XTSE:GTE Gran Tierra Energy Inc Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

XTSE:GTE Fair Value Estimate
Premium
XTSE:GTE Consider Buying
Premium
XTSE:GTE Consider Selling
Premium
XTSE:GTE Fair Value Uncertainty
Premium
XTSE:GTE Economic Moat
Premium
XTSE:GTE Stewardship
Premium
 


 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

ý
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012

OR

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 number)
 
 
 
300, 625 11 Avenue S.W.
Calgary, Alberta, Canada
 
T2R 0E1
(Address of principal executive offices)
 
(Zip code)
(403) 265-3221
(Registrant’s telephone number,
including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý  NO o
 
Indicate by check mark whether the registrant submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   YES   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 August 2, 2012, the following numbers of shares of the registrant’s capital stock were outstanding: 268,043,064 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 6,223,810 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 7,421,891 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

 



1



Gran Tierra Energy Inc.

Quarterly Report on Form 10-Q

Six Months Ended June 30, 2012

Table of contents
 
 
 
Page
 
 
 
PART I
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
Item 4.
Controls and Procedures
 
 
 
PART II
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
Item 1A.
Risk Factors
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
Item 6.
Exhibits
 
 
 
SIGNATURES
 
 
EXHIBIT INDEX

2



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

GLOSSARY OF OIL AND GAS TERMS
 
In this document, the abbreviations set forth below have the following meanings:
 
bbl
barrel
BOPD
barrels of oil per day
Mbbl
thousand barrels
Mcf
thousand cubic feet
MMbbl
million barrels
MMcf
million cubic feet
BOE
barrels of oil equivalent
Bcf
billion cubic feet
MMBOE
million barrels of oil equivalent
NGL
natural gas liquids
BOEPD
barrels of oil equivalent per day
NAR
net after royalty
 
In the discussion that follows we discuss our interests in wells and/or acres in gross and net terms. Gross oil and natural gas wells or acres refer to the total number of wells or acres in which we own a working interest. Net oil and natural gas wells or acres are determined by multiplying gross wells or acres by the working interest that we own in such wells or acres. Working interest refers to the interest we own in a property, which entitles us to receive a specified percentage of the proceeds of the sale of oil and natural gas, and also requires us to bear a specified percentage of the cost to explore for, develop and produce that oil and natural gas. A working interest owner that owns a portion of the working interest may participate either as operator, or by voting its percentage interest to approve or disapprove the appointment of an operator, in drilling and other major activities in connection with the development of a property.
 
We also refer to royalties and farm-in or farmout 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 farmout 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 farmout by the seller of the working interest. Payment in a farm-in or farmout 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.

3



An airplane is equipped with extremely sensitive instruments that measure changes in the earth's gravitational and magnetic field. Variations as small as 1/1,000th in the gravitational and magnetic field strength and direction can indicate structural changes below the ground surface. These structural changes may influence the trapping of hydrocarbons. These surveys are an inexpensive way of gathering data over large regions.
 
Seismic data is used by oil and natural gas companies as their principal source of information to locate oil and natural gas deposits, both for exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computer software applications are then used to process the raw data to develop an image of underground formations. 2-D seismic is the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data. 3-D seismic data is collected using a grid of energy sources, which are generally spread over several square miles. A 3-D seismic survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is generally considered a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated.
 
Wells drilled are classified as exploration, development or stratigraphic. An exploration well is a well drilled in search of a previously undiscovered hydrocarbon-bearing reservoir. A development well is a well drilled to develop a hydrocarbon-bearing reservoir that is already discovered. Exploration and development wells are tested during and after the drilling process to determine if they have oil or natural gas that can be produced economically in commercial quantities. If they do, the well will be completed for production, which could involve a variety of equipment, the specifics of which depend on a number of technical geological and engineering considerations. If there is no oil or natural gas (a “dry” well), or there is oil and natural gas but the quantities are too small and/or too difficult to produce, the well will be abandoned. Abandonment is a completion operation that involves closing or “plugging” the well and remediating the drilling site. An injector well is a development well that will be used to inject fluid into a reservoir to increase production from other wells. A stratigraphic well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. These wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if drilled in an unknown area or “development type” if drilled in a known area.

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

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

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

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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

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


4



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 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.

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

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

5



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.

v.
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 highest known oil (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.

 

6



PART 1

Item 1 - Financial Statements
 
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Operations and Retained Earnings (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
REVENUE AND OTHER INCOME
 
 
 
 
 
 
 
Oil and natural gas sales
$
114,542

 
$
161,664

 
$
269,790

 
$
283,960

Interest income
608

 
456

 
1,311

 
679

 
115,150

 
162,120

 
271,101

 
284,639

EXPENSES
 

 
 

 
 
 
 
Operating
27,333

 
23,160

 
51,820

 
39,556

Depletion, depreciation, accretion and impairment (Note 5)
32,571

 
46,965

 
92,938

 
110,322

General and administrative
17,599

 
16,410

 
33,498

 
30,048

Equity tax (Note 8)

 
221

 

 
8,271

Financial instruments gain (Notes 3 and 6)

 
(1,292
)
 

 
(1,522
)
Gain on acquisition (Note 3)

 
2,601

 

 
(21,699
)
Foreign exchange loss
4,807

 
14,495

 
29,182

 
19,694

 
82,310

 
102,560

 
207,438

 
184,670

 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAXES
32,840

 
59,560

 
63,663

 
99,969

Income tax expense (Note 8)
(19,736
)
 
(27,993
)
 
(50,872
)
 
(54,689
)
NET INCOME AND COMPREHENSIVE INCOME
13,104

 
31,567

 
12,791

 
45,280

RETAINED EARNINGS, BEGINNING OF PERIOD
184,701

 
71,810

 
185,014

 
58,097

RETAINED EARNINGS, END OF PERIOD
$
197,805

 
$
103,377

 
$
197,805

 
$
103,377

 
 
 
 
 
 
 
 
NET INCOME PER SHARE — BASIC
$
0.05

 
$
0.11


$
0.05


$
0.17

NET INCOME PER SHARE — DILUTED
$
0.05

 
$
0.11


$
0.05


$
0.16

WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 6)
280,714,786

 
277,297,728

 
279,726,434

 
269,159,453

WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 6)
284,141,287

 
284,451,536

 
283,500,228

 
277,530,126


(See notes to the condensed consolidated financial statements)



7



Gran Tierra Energy Inc.
Condensed Consolidated Balance Sheets (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
 
June 30,
 
December 31,
 
2012
 
2011
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
128,528

 
$
351,685

Restricted cash
4,034

 
1,655

Accounts receivable
95,004

 
69,362

Inventory (Note 5)
27,055

 
7,116

Taxes receivable
19,267

 
21,485

Prepaids
3,444

 
3,597

Deferred tax assets (Note 8)
3,223

 
3,029

Total Current Assets
280,555

 
457,929

 
 
 
 
Oil and Gas Properties (using the full cost method of accounting)
 

 
 

Proved
665,346

 
618,982

Unproved
425,922

 
417,868

Total Oil and Gas Properties
1,091,268

 
1,036,850

Other capital assets
8,875

 
7,992

Total Property, Plant and Equipment (Note 5)
1,100,143

 
1,044,842

 
 
 
 
Other Long-Term Assets
 

 
 

Restricted cash
33,854

 
13,227

Deferred tax assets (Note 8)
7,974

 
4,747

Other long-term assets
9,299

 
3,454

Goodwill
102,581

 
102,581

Total Other Long-Term Assets
153,708

 
124,009

 
 
 
 
Total Assets
$
1,534,406

 
$
1,626,780

LIABILITIES AND SHAREHOLDERS’ EQUITY
 

 
 

Current Liabilities
 

 
 

Accounts payable
$
51,556

 
$
82,189

Accrued liabilities
55,101

 
66,832

Taxes payable
13,117

 
95,482

Asset retirement obligation (Note 7)
167

 
326

Total Current Liabilities
119,941

 
244,829

 
 
 
 
Long-Term Liabilities
 

 
 

Deferred tax liability (Note 8)
196,241

 
186,799

Equity tax payable (Note 8)
5,294

 
6,484

Asset retirement obligation (Note 7)
12,504

 
12,343

Other long-term liabilities
2,119

 
2,007

Total Long-Term Liabilities
216,158

 
207,633

 
 
 
 
Commitments and Contingencies (Note 9)


 


Shareholders’ Equity
 

 
 

Common shares (Note 6) (267,819,245 and 264,256,159 common shares and 13,869,520 and 13,869,520 exchangeable shares, par value $0.001 per share, issued and outstanding as at June 30, 2012 and December 31, 2011, respectively)
7,986

 
7,510

Additional paid in capital
992,516

 
980,014

Warrants (Note 6)

 
1,780

Retained earnings
197,805

 
185,014

Total Shareholders’ Equity
1,198,307

 
1,174,318

 
 
 
 
Total Liabilities and Shareholders’ Equity
$
1,534,406

 
$
1,626,780


(See notes to the condensed consolidated financial statements)

8



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)

 
Six Months Ended June 30,
 
2012
 
2011
Operating Activities
 
 
 
Net income
$
12,791

 
$
45,280

Adjustments to reconcile net income to net cash (used in) provided by operating activities:
 
 
 

Depletion, depreciation, accretion and impairment
92,938

 
110,322

Deferred taxes (Note 8)
(10,050
)
 
(5,406
)
Stock-based compensation (Note 6)
6,922

 
5,945

Unrealized gain on financial instruments (Note 3)

 
(1,354
)
Unrealized foreign exchange loss
16,164

 
16,102

Settlement of asset retirement obligation (Note 7)
(404
)
 
(309
)
Equity tax
(1,785
)
 
6,251

Gain on acquisition (Note 3)

 
(21,699
)
Net change in assets and liabilities from operating activities
 

 
 

Accounts and other receivables
(17,668
)
 
(100,955
)
Inventory
(13,485
)
 
(213
)
Prepaids
154

 
(211
)
Accounts payable and accrued and other liabilities
(28,567
)
 
(2,508
)
Taxes receivable and payable
(82,262
)
 
(18,120
)
Net cash (used in) provided by operating activities
(25,252
)
 
33,125

 
 
 
 
Investing Activities
 

 
 

Increase in restricted cash
(23,006
)
 
(8,139
)
Additions to property, plant and equipment
(178,644
)
 
(182,408
)
Proceeds from disposition of oil and gas property (Note 5)

 
3,253

Cash acquired on acquisition (Note 3)

 
7,747

Proceeds on sale of asset-backed commercial paper (Note 3)

 
22,679

Net cash used in investing activities
(201,650
)
 
(156,868
)
 
 
 
 
Financing Activities
 

 
 

Settlement of bank debt (Note 3)

 
(22,853
)
Proceeds from issuance of common shares
3,745

 
2,523

Net cash provided by (used in) financing activities
3,745

 
(20,330
)
 
 
 
 
Net decrease in cash and cash equivalents
(223,157
)
 
(144,073
)
Cash and cash equivalents, beginning of period
351,685

 
355,428

Cash and cash equivalents, end of period
$
128,528

 
$
211,355

 
 
 
 
Cash
$
78,929

 
$
135,142

Term deposits
49,599

 
76,213

Cash and cash equivalents, end of period
$
128,528

 
$
211,355

 
 
 
 
Supplemental cash flow disclosures:
 

 
 

Cash paid for interest
$

 
$
1,344

Cash paid for income taxes
$
139,482

 
$
64,205

 
 
 
 
Non-cash investing activities:
 

 
 

Non-cash working capital related to property, plant and equipment, end of period
$
18,447

 
$
39,118


(See notes to the condensed consolidated financial statements)

9



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands of U.S. Dollars)
 
 
Six Months Ended
 
Year Ended
 
June 30, 2012
 
December 31, 2011
Share Capital
 
 
 
Balance, beginning of period
$
7,510

 
$
4,797

Issue of common shares
476

 
2,713

Balance, end of period
7,986

 
7,510

 
 
 
 
Additional Paid in Capital
 

 
 

Balance, beginning of period
980,014

 
821,781

Issue of common shares
2,902

 
142,109

Exercise of warrants (Note 6)
1,590

 
411

Expiry of warrants (Note 6)
190

 

Exercise of stock options (Note 6)
367

 
1,990

Stock-based compensation (Note 6)
7,453

 
13,723

Balance, end of period
992,516

 
980,014

 
 
 
 
Warrants
 

 
 

Balance, beginning of period
1,780

 
2,191

Exercise of warrants (Note 6)
(1,590
)
 
(411
)
  Expiry of warrants (Note 6)
(190
)
 

Balance, end of period

 
1,780

 
 
 
 
Retained Earnings
 

 
 

Balance, beginning of period
185,014

 
58,097

Net income
12,791

 
126,917

Balance, end of period
197,805

 
185,014

 
 
 
 
Total Shareholders’ Equity
$
1,198,307

 
$
1,174,318


(See notes to the condensed consolidated financial statements)


10



Gran Tierra Energy Inc.
Notes to the Condensed Consolidated Financial Statements (Unaudited)
 
1. Description of Business
 
Gran Tierra Energy Inc., a Nevada corporation (the “Company” or “Gran Tierra”), is a publicly traded oil and gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties. The Company’s principal business activities are in Colombia, Argentina, Peru and Brazil.
 
2. Significant Accounting Policies
 
These interim unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of results for the interim periods.

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

The Company’s significant accounting policies are described in Note 2 of the consolidated financial statements which are included in the Company’s 2011 Annual Report on Form 10-K and are the same policies followed in these interim unaudited condensed consolidated financial statements, except as disclosed below. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued. Certain amounts for 2011 have been reclassified to conform to the 2012 presentation. The reclassifications had no effect on net income.

Revenue Recognition

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

Inventory
Inventory consists of oil in tanks and pipelines and supplies and is valued at the lower of cost or market value. The cost of inventory is determined using the weighted average method. Oil inventories include expenditures incurred to produce, upgrade and transport the product to the storage facilities and includes operating, depletion and depreciation expenses and cash royalties.

Adopted Accounting Pronouncements
 
Goodwill

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


11



Recently Issued Accounting Pronouncements

Disclosure about Offsetting Assets and Liabilities

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

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

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

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

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

The fair value of the Replacement Warrants was estimated on the Acquisition Date using the Black-Scholes option pricing model with the following assumptions:
 
Exercise price (CDN dollars per warrant)
$
9.67

Risk-free interest rate
1.3
%
Expected life
0.45
 Years
Volatility
44
%
Expected annual dividend per share
Nil

Estimated fair value per warrant (CDN dollars)
$
0.32


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


12



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

(Thousands of U.S. Dollars)
 
Consideration Transferred:
 
Common shares issued net of share issue costs
$
141,690

Replacement Warrants
1,354

 
$
143,044

 
 

Allocation of Consideration Transferred:
 

Oil and gas properties
 

Proved
$
58,457

Unproved
161,278

Other long-term assets
4,417

Net working capital (including cash acquired of $7.7 million and accounts receivable of $6.4 million)
(17,223
)
Asset retirement obligation
(4,901
)
Bank debt
(22,853
)
Other long-term liabilities
(14,432
)
Gain on acquisition
(21,699
)
 
$
143,044


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

As part of the assets acquired and included in the net working capital in the allocation of the consideration transferred, the Company assigned $22.5 million in fair value to investments in notes that Petrolifera received in exchange for asset-backed commercial paper (“ABCP”) with a face value of $31.3 million. On March 28, 2011, these notes were sold to an unrelated party for proceeds of $22.7 million after the associated line of credit was settled. When combined with the gain arising on expiry of the Replacement Warrants, the financial instruments gain for the six months ended June 30, 2011 was $1.5 million.

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

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

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

13



expired on August 5, 2011.

Interest expense on the reserve-backed credit facility for the 104-day period from the Acquisition Date to June 30, 2011 was $0.8 million. This amount is recorded on the condensed consolidated statements of operations as part of general and administrative (“G&A”) expenses.

Pro forma results for the three and six months ended June 30, 2011 are shown below, as if the acquisition had occurred on January 1, 2010. Pro forma results are not indicative of actual results or future performance.
 
Six Months Ended June 30,
(Thousands of U.S. Dollars except per share amounts)
2011
Revenue and other income
$
293,834

Net income
$
12,457

Net income per share - basic
$
0.05

Net income per share - diluted
$
0.04


The supplemental pro forma earnings of Gran Tierra for the six months ended June 30, 2011 were adjusted to exclude $4.4 million of acquisition costs recorded in G&A expenses and the $21.7 million gain on acquisition because they are not expected to have a continuing impact on Gran Tierra’s results of operations. The condensed consolidated statement of operations for the six months ended June 30, 2011 included revenue of $10.9 million from Petrolifera for the period subsequent to the Acquisition Date. Net income from Petrolifera for the period from the Acquisition Date to June 30, 2011 was not material.

4. Segment and Geographic Reporting
 
The Company is primarily engaged in the exploration and production of oil and natural gas. The Company’s reportable segments are Colombia, Argentina and Peru based on geographic organization. The level of activity in Brazil was not significant at June 30, 2012 or December 31, 2011; 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 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 segmented results include the operations of Petrolifera subsequent to March 18, 2011, the Acquisition Date (Note 3).


14



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


Three Months Ended June 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
$
92,018

 
$
21,482

 
$

 
$
1,042

 
$

 
$
114,542

Interest income
223

 
39

 

 
272

 
74

 
608

Depletion, depreciation, accretion and impairment
23,084

 
7,990

 
991

 
266

 
240

 
32,571

Depletion, depreciation, accretion and impairment - per unit of production
24.61

 
23.78

 

 
23.14

 

 
25.34

Income (loss) before income taxes
42,481

 
1,268

 
(2,573
)
 
(1,228
)
 
(7,108
)
 
32,840

Segment capital expenditures
$
42,247

 
$
2,739

 
$
16,007

 
$
5,442

 
$
169

 
$
66,604

 
Three Months Ended June 30, 2011
(Thousands of U.S. Dollars, except per unit of production amounts)
Colombia
 
Argentina
 
Peru
 
Brazil
 
All Other
 
Total
Oil and natural gas sales
$
148,473

 
$
12,857

 
$

 
$
334

 
$

 
$
161,664

Interest income
158

 
28

 
134

 

 
136

 
456

Depletion, depreciation, accretion and impairment
39,609

 
5,505

 
1,530

 
156

 
165

 
46,965

Depletion, depreciation, accretion and impairment - per unit of production
28.49

 
21.45

 

 
38.87

 

 
28.45

Income (loss) before income taxes
73,729

 
(3,099
)
 
(2,371
)
 
(1,376
)
 
(7,323
)
 
59,560

Segment capital expenditures
$
54,216

 
$
7,138

 
$
11,287

 
$
28,287

 
$
561

 
$
101,489

 
Six Months Ended June 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
$
230,651

 
$
36,851

 
$

 
$
2,288

 
$

 
$
269,790

Interest income
427

 
86

 
15

 
567

 
216

 
1,311

Depletion, depreciation, accretion and impairment
55,370

 
13,915

 
1,106

 
22,074

 
473

 
92,938

Depletion, depreciation, accretion and impairment - per unit of production
25.29

 
23.35

 

 
919.14

 

 
33.08

Income (loss) before income taxes
102,601

 
791

 
(3,300
)
 
(23,297
)
 
(13,132
)
 
63,663

Segment capital expenditures
$
62,596

 
$
16,844

 
$
32,662

 
$
41,698

 
$
395

 
$
154,195

 
Six Months Ended June 30, 2011
(Thousands of U.S. Dollars, except per unit of production amounts)
Colombia
 
Argentina
 
Peru
 
Brazil
 
All Other
 
Total
Oil and natural gas sales
$
265,777

 
$
17,849

 
$

 
$
334

 
$

 
$
283,960

Interest income
245

 
28

 
134

 
11

 
261

 
679

Depletion, depreciation, accretion and impairment
69,645

 
6,652

 
33,463

 
252

 
310

 
110,322

Depletion, depreciation, accretion and impairment - per unit of production
26.75

 
18.85

 

 
62.80

 

 
37.27

Income (loss) before income taxes
131,615

 
(3,529
)
 
(34,996
)
 
(2,744
)
 
9,623

 
99,969

Segment capital expenditures (1)
$
96,480

 
$
18,760

 
$
25,574

 
$
28,674

 
$
1,104

 
$
170,592

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

15



 
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.

The Company has one significant customer in Colombia, Ecopetrol. Sales to Ecopetrol accounted for 75% and 88% of the Company’s revenues for the three months ended June 30, 2012 and 2011, and 81% and 89% for the six months ended June 30, 2012 and 2011, respectively.

The Company has two significant customers in Argentina, Shell C.A.P.S.A. (“Shell”) and Refineria del Norte S.A. (“Refiner”). Sales to Shell and Refiner accounted for 2% and 8% of the Company’s oil and natural gas sales for the three months ended June 30, 2012, and 3% and 5% for the six months ended June 30, 2012, respectively. In the three months ended June 30, 2011, sales to Shell and Refiner accounted for 7% and 2%, and in the six months ended June 30, 2011, accounted for 4% and 3%, respectively.

(Thousands of U.S. Dollars)
As at June 30, 2012
 
Colombia
 
Argentina
 
Peru
 
Brazil
 
All Other
 
Total
Property, plant and equipment
$
817,431

 
$
132,190

 
$
65,860

 
$
81,546

 
$
3,116

 
$
1,100,143

Goodwill
102,581

 

 

 

 

 
102,581

Other assets
170,076

 
46,260

 
11,712

 
11,719

 
91,915

 
331,682

Total Assets
$
1,090,088

 
$
178,450

 
$
77,572

 
$
93,265

 
$
95,031

 
$
1,534,406

 
 
 
 
 
 
 
 
 
 
 
 
 
As at December 31, 2011
(Thousands of U.S. Dollars)
Colombia
 
Argentina
 
Peru
 
Brazil
 
All Other
 
Total
Property, plant and equipment
$
816,396

 
$
129,072

 
$
34,305

 
$
61,875

 
$
3,194

 
$
1,044,842

Goodwill
102,581

 

 

 

 

 
102,581

Other assets
269,843

 
34,672

 
9,597

 
17,065

 
148,180

 
479,357

Total Assets
$
1,188,820

 
$
163,744

 
$
43,902

 
$
78,940

 
$
151,374

 
$
1,626,780

 
5. Property, Plant and Equipment and Inventory
 
Property, Plant and Equipment

 
As at June 30, 2012
 
As at December 31, 2011
(Thousands of U.S. Dollars)
Cost
 
Accumulated
depletion,
depreciation
and
impairment
 
Net book value
 
Cost
 
Accumulated
depletion,
depreciation
and
impairment
 
Net book value
Oil and natural gas properties
 
 
 

 
 

 
 

 
 

 
 

  Proved
$
1,325,336

 
$
(659,990
)
 
$
665,346

 
$
1,181,503

 
$
(562,521
)
 
$
618,982

  Unproved
425,922

 

 
425,922

 
417,868

 

 
417,868

 
1,751,258

 
(659,990
)
 
1,091,268

 
1,599,371

 
(562,521
)
 
1,036,850

Furniture and fixtures and leasehold improvements
7,649

 
(4,551
)
 
3,098

 
6,973

 
(4,002
)
 
2,971

Computer equipment
10,076

 
(4,968
)
 
5,108

 
8,443

 
(4,174
)
 
4,269

Automobiles
1,295

 
(626
)
 
669

 
1,295

 
(543
)
 
752

Total Property, Plant and Equipment
$
1,770,278

 
$
(670,135
)
 
$
1,100,143

 
$
1,616,082

 
$
(571,240
)
 
$
1,044,842

 

16



Depletion and depreciation expense on property, plant and equipment for the six months ended June 30, 2012 was $77.8 million (six months ended June 30, 2011 - $77.2 million) and for the three months ended June 30, 2012 was $35.1 million (three months ended June 30, 2011 - $45.0 million). A portion of depletion and depreciation expense was recorded as inventory in each period.

On August 7, 2012, the Company announced that Costayaco Field reserves as of June 30, 2012, net after royalty ("NAR"), calculated in accordance with SEC rules, increased, after production, from year-end 2011 reserves as follows: total proved reserves increased to approximately 19.6 million barrels of oil. The reserve revisions were due to a successful waterflood program and reservoir management.

On June 5, 2012, the Company received regulatory approval of a farm-in agreement on a block in Colombia. This approval triggered a payment of $21.1 million related to drilling costs for a previously drilled oil exploration well, which was recorded as a capital expenditure in the second quarter of 2012.

Effective June 1, 2012, the Company entered into an agreement to acquire the remaining 40% working interest in a block in Peru. The block is an unproved property. Purchase consideration was $5.4 million and was recorded as a capital expenditure in the three months ended June 30, 2012. The agreement is subject to government approval.

On August 26, 2010, the Company entered into an agreement to acquire a 70% participating interest in four blocks in Brazil. With the exception of one block which has a producing well, the remaining blocks are unproved properties. The agreement was effective September 1, 2010, subject to regulatory approvals, and the transaction was completed on June 15, 2011. Purchase consideration was $40.1 million and was recorded as a capital expenditure in 2011 and 2010. The 70% share of all benefits and costs with respect to the period between the effective date and the completion of the transaction were an adjustment to the consideration paid for the four blocks. On January 20, 2012, the Company entered into an agreement to acquire the remaining 30% participating interest in these four blocks. The completion of the transaction is subject to regulatory approval.

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

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

On February 17, 2012, in accordance with the terms of the farmout agreement for BM-CAL-10, the Company gave notice to Statoil that it would not enter into and assume its share of the work obligations of the second exploration period of the block. As a result, the farmout agreement has terminated and the Company will not receive any interest in the block. Pursuant to the farmout agreement, the Company was obligated to make payment for a certain percentage of the costs relating to Block BM-CAL-10, which relate primarily to a well that was drilled during the term of the farmout agreement. The notice of withdrawal was a trigger for payment of amounts that would otherwise have been due if the farmout agreement had closed and the Company had acquired a participating interest. In the three months ended March 31, 2011, the Company recorded a ceiling test impairment loss in the Company’s Brazil cost center of $20.2 million. This impairment charge resulted from the recognition of $23.8 million of capital expenditures in relation to the Block BM-CAL-10 farmout agreement in the first quarter of 2012.

In the six months ended June 30, 2011, the Company recorded a ceiling test impairment loss in the Company’s Peru cost center of $33.4 million (three months ended June 30, 2011 - $1.5 million). This impairment charge related to seismic and drilling costs from a dry well.

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


17



The amounts capitalized in each of the Company's cost centers during the six months ended June 30, 2012 and 2011, respectively, were as follows:

 
Six Months Ended June 30, 2012
(Thousands of U.S. Dollars)
Colombia
 
Argentina
 
Peru
 
Brazil
 
Total
Capitalized G&A, including stock-based compensation
$
4,219

 
$
1,915

 
$
1,623

 
$
2,107

 
$
9,864

Capitalized stock-based compensation
$
190

 
$
148

 
$

 
$
193

 
$
531

 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2011
(Thousands of U.S. Dollars)
Colombia
 
Argentina
 
Peru
 
Brazil
 
Total
Capitalized G&A, including stock-based compensation
$
4,121

 
$
1,022

 
$
824

 
$
228

 
$
6,195

Capitalized stock-based compensation
$
189

 
$
114

 
$

 
$

 
$
303


Unproved oil and natural gas properties consist of exploration lands held in Colombia, Argentina, Peru and Brazil. As at June 30, 2012, the Company had $261.9 million (December 31, 2011 - $274.8 million) of unproved assets in Colombia, $49.9 million (December 31, 2011 - $57.0 million) of unproved assets in Argentina, $65.2 million (December 31, 2011 - $33.7 million) of unproved assets in Peru, and $48.9 million (December 31, 2011 - $52.4 million) of unproved assets in Brazil for a total of $425.9 million (December 31, 2011 - $417.9 million). These properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration dictates whether or not future areas will be developed.

Inventories

As at June 30, 2012, oil and supplies inventories were $24.6 million and $2.5 million, respectively (December 31, 2011 - $4.7 million and $2.4 million, respectively).
 
6. Share Capital
 
The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as common stock, par value $0.001 per share, 25 million are designated as preferred stock, par value $0.001 per share, and two shares are designated as special voting stock, par value $0.001 per share.

As at June 30, 2012, outstanding share capital consists of 267,819,245 common voting shares of the Company, 7,645,710 exchangeable shares of Gran Tierra Exchange Co., automatically exchangeable on November 14, 2013, and 6,223,810 exchangeable shares of Goldstrike Exchange Co., automatically exchangeable on November 10, 2012. The exchangeable shares of Gran Tierra Exchange Co., were issued upon acquisition of Solana Resources Limited (“Solana”). The exchangeable shares of Gran Tierra Goldstrike Inc. were issued upon the business combination between Gran Tierra Energy Inc., an Alberta corporation, and Goldstrike, Inc., which is now the Company. Each exchangeable share is exchangeable into one common voting share of the Company.

The holders of common voting shares 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 voting shares have no pre-emptive rights, no conversion rights, and there are no redemption provisions applicable to the common voting shares. Holders of exchangeable shares have substantially the same rights as holders of common voting shares.
 
Stock Options
  
For the six months ended June 30, 2012, the stock-based compensation expense was $7.4 million (six months ended June 30, 2011- $6.2 million) of which $6.3 million (six months ended June 30, 2011 - $5.4 million) was recorded in G&A expenses, $0.6 million was recorded in operating expense (six months ended June 30, 2011$0.5 million) and $0.5 million was capitalized as part of exploration and development costs (six months ended June 30, 2011$0.3 million).


18



For the three months ended June 30, 2012, the stock-based compensation expense was $4.0 million (three months ended June 30, 2011- $2.7 million) of which $3.4 million (three months ended June 30, 2011 - $2.2 million) was recorded in G&A expenses, $0.3 million was recorded in operating expense (three months ended June 30, 2011$0.3 million) and $0.3 million was capitalized as part of exploration and development costs (three months ended June 30, 2011$0.2 million).

At June 30, 2012, there was $14.3 million (December 31, 2011 - $11.7 million) of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next three years.

On June 27, 2012, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the number of shares of common stock available for issuance thereunder from 23,306,100 shares to 39,806,100 shares. The following table provides information about stock option activity for the six months ended June 30, 2012:
 
 
Number of
Outstanding
Options 
 
Weighted Average
Exercise Price
$/Option
Balance, December 31, 2011
12,864,002

 
$
4.90

Granted in 2012
3,260,650

 
5.80

Exercised in 2012
(267,673
)
 
(3.14
)
Forfeited in 2012
(197,314
)
 
(6.99
)
Balance, June 30, 2012
15,659,665

 
$
5.09

 
The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table.
 
 
Three Months Ended June 30,
 
2012
 
 

Dividend yield (per share)
nil

Volatility
75
%
Risk-free interest rate
0.4
%
Expected term
4-6 years

 
The weighted average grant date fair value for options granted in the six months ended June 30, 2012 was $5.80 (six months ended June 30, 2011 - $5.07) and for the three months ended June 30, 2012 was $5.29 (three months ended June 30, 2011 - $7.28) .

Warrants
 
At December 31, 2011, the Company had 6,298,230 warrants outstanding to purchase 3,149,115 common shares for $1.05 per share, expiring between June 20, 2012 and June 30, 2012. During the six months ended June 30, 2012, 2,775,334 common shares were issued upon the exercise of 5,550,668 warrants (six months ended June 30, 2011, 525,817 common shares were issued upon the exercise of 1,051,634 warrants), 26,190 common shares were issued with 7,143 shares withheld in lieu of a cashless exchange upon the exercise of 66,666 warrants, and 680,896 warrants expired unexercised.

The Company issued 4,125,036 Replacement Warrants in connection with its acquisition of Petrolifera during March 2011 (Note 3). The Replacement Warrants expired unexercised in August 2011.The fair value of the Replacement Warrants as of June 30, 2011, was determined using the Black-Scholes option pricing model with the following assumptions:
 

19



Exercise price (CDN dollars per warrant)
$
9.67

Risk-free interest rate
1.2
%
Expected life
0.16
 Years
Volatility
42
%
Expected annual dividend per share
Nil

Estimated fair value per warrant (CDN dollars)
$
0.003


During the three months ended June 30, 2011, a financial instruments gain resulting from the change in fair value of the Replacement Warrants of $1.3 million was recorded.

Weighted Average Shares Outstanding
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Weighted average number of common and exchangeable shares outstanding
280,714,786

 
277,297,728

 
279,726,434

 
269,159,453

Shares issuable pursuant to warrants
170,145

 
2,728,361

 
339,495

 
2,789,122

Shares issuable pursuant to stock options
5,942,583

 
5,191,288

 
6,078,405

 
6,079,268

Shares to be purchased from proceeds of stock options
(2,686,227
)
 
(765,841
)
 
(2,644,106
)
 
(497,717
)
Weighted average number of diluted common and exchangeable shares outstanding
284,141,287

 
284,451,536

 
283,500,228

 
277,530,126

 
For the three month period ended June 30, 2012, 9,726,917 options were excluded from the diluted income per share calculation as the instruments were anti-dilutive (for the three months ended June 30, 2011, 3,815,996 options and 4,125,036 Replacement Warrants were excluded from the diluted income per share calculation for the same reason).

For the six month period ended June 30, 2012, 9,731,230 options were excluded from the diluted income per share calculation as the instruments were anti-dilutive (for the six months ended June 30, 2011, 3,219,996 options and 4,125,036 Replacement Warrants were excluded from the diluted income per share calculation).
 
7. Asset Retirement Obligation
 
As at June 30, 2012, the Company’s asset retirement obligation comprised a Colombian obligation in the amount of $5.9 million (December 31, 2011 - $5.5 million), an Argentine obligation in the amount of $6.1 million (December 31, 2011 - $6.7 million), a Brazilian obligation in the amount of $0.5 million (December 31, 2011 - $0.5 million) and a Peruvian obligation in the amount of $0.2 million (December 31, 2011 - $nil). As at June 30, 2012, the undiscounted asset retirement obligation was $32.6 million (December 31, 2011 - $29.9 million). Revisions to estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling the asset retirement obligation. Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:

20



 
Six Months Ended
 
Year Ended
(Thousands of U.S. Dollars)
2012
 
2011
Balance, beginning of period
$
12,669

 
$
4,807

Settlements
(404
)
 
(345
)
Disposal

 
(172
)
Liability incurred
513

 
867

Liability assumed in a business combination (Note 3)

 
4,901

Foreign exchange
9

 
17

Accretion
500

 
673

Revisions in estimated liability
(616
)
 
1,921

Balance, end of period
$
12,671

 
$
12,669

 
 
 
 
Asset retirement obligation - current
$
167

 
$
326

Asset retirement obligation - long-term
12,504

 
12,343

Balance, end of period
$
12,671

 
$
12,669

 


21



8. Taxes
 
The income tax expense reported differs from the amount computed by applying the U.S. statutory rate to income before income taxes for the following reasons:
 
Six Months Ended June 30,
(Thousands of U.S. Dollars)
2012
 
2011
Income before income taxes
$
63,663

 
$
99,969

 
35
%
 
35
%
Income tax expense expected
22,282

 
34,989

Foreign currency translation adjustments
8,101

 
4,956

Impact of foreign taxes
(86
)
 
(3,134
)
Stock-based compensation
2,326

 
1,825

Increase in valuation allowance
5,457

 
24,065

Branch and other foreign loss pick-up in the United States and Canada
(2,159
)
 
(2,898
)
Non-deductible third party royalty in Colombia
7,140

 
4,115

Non-taxable gain on acquisition

 
(7,595
)
Other permanent differences
7,811

 
(1,634
)
Total income tax expense
$
50,872

 
$
54,689

 
 
 
 
Current income tax
60,922

 
63,439

Deferred tax recovery
(10,050
)
 
(8,750
)
Total income tax expense
$
50,872

 
$
54,689


For the six months ended June 30, 2012, other permanent differences include $8.2 million of loss adjustments which are fully offset by a change in the valuation allowance.
 
As at
(Thousands of U.S. Dollars)
June 30, 2012
 
December 31, 2011
Deferred Tax Assets
 

 
 

Tax benefit of loss carryforwards
$
71,805

 
$
63,910

Tax basis in excess of book basis
15,261

 
17,065

Foreign tax credits and other accruals
27,445

 
27,164

Capital losses
5,510

 
2,433

Deferred tax assets before valuation allowance
120,021

 
110,572

Valuation allowance
(108,824
)
 
(102,796
)
 
$
11,197

 
$
7,776

 
 
 
 
Deferred tax assets - current
$
3,223

 
$
3,029

Deferred tax assets - long-term
7,974

 
4,747

 
11,197

 
7,776

Deferred Tax Liabilities
 

 
 

  Long-term - book value in excess of tax basis
(196,241
)
 
(186,799
)
Net Deferred Tax Liabilities
$
(185,044
)
 
$
(179,023
)

As at June 30, 2012, the Company had operating loss carryforwards of $388.8 million (December 31, 2011 - $361.6 million) and capital losses of $36.6 million (December 31, 2011$13.7 million) before valuation allowance. Of these losses, $391.9 million (December 31, 2011 - $339.8 million) were losses generated by the foreign subsidiaries of the Company, including $119.2 million relating to a Barbadian subsidiary taxable at 1.75% which are expected to be extinguished by the end of 2012. In certain jurisdictions, the operating loss carryforwards expire between 2013 and 2032 and the capital losses expire between 2013 and 2017, while certain other jurisdictions allow operating losses to be carried forward indefinitely. Of the total operating loss

22



carryforwards, $3.5 million will expire in 2013.
 
As at June 30, 2012, the total amount of Gran Tierra’s unrecognized tax benefit was approximately $20.5 million (December 31, 2011 - $20.5 million), a portion of which, if recognized, would affect the Company’s effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the condensed consolidated statement of operations. As at June 30, 2012, the amount of interest and penalties on the unrecognized tax benefit included in current income tax liabilities in the condensed consolidated balance sheet was approximately $1.6 million (December 31, 2011 - $1.6 million). The Company had no material interest or penalties included in the condensed consolidated statement of operations for the three and six months ended June 30, 2012 and 2011, respectively.
 
Changes in the Company's unrecognized tax benefit are as follows:
 
Six Months Ended June 30,
 
2012
 
2011
(Thousands of U.S. Dollars)
 
 
 
Unrecognized tax benefit at January 1
$
20,500

 
$
4,175

  Changes for positions relating to prior year

 
(257
)
  Additions to tax position related to the current year

 
9,190

Unrecognized tax benefit at June 30
$
20,500

 
$
13,108


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 2011 in certain jurisdictions. The Company does not anticipate any material changes to the unrecognized tax benefit disclosed above within the next twelve months.

Equity tax for the six months ended June 30, 2011 of $8.3 million represented a Colombian tax of 6% 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 at June 30, 2012 and December 31, 2011 was also partially related to an equity tax liability assumed upon the acquisition of Petrolifera.
 
9. Commitments and Contingencies
 
Purchase Obligations, Firm Agreements and Leases
 
The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancellable lease terms in excess of one year as of June 30, 2012:

 
As at June 30, 2012
 
Payments Due in Period
 
Total
 
Less than 1
Year
 
1 to 3 years
 
3 to 5 years
 
More than 5
years
(Thousands of U.S. Dollars)
 
 
 
 
 
 
 
 
 
Oil transportation services
$
32,560

 
$
8,710

 
$
7,100

 
$
7,100

 
$
9,650

Drilling and geological and geophysical
39,480

 
38,374

 
1,106

 

 

Completions
30,828

 
24,560

 
6,268

 

 

Facility construction
31,000

 
17,049

 
13,951

 

 

Operating leases
6,882

 
2,861

 
3,003

 
1,018

 

Software and telecommunication
8,093

 
3,685

 
4,408

 

 

Consulting
1,058

 
1,058

 

 

 

Total
$
149,901

 
$
96,297

 
$
35,836

 
$
8,118

 
$
9,650



23



Indemnities
 
Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated.
 
The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid.

Letters of credit

At June 30, 2012, the Company had provided promissory notes totaling $34.4 million (December 31, 2011 - $20.7 million) as security for letters of credit relating to work commitment guarantees contained in exploration contracts.

Contingencies
 
Ecopetrol and Gran Tierra Energy Colombia Ltd. (“Gran Tierra Colombia”), the contracting parties of the Guayuyaco Association Contract, are engaged in a dispute regarding the interpretation of the procedure for allocation of oil produced and sold during the long-term test of the Guayuyaco-1 and Guayuyaco-2 wells. There is a material difference in the interpretation of the procedure established in Clause 3.5 of Attachment-B of the Guayuyaco Association Contract. Ecopetrol interprets the contract to provide that the extended test production up to a value equal to 30% of the direct exploration costs of the wells is for Ecopetrol’s account only and serves as reimbursement of its 30% back-in to the Guayuyaco discovery. Gran Tierra Colombia’s contention is that this amount is merely the recovery of 30% of the direct exploration costs of the wells and not exclusively for the benefit of Ecopetrol. There has been no agreement between the parties, and Ecopetrol has filed a lawsuit in the Contravention Administrative Court in the District of Cauca regarding this matter. Gran Tierra Colombia filed a response on April 29, 2008 in which it refuted all of Ecopetrol’s claims and requested a change of venue to the courts in Bogota. At this time no amount has been accrued in the financial statements as the Company does not consider it probable that a loss will be incurred. Ecopetrol is claiming damages of approximately $5.8 million.

Gran Tierra’s production from the Costayaco field is subject to an additional royalty that applies when cumulative gross production from a commercial field is greater than five million barrels. This additional royalty is calculated on the difference between a trigger price defined by the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) and the sales price. The ANH has requested that the additional compensation be paid with respect to production from wells relating to the Moqueta discovery and has initiated a non-compliance procedure under the Chaza Contract. The Moqueta discovery is not located in the Costayaco Exploitation Area. Further, Gran Tierra views the Costayaco field and the Moqueta discovery as two clearly separate and independent hydrocarbon accumulations. Therefore, it is Gran Tierra’s view that it is clear that, pursuant to the Chaza Contract, the additional compensation payments are only to be paid with respect to production from the Moqueta wells when the accumulated oil production from any new Exploitation Area created with respect to the Moqueta discovery exceeds five million barrels. Discussions with the ANH have not resolved this issue and Gran Tierra has sent notice to the ANH to initiate the dispute resolution process prescribed by the Chaza Contract. As at June 30, 2012, total cumulative production from the Moqueta field was 0.6 MMbbl. The estimated compensation which would be payable on cumulative production to date if the ANH’s interpretation is successful is $10.3 million. At this time no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

Gran Tierra is subject to a third party 10% net profits interest on 50% of Gran Tierra's production from the Chaza Block that arises from the original acquisition in 2006 of 50% of Gran Tierra's interest in the Chaza Block Contract. There was a disagreement between Gran Tierra and the third party as to the calculation of the net profits interest. Gran Tierra and the third party agreed to resolve this issue through arbitration. The arbitration was heard in Texas, in accordance with the rules of the American Arbitration Association, in the fourth quarter of 2011. Gran Tierra received the arbitrator's decision on May 24, 2012. The arbitrator ruled against Gran Tierra and as a result $10.9 million became payable in relation to past production. The arbitrator's decision will also increase future net profit interests payable to this third party, but is not expected to have a material impact on future results.
Gran Tierra has several lawsuits and claims pending for which the Company currently cannot determine the ultimate result. Gran Tierra records costs as they are incurred or become probable and determinable. Gran Tierra believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations

24



or cash flows.

10. Financial Instruments, Fair Value Measurements and Credit Risk
 
At June 30, 2012, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash, accounts receivable and accounts payable and accrued liabilities. The fair value of long-term restricted cash approximates its carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities. At June 30, 2012, the Company did not have any financial assets or liabilities measured at fair value on the balance sheet and held no derivative instruments. The Company does not use derivative financial instruments for speculative purposes.

At June 30, 2011, the Replacement Warrants (Note 3) met the definition of a derivative. Because the exercise price of the Replacement Warrants was denominated in Canadian dollars, which is different from Gran Tierra’s functional currency, the Replacement Warrants were not considered indexed to Gran Tierra’s common shares and the Replacement Warrants could not be classified within equity. Therefore the Replacement Warrants were classified as a current liability on Gran Tierra’s condensed consolidated balance sheet. Furthermore, these derivative instruments did not qualify as fair value hedges or cash flow hedges, and accordingly, changes in their fair value were recognized as income or expense in the condensed consolidated statement of operations with a corresponding adjustment to the fair value of derivative instruments recognized on the balance sheet. The fair value of the Replacement Warrants at June 30, 2011 was determined using Level 3 inputs (Note 6).

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

At June 30, 2012, cash and cash equivalents and restricted cash included balances in savings and checking accounts, as well as term deposits and certificates of deposit, placed primarily with governments and financial institutions with strong investment grade ratings, or the equivalent in the Company’s operating areas. Any foreign currency transactions are conducted on a spot basis, with major financial institutions in the Company’s operating areas.
 
Most of the Company’s accounts receivable relate to uncollateralized sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. For the three and six months ended June 30, 2012, the Company had one significant customer for its Colombian oil, Ecopetrol, and in Argentina the Company had two significant customers, Shell and Refiner.

Additionally, foreign exchange gains and losses mainly result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, monetary liabilities, which are mainly denominated in the local currency of the Colombian foreign operations. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at $105,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.
 
11. Bank Debt and Credit Facilities
 
Effective July 30, 2010, a subsidiary of Gran Tierra, Solana, established a credit facility with BNP Paribas for a three-year term which may be extended or amended by agreement between the parties. This reserve-based facility has a maximum borrowing base up to $100 million and is supported by the present value of the petroleum reserves of two of the Company’s subsidiaries with operating branches in Colombia, Gran Tierra Colombia and Solana Petroleum Exploration (Colombia) Ltd, and the Company's subsidiary in Brazil - Gran Tierra Energy Brasil Ltda. The initial committed borrowing base was $20 million. Effective August 2, 2012, the committed borrowing base was increased to $50 million. Amounts drawn down under the facility bear interest at the U.S. dollar LIBOR rate plus 3.5%. In addition, a stand-by fee of 1.5% per annum is charged on the unutilized balance of the committed borrowing base and is included in G&A expenses. Under the terms of the facility, the

25



Company is required to maintain and was in compliance with certain financial and operating covenants. As at June 30, 2012 and December 31, 2011, the Company had not drawn down any amounts under this facility. On May 17, 2012, BNP Paribas sold Solana’s credit facility to Wells Fargo Bank National Association, as part of the sale of its North American reserve-based lending business, without any modification to the facility.

12. Related Party Transactions
 
On January 12, 2011, the Company entered into an agreement to sublease office space to a company of which Gran Tierra’s President and Chief Executive Officer serves as an independent director. The term of the sublease runs from February 1, 2011 to January 30, 2013 and the sublease payment is $4,300 per month plus approximately $5,500 of operating and other expense.

On August 3, 2010, Gran Tierra entered into a contract related to the Peru drilling program with a company for which one of Gran Tierra’s directors is a shareholder and director. During the three and six months ended June 30, 2011, $0.2 million and $2.2 million was incurred and capitalized under this contract. During the three and six months ended June 30, 2012, $nil was incurred and capitalized under this contract.

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


26



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
This report, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Please see the cautionary language at the very beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements, as well as Part II, Item 1A “Risk Factors” in this Quarterly Report on Form 10-Q.
 
The following discussion of our financial condition and results of operations should be read in conjunction with the Financial Statements as set out in Part I – Item 1 of this Quarterly Report on Form 10-Q as well as the financial statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K, filed with the U.S. Securities and Exchange Commission (“SEC”) on February 27, 2012.

Overview
 
We are an independent international energy company incorporated in the United States and engaged in oil and natural gas acquisition, exploration, development and production. Our operations are carried out in South America in Colombia, Argentina, Peru, and Brazil, and we are headquartered in Calgary, Alberta, Canada. For the six months ended June 30, 2012, 85% (six months ended June 30, 2011 - 94%) of our revenue and other income was generated in Colombia.

Highlights
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
% Change
 
2012
 
2011
 
% Change
Production (BOEPD) (1)
14,127

 
18,141

 
(22
)
 
15,435

 
16,354

 
(6
)
 
 
 
 
 
 
 
 
 
 
 


Prices Realized - per BOE
$
89.10

 
$
97.93

 
(9
)
 
$
96.04

 
$
95.93

 

 
 
 
 
 
 
 
 
 
 
 


Revenue and Other Income ($000s)
$
115,150

 
$
162,120

 
(29
)
 
$
271,101

 
$
284,639

 
(5
)
 
 
 
 
 
 
 
 
 
 
 


Net Income ($000s)
$
13,104

 
$
31,567

 
(58
)
 
$
12,791

 
$
45,280

 
(72
)
 
 
 
 
 
 
 
 
 
 
 


Net Income Per Share - Basic
$
0.05

 
$
0.11

 
(55
)
 
$
0.05

 
$
0.17

 
(71
)
 
 
 
 
 
 
 
 
 
 
 


Net Income Per Share - Diluted
$
0.05

 
$
0.11

 
(55
)
 
$
0.05

 
$
0.16

 
(69
)
 
 
 
 
 
 
 
 
 
 
 


Funds Flow From Operations ($000s) (2)
$
37,633

 
$
88,572

 
(58
)
 
$
116,576

 
$
155,132

 
(25
)
 
 
 
 
 
 
 
 
 
 
 


Capital Expenditures ($000s)
$
66,604

 
$
101,489

 
(34
)
 
$
154,195

 
$
170,592

 
(10
)

 
As at
 
June 30, 2012
 
December 31, 2011
 
% Change
Cash & Cash Equivalents ($000s)
$
128,528

 
$
351,685

 
(63
)
 
 
 
 
 
 
Working Capital (including cash & cash equivalents) ($000s)
$
160,614

 
$
213,100

 
(25
)
 
 
 
 
 
 
Property, Plant & Equipment ($000s)
$
1,100,143

 
$
1,044,842

 
5


(1) Production represents production volumes NAR adjusted for inventory changes. NGL volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices.

27



 
(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 taxes, stock-based compensation, gain on financial instruments, unrealized foreign exchange gain or loss, settlement of asset retirement obligation, equity tax and gain on acquisition. A reconciliation from net income to funds flow from operations is as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Funds Flow From Operations - Non-GAAP Measure ($000s)
2012
 
2011
 
2012
 
2011
Net income
$
13,104

 
$
31,567

 
$
12,791

 
$
45,280

Adjustments to reconcile net income to funds flow from operations
 
 
 
 
 
 
 
DD&A expenses
32,571

 
46,965

 
92,938

 
110,322

Deferred taxes
(4,800
)
 
(5,219
)
 
(10,050
)
 
(5,406
)
Stock-based compensation
3,730

 
2,492

 
6,922

 
5,945

Unrealized gain on financial instruments

 
(1,292
)
 

 
(1,354
)
Unrealized foreign exchange (gain) loss
(5,187
)
 
11,644

 
16,164

 
16,102

Settlement of asset retirement obligation

 
(305
)
 
(404
)
 
(309
)
Equity tax
(1,785
)
 
119

 
(1,785
)
 
6,251

Gain on acquisition

 
2,601

 

 
(21,699
)
Funds flows from operations
$
37,633

 
$
88,572

 
$
116,576

 
$
155,132


Highlights
 
Effective June 30, 2012, Costayaco Field reserves, NAR, calculated in accordance with SEC rules, increased, adjusted for production from the first half of 2012, from year-end 2011 reserves as follows: total proved reserves increased 33% to approximately 19.6 MMbbl, total proved plus probable reserves increased 35% to approximately 22.2 MMbbl, and total proved plus probable plus possible reserves increased 18% to approximately 25.6 MMbbl.

In the second quarter of 2012, oil and natural gas production, NAR and adjusted for inventory changes, averaged 14,127 BOEPD, a decrease of 22% over the second quarter of 2011. The decrease was primarily due to oil delivery restrictions during disruptions in the Ecopetrol-operated Trans-Andean oil pipeline (“the OTA pipeline”) in Colombia, partially offset by production from new producing wells in Colombia. For the first half of 2012, oil and gas production, NAR and adjusted for inventory changes, decreased by 6% to 15,435 BOEPD compared with the first half of 2011. Production during the first half of 2012 was impacted by an increase in oil inventory in the OTA pipeline as a result of the change in the sales point in Colombia and pipeline disruptions.

Revenue and other income decreased by 29% to $115.2 million in the second quarter of 2012 compared with $162.1 million in the second quarter of 2011 due to lower production and realized oil prices. The average price realized in the second quarter of 2012 was $89.10 per BOE, a decrease of 9% compared with $97.93 per BOE in the second quarter of 2011. The price was impacted by the settlement of a third party royalty dispute in Colombia which reduced the average realized price by $8.48 per BOE in the second quarter of 2012 and $3.88 per BOE in the first half of 2012. For the first half of 2012, the average price realized per BOE was consistent with the comparative period in 2011 at $96.04. The third party royalty settlement related to production from July 2009 to May 2012, represented less than 1% of the reported revenue for the periods under dispute, and is not expected to have a materially different effect on future revenue.

 

28



Net income was $13.1 million in the second quarter of 2012, representing basic and diluted net income per share of $0.05. This compares with net income of