(7,458		)	6,560		10,971		(5,248		)	5,723
Automobiles	1,352		(823		)	529		1,376		(816		)	560
Total Property, Plant and Equipment	$	2,169,455	$	(935,079	)	$	1,234,376	$	1,965,813	$	(760,387	)	$	1,205,426

Depletion and depreciation expense on property, plant and equipment for the three months ended September 30, 2013, was $59.1 million (three months ended September 30, 2012 - $43.0 million) and for the nine months ended September 30, 2013, was $172.7 million (nine months ended September 30, 2012 - $120.8 million). A portion of depletion and depreciation expense was recorded as inventory in each period and adjusted for inventory changes.

In the second quarter of 2013, the Company recorded a ceiling test impairment loss of $2.0 million in the Company's Brazil cost center as a result of lower realized prices and increased operating costs.

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

In the second quarter of 2013, the Company assumed its partner's 50% working interest in the Santa Victoria Block in Argentina and received cash consideration of $4.1 million from its partner, comprising the balance owing for carry consideration and compensation for the second exploration phase work commitment. The Company also received proceeds of $1.5 million relating to a sale of its 15% working interest in the Mecaya Block in Colombia.

During the third quarter of 2013, the Company received a net payment of $54.0 million (before income taxes) from a third party in connection with termination of a farm-in agreement in the Recôncavo Basin relating to Block REC-T-129, Block REC-T-142, Block REC-T-155 and Block REC-T-224.

The Company successfully bid on three blocks in the 2013 Brazil Bid Round administered by Brazil's Agência Nacional de Petróleo, Gás Natural e Biocombustíveis ("ANP") and, in the third quarter of 2013, paid a signature bonus of $14.4 million upon finalization of the concession agreement.

In Brazil, the exploration phase of the concession agreements on Blocks REC-T-129, REC-T-142 and REC-T-155 is due to expire on November 24, 2013; however, under the concession agreements the Company is able and has submitted an application to the ANP for extension of the exploration phase of these blocks. Additionally, the exploration phase of the concession agreement on Block REC-T-224 is due to expire on December 11, 2013, but we plan to apply for an extension of the exploration phase of this block. At September 30, 2013, unproved properties included $59.6 million relating to these four blocks. Management assessed these blocks for impairment at September 30, 2013 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.

The amounts of G&A expenses and stock-based compensation capitalized in each of the Company's cost centers were as follows:



	Nine Months Ended September 30, 2013
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock-based compensation	$	14,746	$	2,896	$	5,981	$	5,813	$	29,436
Capitalized stock-based compensation	$	794	$	171	$	571	$	566	$	2,102

	Nine Months Ended September 30, 2012
(Thousands of U.S. Dollars)	Colombia		Argentina		Peru		Brazil		Total
Capitalized G&A, including stock-based compensation	$	9,279	$	3,480	$	3,670	$	2,653	$	19,082
Capitalized stock-based compensation	$	376	$	275	$	—	$	216	$	867

Unproved oil and natural gas properties consist of exploration lands held in Colombia, Argentina, Peru and Brazil. As at September 30, 2013, the Company had $163.0 million (December 31, 2012 - $175.9 million) of unproved assets in Colombia, $39.5 million (December 31, 2012 - $42.3 million) of unproved assets in Argentina, $154.6 million (December 31, 2012 - $95.1 million) of unproved assets in Peru, and $78.0 million (December 31, 2012 - $70.1 million) of unproved assets in Brazil for a total of $435.1 million (December 31, 2012 - $383.4 million). These properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed. The Company expects that approximately 62% of costs not subject to depletion at September 30, 2013, will be transferred to the depletable base within the next five years and the remainder in the next five to 10 years.

Inventory

At September 30, 2013, oil and supplies inventories were $14.6 million and $1.8 million, respectively (December 31, 2012 - $31.2 million and $2.3 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 September 30, 2013, outstanding share capital consists of 271,872,896 shares of Common Stock of the Company, 6,744,728 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 of the Exchangeco exchangeable shares was previously established as November 14, 2013 (or at an earlier date under certain specified circumstances). However, pursuant to resolutions of the board of directors of Gran Tierra Exchangeco Inc., effective October 25, 2013, the redemption date for the Exchangeco exchangeable shares was extended to such later date as may be established by the board of directors of Gran Tierra Exchangeco Inc. at its discretion. The redemption date of the Goldstrike exchangeable shares was previously established as November 10, 2013. However, pursuant to resolutions of the board of directors of Gran Tierra Goldstrike Inc., effective October 31, 2013, the redemption date for the Goldstrike exchangeable shares was extended to such later date as may be established by the board of directors of Gran Tierra Goldstrike Inc. at its discretion. During the nine months ended September 30, 2013, 1,247,818 shares of Common Stock were issued upon the exercise of stock options, 452,950 shares of Common Stock were issued upon the exchange of the Exchangeco exchangeable shares and 1,689,683 shares of Common Stock were issued upon the exchange of the Goldstrike exchangeable shares.

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

The Exchangeco exchangeable shares were issued upon acquisition of Solana Resources Limited. The Goldstrike exchangeable shares were issued upon the business combination between Gran Tierra Energy Inc., an Alberta corporation, and Goldstrike, Inc., which is now the Company. 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

In May 2013, the Company issued RSUs and stock options, which will vest as to 1/3 of the awards on each of March 1, 2014, March 1, 2015 and March 1, 2016. The term of options granted starting May 2013 is five years or three months after the grantee’s end of service to the Company, whichever occurs first. Options granted prior to May 2013 continue to have a term of ten years or three months after the grantee’s end of service to the Company, whichever occurs first. Once an RSU is vested, it is immediately settled and considered to be at the end of its term.

The following table provides information about long-term incentive plan ("LTIP") activity for the nine months ended September 30, 2013:



	RSUs		Options
	Number of Outstanding Share Units		Number of Outstanding Options		Weighted Average Exercise Price $/Option
Balance, December 31, 2012	—		15,399,662		5.11
Granted	939,365		2,066,935		6.27
Exercised	—		(1,247,818	)	(2.79	)
Forfeited	(21,655	)	(284,835	)	(6.17	)
Expired	—		(102,593	)	(6.57	)
Balance, September 30, 2013	917,710		15,831,351		5.42

For the nine months ended September 30, 2013, 1,247,818 shares of Common Stock were issued for cash proceeds of $3.5 million upon the exercise of 1,247,818 stock options (nine months ended September 30, 2012 - $3.8 million).

The weighted average grant date fair value for options granted in the three months ended September 30, 2013, was $2.34 (three months ended September 30, 2012 - $2.62) and for the nine months ended September 30, 2013, was $2.62 (nine months ended September 30, 2012 - $3.36). As a result of the change in the term of stock options to five years for stock options granted starting May 2013, the weighted average volatility used in the Black-Scholes option pricing model was reduced to 43% for the three months ended September 30, 2013 and 53% for the nine months ended September 30, 2013, from 75% for the year ended December 31, 2012, resulting in a lower grant date fair value per share than in prior periods.

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



(Thousands of U.S. Dollars)	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Compensation costs for stock options	$	2,132		$	3,268		$	6,314		$	10,721
Compensation costs for RSUs	1,282			—			1,901			—
	3,414			3,268			8,215			10,721
Less: stock-based compensation costs capitalized	(1,717		)	(336		)	(2,102		)	(867		)
Total stock-based compensation expense	$	1,697		$	2,932		$	6,113		$	9,854

Of the total compensation expense for the three months ended September 30, 2013, $1.3 million (three months ended September 30, 2012 - $2.6 million) was recorded in G&A expenses and $0.4 million (three months ended September 30, 2012 – $0.3 million) was recorded in operating expenses. Of the total compensation expense for the nine months ended September 30, 2013, $5.3 million (nine months ended September 30, 2012 – $8.9 million) was recorded in G&A expenses and $0.8 million (nine months ended September 30, 2012 – $0.9 million) was recorded in operating expenses.

At September 30, 2013, there was $11.3 million (December 31, 2012 - $8.2 million) of unrecognized compensation cost related to unvested LTIP units which is expected to be recognized over a weighted average period of 2.1 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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Weighted average number of common and exchangeable shares outstanding	283,092,224		281,695,212		282,687,871		280,387,484
Shares issuable pursuant to warrants	—		—		—		235,582
Shares issuable pursuant to stock options	12,428,489		5,643,730		10,823,968		5,947,880
Shares assumed to be purchased from proceeds of stock options	(9,494,194	)	(2,733,780	)	(7,691,832	)	(2,602,562	)
Weighted average number of diluted common and exchangeable shares outstanding	286,026,519		284,605,162		285,820,007		283,968,384

For the three months ended September 30, 2013, 3,472,472 options (three months ended September 30, 2012 - 9,957,585 options) were excluded from the diluted income per share calculation as the options were anti-dilutive. For the nine months ended September 30, 2013, 5,584,732 options (nine months ended September 30, 2012 - 9,808,758 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:



	Nine Months Ended			Year Ended
(Thousands of U.S. Dollars)	September 30, 2013			December 31, 2012
Balance, beginning of year	$	18,292		$	12,669
Settlements	(2,068		)	(404		)
Liability incurred	1,397			5,190
Liability assumed in a business combination	—			410
Foreign exchange	(23		)	45
Accretion	918			998
Revisions in estimated liability	1,872			(616		)
Balance, end of period	$	20,388		$	18,292

Asset retirement obligation - current	$	—		$	28
Asset retirement obligation - long-term	20,388			18,264
Balance, end of period	$	20,388		$	18,292

For the nine months ended September 30, 2013, settlements included cash payments of $0.9 million with the balance in accounts payable and accrued liabilities at September 30, 2013. Revisions to estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling the asset retirement obligation. At September 30, 2013, the fair value of assets that are legally restricted for purposes of settling the asset retirement obligation was $1.9 million (December 31, 2012 - $1.3 million).

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:



	Nine Months Ended September 30,
(Thousands of U.S. Dollars)	2013			2012
Income (loss) before income taxes
United States	$	(8,488	)	$	(7,942	)
Foreign	256,602			147,618
	248,114			139,676
	35		%	35		%
Income tax expense expected	86,840			48,887
Foreign currency translation adjustments	(7,649		)	8,025
Impact of foreign taxes	1,908			2,716
Stock-based compensation	1,943			3,277
Increase in valuation allowance	22,700			9,304
Branch and other foreign loss pick-up	(2,013		)	(4,358		)
Non-deductible third party royalty in Colombia	8,812			9,951
Other permanent differences	(3,180		)	4,478
Total income tax expense	$	109,361		$	82,280

Current income tax expense
United States	$	813		$	778
Foreign	132,339			90,357
	133,152			91,135
Deferred income tax recovery
United States	—			—
Foreign	(23,791		)	(8,855		)
	(23,791		)	(8,855		)
Total income tax expense	$	109,361		$	82,280



	As at
(Thousands of U.S. Dollars)	September 30, 2013			December 31, 2012
Deferred Tax Assets
Tax benefit of operating loss carryforwards	$	53,693		$	51,920
Tax basis in excess of book basis	44,500			22,519
Foreign tax credits and other accruals	30,550			30,926
Tax benefit of capital loss carryforwards	4,835			4,779
Deferred tax assets before valuation allowance	133,578			110,144
Valuation allowance	(129,412		)	(106,226		)
	$	4,166		$	3,918

Deferred tax assets - current	$	2,090		$	2,517
Deferred tax assets - long-term	2,076			1,401
	4,166			3,918
Deferred tax liabilities - current	(1,643		)	(337		)
Deferred tax liabilities - long-term	(183,925		)	(225,195		)
	(185,568		)	(225,532		)
Net Deferred Tax Liabilities	$	(181,402	)	$	(221,614	)

As at September 30, 2013, the Company had operating loss carryforwards of $233.7 million (December 31, 2012 - $213.1 million) and capital loss carryforwards of $32.6 million (December 31, 2012 – $35.9 million) before valuation allowance. Of these operating loss carryforwards and capital loss carryforwards, $233.8 million (December 31, 2012 - $215.2 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 2014 and 2017, while certain other jurisdictions allow operating losses to be carried forward indefinitely.

As at September 30, 2013, the total amount of Gran Tierra’s unrecognized tax benefit was approximately $19.8 million (December 31, 2012 - $21.8 million), a portion of which, if recognized, would affect the Company’s effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the consolidated statement of operations.

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



	Nine Months Ended September 30,
	2013			2012
(Thousands of U.S. Dollars)
Unrecognized tax benefit at beginning of period	$	21,800		$	20,500
Changes for positions relating to prior year	(2,000		)	—
Unrecognized tax benefit at end of period	$	19,800		$	20,500

The Company and its subsidiaries file income tax returns in the U.S. and certain other foreign jurisdictions. The Company is potentially subject to income tax examinations for the tax years 2005 through 2012 in certain jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefit disclosed above within the next twelve months.

The equity tax liability at September 30, 2013, and December 31, 2012, includes a Colombian tax of 6% on a legislated measure and was 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 the 2011 acquisition of Petrolifera Petroleum Limited.

8. Contingencies

Gran Tierra Energy Colombia, Ltd. and Petrolifera Petroleum Exploration (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 nine months ended September 30, 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.

Gran Tierra’s production from the Costayaco field is subject to an additional royalty that applies when cumulative gross production from a commercial field is greater than 5 MMbbl. This additional royalty is calculated on the difference between a trigger price defined by the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) and the sales price. The ANH has requested that the additional compensation be paid with respect to production from wells relating to the Moqueta discovery and has initiated a non-compliance procedure under the Chaza Contract. The Moqueta discovery is not located in the Costayaco Exploitation Area. Further, Gran Tierra views the Costayaco field and the Moqueta discovery as two clearly separate and independent hydrocarbon accumulations. Therefore, it is Gran Tierra’s view that it is clear that, pursuant to the Chaza Contract, the additional compensation payments are only to be paid with respect to production from the Moqueta wells when the accumulated oil production from any new Exploitation Area created with respect to the Moqueta discovery exceeds 5 MMbbl. Discussions with the ANH have not resolved this issue and Gran Tierra has initiated the dispute resolution process and filed an arbitration claim. As at September 30, 2013, total cumulative production from the Moqueta field was 1.9 MMbbl. The estimated compensation which would be payable on cumulative production to date if the ANH’s interpretation is successful is $31.7 million. At this time, no amount has been accrued in the condensed consolidated financial statements nor deducted from the Company's reserves as Gran Tierra does not consider it probable that a loss will be incurred.

Additionally, the ANH and Gran Tierra Colombia are engaged in discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the additional royalty. Discussions with the ANH are ongoing. As at September 30, 2013, the estimated compensation which would be payable if the ANH’s interpretation is successful is $23.4 million. At this time, no amount has been accrued in the condensed consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

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

Letters of credit

At September 30, 2013, the Company had provided promissory notes totaling $49.6 million (December 31, 2012 - $34.2 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 September 30, 2013, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, 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. Contingent consideration, which relates to the acquisition of the remaining 30% working interest in certain properties in Brazil in October 2012, 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 contingent liability which relates to a dispute with Ecopetrol (Note 8) was based on the fair value of the amount awarded. The fair value of the contingent consideration and contingent liability is being remeasured at the estimated fair value at each reporting period with the change in fair value recognized as income or expense in operating income. The fair value of the contingent consideration was $1.1 million at September 30, 2013, and December 31, 2012. The fair value of the contingent liability was $4.4 million at

September 30, 2013. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments. At September 30, 2013, and December 31, 2012, the Company held no derivative 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. The fair value of the contingent consideration payable in connection with the Brazil acquisition was determined using Level 3 inputs at September 30, 2013, and December 31, 2012. The disclosure in the paragraph above regarding the fair value of other financial instruments is based on Level 1 inputs.

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

At September 30, 2013, 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. Any foreign currency transactions are conducted on a spot basis, with major financial institutions in the Company’s operating areas.

Most of the Company’s accounts receivable relate to uncollateralized sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. For the nine months ended September 30, 2013, 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.

For the nine months ended September 30, 2013, 87% (nine months ended September 30, 2012 - 86%) of the Company's revenue and other income was generated in Colombia.

Additionally, foreign exchange gains and losses mainly result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, which are monetary liabilities mainly denominated in the local currency of the Colombian foreign operations. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $95,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

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. During the three months ended June 30, 2013, the Company repatriated $11.1 million from one of its Argentina subsidiaries through loan repayments, authorized by the Argentina Central Bank. These were repayments of loan principal and as such had no withholding tax applied. At September 30, 2013, $20.3 million, or 6%, of the Company's cash and cash equivalents was deposited with banks in Argentina. We expect to use these funds for the Argentina work program and operations in 2013.

10. Credit Facilities

At September 30, 2013, a subsidiary of Gran Tierra had a credit facility with a syndicate of banks, led by Wells Fargo Bank National Association as administrative agent. This reserve-based facility has a current borrowing base of $150 million and a maximum borrowing base of up to $300 million and is supported by the present value of the petroleum reserves of two of the Company’s subsidiaries with operating branches in Colombia and the Company's subsidiary in Brazil. Amounts drawn down under the facility bear interest at the U.S. dollar LIBOR rate plus a margin ranging between 2.25% and 3.25% per annum depending on the rate of borrowing base utilization. In addition, a stand-by fee of 0.875% per annum is charged on the unutilized balance of the committed borrowing base and is included in G&A expenses. The credit facility was entered into on August 30, 2013 and became effective on October 31, 2013 for a three-year term. Subsequent to the effective date, the

Company has not drawn down any amounts under the new credit facility. Under the terms of the facility, the Company is required to maintain and was in compliance with certain financial and operating covenants. Under the terms of the credit facility, the Company cannot pay any dividends to its shareholders if it is in default under the facility and, if the Company is not in default, then it is required to obtain bank approval for any dividend payments exceeding $2 million in any fiscal year.

11. Related Party Transactions

On August 7, 2012, Gran Tierra entered into a contract related to the Brazil drilling program with a company for which one of Gran Tierra’s directors is a shareholder and was a director. During the three and nine months ended September 30, 2013, $4.2 million and $11.8 million, respectively, (three and nine months ended September 30, 2012 - $nil) was incurred and capitalized under this contract. At September 30, 2013, $2.3 million (December 31, 2012 - $1.1 million) was included in accounts payable relating to this contract.

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, 2013.

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 nine months ended September 30, 2013, 87% (nine months ended September 30, 2012 - 86%) of our revenue and other income was generated in Colombia.

Highlights



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013		2012		% Change		2013		2012		% Change
Production (BOEPD) (1)	21,978		19,491		13		22,505		16,797		34

Prices Realized - per BOE	$	93.46	$	94.03	(1	)	$	91.46	$	95.26	(4	)

Revenue and Other Income ($000s)	$	189,658	$	168,933	12		$	563,839	$	440,034	28

Net Income ($000s)	$	33,057	$	44,605	(26	)	$	138,753	$	57,396	142

Net Income Per Share - Basic	$	0.12	$	0.16	(25	)	$	0.49	$	0.20	145

Net Income Per Share - Diluted	$	0.12	$	0.16	(25	)	$	0.49	$	0.20	145

Funds Flow From Operations ($000s) (2)	$	84,546	$	89,935	(6	)	$	284,659	$	206,511	38

Net Capital Expenditures ($000s) (3)	$	36,619	$	61,790	(41	)	$	203,642	$	215,985	(6	)



	As at
	September 30, 2013		December 31, 2012		% Change
Cash & Cash Equivalents ($000s)	$	353,064	$	212,624	66

Working Capital (including cash & cash equivalents) ($000s)	$	289,609	$	222,468	30

Property, Plant & Equipment ($000s)	$	1,234,376	$	1,205,426	2

(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 the income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is also useful supplemental information for investors to analyze operating performance and our financial results. Investors should be cautioned that this measure should not be construed as an alternative to net income or other measures of financial performance as determined in accordance with GAAP. Our method of calculating this measure may differ from other companies and, accordingly, it may not be comparable to similar measures used by other companies. Funds flow from operations, as presented, is net income adjusted for depletion, depreciation, accretion and impairment (“DD&A”) expenses, deferred tax recovery, stock-based compensation, unrealized foreign exchange gain or loss, settlement of asset retirement obligation, equity tax and other loss. A reconciliation from net income to funds flow from operations is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
Funds Flow From Operations - Non-GAAP Measure ($000s)	2013			2012			2013			2012
Net income	$	33,057		$	44,605		$	138,753		$	57,396
Adjustments to reconcile net income to funds flow from operations
DD&A expenses	58,875			45,044			180,309			137,982
Deferred tax (recovery) expense	(8,042		)	1,195			(23,791		)	(8,855		)
Stock-based compensation	1,697			2,932			6,113			9,854
Unrealized foreign exchange loss (gain)	1,513			(2,092		)	(16,853		)	14,072
Cash settlement of asset retirement obligation	(927		)	—			(927		)	(404		)
Equity tax	(1,627		)	(1,749		)	(3,345		)	(3,534		)
Other loss	—			—			4,400			—
Funds flow from operations	$	84,546		$	89,935		$	284,659		$	206,511

(3) In the third quarter of 2013, segment capital expenditures in Brazil are net of proceeds of $54.0 million relating to termination of a farm-in agreement. Additionally, segment capital expenditures for the nine months ended September 30, 2013, are net of proceeds of $4.1 million relating to the Company's assumption of the remaining 50% working interest in the Santa Victoria Block in Argentina and $1.5 million relating to the Company's sale of its 15% working interest in the Mecaya Block in Colombia.

•

For the three and nine months ended September 30, 2013, oil and gas production, NAR and adjusted for inventory changes, increased by 13% to 21,978 BOEPD and by 34% to 22,505 BOEPD compared with the corresponding periods in 2012, respectively. In Colombia, alternative transportation arrangements to minimize the impact of pipeline disruptions, production from new wells and a decrease in oil inventory had a positive impact on production in 2013. In the three and nine months ended September 30, 2013, production was 75% from the Chaza Block in Colombia. In the three months ended September 30, 2013, the Puesto Morales and Surubi Blocks in Argentina contributed 7% and 4% of total production, respectively, and in the nine months ended September 30, 2013, their contribution was 8% and 5%, respectively.

•

For the three and nine months ended September 30, 2013, revenue and other income increased by 12% to $189.7 million and by 28% to $563.8 million compared with $168.9 million and $440.0 million in the corresponding periods in 2012, respectively. The positive contribution from higher production levels was partially offset by lower realized prices. The average price realized per BOE decreased by 1% to $93.46 and by 4% to $91.46 for the three and nine months ended September 30, 2013, from $94.03 and $95.26, in the comparable periods in 2012, respectively.

•

Net income was $33.1 million, or $0.12 per share basic and diluted, and $138.8 million, or $0.49 per share basic and diluted, for the three and nine months ended September 30, 2013, respectively, compared with $44.6 million and $57.4 million, or $0.16 and $0.20 per share basic and diluted, in the corresponding periods in 2012, respectively. For the three months ended September 30, 2013, increased oil and natural gas sales were more than offset by increased DD&A, general and administrative ("G&A") and income tax expenses and foreign exchange losses. For the nine

months ended September 30, 2013, increased oil and natural gas sales and foreign exchange gains and lower G&A expenses were partially offset by increased DD&A, operating and income tax expenses.

•

For the three and nine months ended September 30, 2013, funds flow from operations decreased by 6% to $84.5 million and increased by 38% to $284.7 million, respectively. For the three months ended September 30, 2013, increased oil and natural gas sales were more than offset by increased G&A and income tax expenses. For the nine months ended September 30, 2013, increased oil and natural gas sales, lower G&A expenses and decreased realized foreign exchange losses were partially offset by increased operating and income tax expenses.

•

Cash and cash equivalents were $353.1 million at September 30, 2013, compared with $212.6 million at December 31, 2012. The increase in cash and cash equivalents during the nine months ended September 30, 2013, was primarily the result of funds flow from operations of $284.7 million, a $64.4 million change in assets and liabilities from operating activities, partially offset by capital expenditures, net of proceeds from oil and gas properties, of $208.0 million.


•	Working capital (including cash and cash equivalents) was $289.6 million at September 30, 2013, a $67.1 million increase from December 31, 2012.


•	Property, plant and equipment at September 30, 2013, was $1.2 billion, an increase of $29.0 million from December 31, 2012, as a result of $203.6 million of net capital expenditures (net of proceeds from oil and gas properties of $59.6 million and excluding changes in non-cash working capital), partially offset by $174.6 million of depletion, depreciation and impairment expenses.

•

Net capital expenditures for the nine months ended September 30, 2013, were $203.6 million compared with $216.0 million for the nine months ended September 30, 2012. In 2013, capital expenditures included drilling of $161.1 million, geological and geophysical (“G&G”) expenditures of $56.9 million, facilities of $27.4 million and other expenditures of $17.8 million. Capital expenditures in 2013 were offset by proceeds from oil and gas properties of $59.6 million.

Business Environment Outlook

Our revenues have been significantly affected by pipeline 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 2013 capital expenditure program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including additional pipeline delivery restrictions in Colombia or a downturn in oil and gas prices, we would examine measures such as capital expenditure program reductions, use of our existing revolving credit facility, issuance of debt, disposition of assets, or issuance of equity. Continuing social and political uncertainty in the Middle East, North Africa and South America, 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. 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.

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. Our ability to utilize our Common Stock to raise capital may be negatively affected by declines in the price 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 September 30,								Nine Months Ended September 30,
	2013			2012			% Change		2013			2012			% Change
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	188,974		$	168,616		12		$	561,935		$	438,406		28
Interest income	684			317			116		1,904			1,628			17
	189,658			168,933			12		563,839			440,034			28

Operating expenses	35,588			36,295			(2	)	108,505			88,115			23
DD&A expenses	58,875			45,044			31		180,309			137,982			31
G&A expenses	14,673			12,896			14		37,840			46,394			(18	)
Foreign exchange loss (gain)	1,880			(1,315		)	243		(15,329		)	27,867			(155	)
Other loss	—			—			—		4,400			—			—
	111,016			92,920			19		315,725			300,358			5

Income before income taxes	78,642			76,013			3		248,114			139,676			78
Income tax expense	(45,585		)	(31,408		)	45		(109,361		)	(82,280		)	33
Net income	$	33,057		$	44,605		(26	)	$	138,753		$	57,396		142

Production

Oil and NGL's, bbl	1,969,077			1,726,224			14		5,982,710			4,410,917			36