10-Q 1 gte-20130331x10q.htm 10-Q GTE - 2013.03.31 - 10Q


 

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

ý
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended March 31, 2013

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 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 April 30, 2013, the following number of shares of the registrant’s capital stock were outstanding: 269,577,263 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 6,840,062 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

Three Months Ended March 31, 2013

Table of contents
 
 
 
Page
PART I
Financial Information
 
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
Other Information
 
Item 1.
Legal Proceedings
Item 1A.
Risk Factors
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, 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. Farm-in or farm-out transactions refer to transactions in which a portion of a working interest is sold by an owner of an oil and gas property. The transaction is labeled a farm-in by the purchaser of the working interest and a farm-out by the seller of the working interest. Payment in a farm-in or farm-out transaction can be in cash or in kind by committing to perform and/or pay for certain work obligations.

3



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

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

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

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




4



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.

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.


5



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.

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 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.

6




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.


7



PART I - Financial Information

Item 1. Financial Statements
 
Gran Tierra Energy Inc.
Condensed Consolidated Statements of Operations and Retained Earnings (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
 
 
 
Three Months Ended March 31,
 
 
2013
 
2012
REVENUE AND OTHER INCOME
 
 
 
 
Oil and natural gas sales
 
$
204,780

 
$
155,248

Interest income
 
591

 
703

 
 
205,371

 
155,951

EXPENSES
 
 
 
 
Operating
 
41,015

 
24,487

Depletion, depreciation, accretion and impairment (Note 4)
 
58,412

 
60,367

General and administrative
 
11,421

 
15,899

Foreign exchange (gain) loss
 
(5,229
)
 
24,375

Other loss (Note 8)
 
4,400

 

 
 
110,019

 
125,128

 
 
 
 
 
INCOME BEFORE INCOME TAXES
 
95,352

 
30,823

Income tax expense (Note 7)
 
(37,439
)
 
(31,136
)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
 
57,913

 
(313
)
RETAINED EARNINGS, BEGINNING OF PERIOD
 
284,673

 
185,014

RETAINED EARNINGS, END OF PERIOD
 
$
342,586

 
$
184,701

 
 
 
 
 
NET INCOME (LOSS) PER SHARE — BASIC

$
0.21


$
(0.00
)
NET INCOME (LOSS) PER SHARE — DILUTED

$
0.20


$
(0.00
)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 5)
 
282,138,525

 
278,734,280

WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 5)
 
285,026,183

 
278,734,280


(See notes to the condensed consolidated financial statements)



8



Gran Tierra Energy Inc.
Condensed Consolidated Balance Sheets (Unaudited)
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
 
March 31,
 
December 31,
 
2013
 
2012
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
235,910

 
$
212,624

Restricted cash
1,375

 
1,404

Accounts receivable
147,791

 
119,844

Inventory (Note 4)
18,320

 
33,468

Taxes receivable
14,326

 
39,922

Prepaids
4,332

 
4,074

Deferred tax assets (Note 7)
1,361

 
2,517

Total Current Assets
423,415

 
413,853

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

 
 

Proved
802,267

 
813,247

Unproved
418,647

 
383,414

Total Oil and Gas Properties
1,220,914

 
1,196,661

Other capital assets
8,946

 
8,765

Total Property, Plant and Equipment (Note 4)
1,229,860

 
1,205,426

 
 
 
 
Other Long-Term Assets
 

 
 

Restricted cash
2,386

 
1,619

Deferred tax assets (Note 7)
2,807

 
1,401

Taxes receivable
2,564

 
1,374

Other long-term assets
7,448

 
6,621

Goodwill
102,581

 
102,581

Total Other Long-Term Assets
117,786

 
113,596

Total Assets
$
1,771,061

 
$
1,732,875

LIABILITIES AND SHAREHOLDERS’ EQUITY
 

 
 

Current Liabilities
 

 
 

Accounts payable
$
66,058

 
$
102,263

Accrued liabilities
78,480

 
66,418

Taxes payable
31,387

 
22,339

Deferred tax liabilities (Note 7)
668

 
337

Asset retirement obligation (Note 6)

 
28

Total Current Liabilities
176,593

 
191,385

 
 
 
 
Long-Term Liabilities
 

 
 

Deferred tax liabilities (Note 7)
211,515

 
225,195

Equity tax payable (Note 7)
3,437

 
3,562

Asset retirement obligation (Note 6)
18,930

 
18,264

Other long-term liabilities
7,382

 
3,038

Total Long-Term Liabilities
241,264

 
250,059

 
 
 
 
Contingencies (Note 8)


 


Shareholders’ Equity
 

 
 

Common Stock (Note 5) (269,518,147 and 268,482,445 shares of Common Stock and 13,122,988 and 13,421,488 exchangeable shares, par value $0.001 per share, issued and outstanding as at March 31, 2013 and December 31, 2012, respectively)
8,973

 
7,986

Additional paid in capital
1,001,645

 
998,772

Retained earnings
342,586

 
284,673

Total Shareholders’ Equity
1,353,204

 
1,291,431

Total Liabilities and Shareholders’ Equity
$
1,771,061

 
$
1,732,875


(See notes to the condensed consolidated financial statements)

9



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)
(Thousands of U.S. Dollars)
 
Three Months Ended March 31,
 
2013
 
2012
Operating Activities
 
 
 
Net income (loss)
$
57,913

 
$
(313
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 

Depletion, depreciation, accretion and impairment
58,412

 
60,367

Deferred tax recovery (Note 7)
(7,450
)
 
(5,250
)
Stock-based compensation (Note 5)
2,067

 
3,192

Unrealized foreign exchange (gain) loss
(6,744
)
 
21,351

Settlement of asset retirement obligation (Note 6)

 
(404
)
Other loss (Note 8)
4,400

 

Net change in assets and liabilities from operating activities
 

 
 

Accounts receivable and other long-term assets
(29,387
)
 
(72,865
)
Inventory
11,643

 
(4,500
)
Prepaids
(258
)
 
(618
)
Accounts payable and accrued and other liabilities
(14,731
)
 
(34,035
)
Taxes receivable and payable
33,926

 
19,595

Net cash provided by (used in) operating activities
109,791

 
(13,480
)
 
 
 
 
Investing Activities
 

 
 

Increase in restricted cash
(738
)
 
(31,037
)
Additions to property, plant and equipment
(87,378
)
 
(77,983
)
Net cash used in investing activities
(88,116
)
 
(109,020
)
 
 
 
 
Financing Activities
 

 
 

Proceeds from issuance of shares of Common Stock
1,611

 
891

Net cash provided by financing activities
1,611

 
891

 
 
 
 
Net increase (decrease) in cash and cash equivalents
23,286

 
(121,609
)
Cash and cash equivalents, beginning of period
212,624

 
351,685

Cash and cash equivalents, end of period
$
235,910

 
$
230,076

 
 
 
 
Cash
$
230,767

 
$
148,035

Term deposits
5,143

 
82,041

Cash and cash equivalents, end of period
$
235,910

 
$
230,076

 
 
 
 
Supplemental cash flow disclosures:
 

 
 

Cash paid for income taxes
$
13,103

 
$
13,733

 
 
 
 
Non-cash investing activities:
 

 
 

Non-cash net liabilities related to property, plant and equipment, end of period
$
66,536

 
$
53,090


(See notes to the condensed consolidated financial statements)

10



Gran Tierra Energy Inc.
Condensed Consolidated Statements of Shareholders’ Equity (Unaudited)
(Thousands of U.S. Dollars)
 
 
Three Months Ended March 31,
 
Year Ended December 31,
 
2013
 
2012
Share Capital
 
 
 
Balance, beginning of period
$
7,986

 
$
7,510

Issue of shares of Common Stock (Note 5)
987

 
476

Balance, end of period
8,973

 
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)
624

 
960

Stock-based compensation (Note 5)
2,249

 
13,116

Balance, end of period
1,001,645

 
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
57,913

 
99,659

Balance, end of period
342,586

 
284,673

 
 
 
 
Total Shareholders’ Equity
$
1,353,204

 
$
1,291,431


(See notes to the condensed consolidated financial statements)


11



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. The Company has evaluated all subsequent events through to the date these interim unaudited condensed consolidated financial statements were issued.

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.

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 March 31, 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.


12



The following tables present information on the Company’s reportable segments and other activities:
 
Three Months Ended March 31, 2013
(Thousands of U.S. Dollars, except per unit of production amounts)
Colombia
 
Argentina
 
Peru
 
Brazil
 
All Other
 
Total
Oil and natural gas sales
180,003

 
18,540

 

 
6,237

 

 
204,780

Interest income
161

 
243

 
14

 
9

 
164

 
591

Depletion, depreciation, accretion and impairment
45,956

 
7,950

 
62

 
4,171

 
273

 
58,412

Depletion, depreciation, accretion and impairment - per unit of production
26.32

 
26.68

 

 
65.34

 

 
27.71

Income (loss) before income taxes
101,668

 
(1,636
)
 
(1,227
)
 
(439
)
 
(3,014
)
 
95,352

Segment capital expenditures
30,407

 
4,805

 
29,247

 
14,539

 
11

 
79,009

 
Three Months Ended March 31, 2012
(Thousands of U.S. Dollars, except per unit of production amounts)
Colombia
 
Argentina
 
Peru
 
Brazil
 
All Other
 
Total
Oil and natural gas sales
138,633

 
15,369

 

 
1,246

 

 
155,248

Interest income
204

 
47

 
15

 
294

 
143

 
703

Depletion, depreciation, accretion and impairment
32,286

 
5,925

 
115

 
21,808

 
233

 
60,367

Depletion, depreciation, accretion and impairment - per unit of production
25.80

 
22.80

 

 
1,741.44

 

 
39.62

Income (loss) before income taxes
60,120

 
(477
)
 
(727
)
 
(22,070
)
 
(6,023
)
 
30,823

Segment capital expenditures
20,349

 
14,105

 
16,655

 
36,256

 
226

 
87,591

 
 
As at March 31, 2013
(Thousands of U.S. Dollars)
Colombia
 
Argentina
 
Peru
 
Brazil
 
All Other
 
Total
Property, plant and equipment
$
827,899

 
$
136,029

 
$
125,125

 
$
137,772

 
$
3,035

 
$
1,229,860

Goodwill
102,581

 

 

 

 

 
102,581

Other assets
229,313

 
43,556

 
15,593

 
5,262

 
144,896

 
438,620

Total Assets
$
1,159,793

 
$
179,585

 
$
140,718

 
$
143,034

 
$
147,931

 
$
1,771,061

 
 
 
 
 
 
 
 
 
 
 
 
 
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 three months ended March 31, 2013, the Company had three significant customers in Colombia: Ecopetrol S.A. ("Ecopetrol") and two other customers, which accounted for 54%, 21% and 11%, respectively, of the Company's consolidated revenue and other income for the three months ended March 31, 2013. For the three months ended March 31, 2012, sales to Ecopetrol accounted for 85% of the Company's consolidated revenues.
 


13



4. Property, Plant and Equipment and Inventory
 
Property, Plant and Equipment

 
As at March 31, 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
$
1,605,483

 
$
(803,216
)
 
$
802,267

 
$
1,562,477

 
$
(749,230
)
 
$
813,247

  Unproved
418,647

 

 
418,647

 
383,414

 

 
383,414

 
2,024,130

 
(803,216
)
 
1,220,914

 
1,945,891

 
(749,230
)
 
1,196,661

Furniture and fixtures and leasehold improvements
7,514

 
(5,239
)
 
2,275

 
7,575

 
(5,093
)
 
2,482

Computer equipment
11,709

 
(5,675
)
 
6,034

 
10,971

 
(5,248
)
 
5,723

Automobiles
1,469

 
(832
)
 
637

 
1,376

 
(816
)
 
560

Total Property, Plant and Equipment
$
2,044,822

 
$
(814,962
)
 
$
1,229,860

 
$
1,965,813

 
$
(760,387
)
 
$
1,205,426

 
Depletion and depreciation expense on property, plant and equipment for the three months ended March 31, 2013, was $54.6 million (three months ended March 31, 2012 - $42.6 million). A portion of depletion and depreciation expense was recorded as inventory in each period and adjusted for inventory changes.

On February 17, 2012, in accordance with the terms of the farm-out agreement for Block 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 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 three months ended March 31, 2012, the Company recorded a ceiling test impairment loss in the Company’s Brazil cost center of $20.2 million. This impairment charge resulted from the recognition of $23.8 million of capital expenditures in relation to the Block BM-CAL-10 farm-out agreement in the first quarter of 2012.

The amounts of G&A and stock-based compensation capitalized in each of the Company's cost centers during the three months ended March 31, 2013 and 2012, respectively, were as follows:

 
Three Months Ended March 31, 2013
(Thousands of U.S. Dollars)
Colombia
 
Argentina
 
Peru
 
Brazil
 
Total
Capitalized G&A, including stock-based compensation
$
4,874

 
$
1,265

 
$
1,570

 
$
1,145

 
$
8,854

Capitalized stock-based compensation
$
74

 
$
60

 
$

 
$
48

 
$
182

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

 
$
1,080

 
$
927

 
$
1,068

 
$
4,927

Capitalized stock-based compensation
$
114

 
$
66

 
$

 
$
59

 
$
239



14



Unproved oil and natural gas properties consist of exploration lands held in Colombia, Argentina, Peru and Brazil. As at March 31, 2013, the Company had $177.0 million (December 31, 2012 - $175.9 million) of unproved assets in Colombia, $41.6 million (December 31, 2012 - $42.3 million) of unproved assets in Argentina, $124.3 million (December 31, 2012 - $95.1 million) of unproved assets in Peru, and $75.7 million (December 31, 2012 - $70.1 million) of unproved assets in Brazil for a total of $418.6 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 53% of costs not subject to depletion at March 31, 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 March 31, 2013, oil and supplies inventories were $16.0 million and $2.3 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 March 31, 2013, outstanding share capital consists of 269,518,147 shares of Common Stock of the Company, 6,899,178 exchangeable shares of Gran Tierra Exchange Co., (the "Exchangeco exchangeable shares") that will be automatically exchangeable on November 14, 2013, except under certain specified circumstances, and 6,223,810 exchangeable shares of Goldstrike Exchange Co. (the "Goldstrike exchangeable shares"), automatically exchangeable on November 10, 2013. During the three months ended March 31, 2013, 737,202 shares of Common Stock were issued upon the exercise of stock options and 298,500 shares of common stock were issued upon the exchange of the Exchangeco exchangeable shares.

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

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. On October 5, 2012, the automatic redemption date on the Goldstrike exchangeable shares was extended by one year to November 10, 2013. As at March 31, 2013, 95.8% of the outstanding Goldstrike exchangeable shares were held by directors and management of 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.

Stock Options
  
The Company grants options to purchase shares of Common Stock to certain directors, officers, employees and consultants in accordance with the 2007 Equity Incentive Plan. The Company did not make its customary annual grant of options during the three months ended March 31, 2013, because the Company was assessing proposed changes to its long-term incentive plan.
 

15



The following table provides information about stock option activity for the three months ended March 31, 2013:
 
Number of Outstanding Options
 
Weighted Average Exercise Price $/Option
Balance, December 31, 2012
15,399,662

 
5.11

Granted
75,000

 
6.00

Exercised
(737,202
)
 
(2.18
)
Forfeited
(117,211
)
 
(6.31
)
Expired
(29,766
)
 
(6.89
)
Balance, March 31, 2013
14,590,483

 
5.25


For the three months ended March 31, 2013, 737,202 shares of Common Stock were issued for cash proceeds of $1.6 million upon the exercise of 737,202 stock options (three months ended March 31, 2012 - $0.9 million).

The weighted average grant date fair value for options granted in the three months ended March 31, 2013, was $3.33 (three months ended March 31, 2012 - $3.37).

For the three months ended March 31, 2013, the stock-based compensation expense was $2.2 million (three months ended March 31, 2012- $3.4 million) of which $1.8 million (three months ended March 31, 2012 - $2.9 million) was recorded in G&A expenses, $0.2 million was recorded in operating expenses (three months ended March 31, 2012$0.3 million) and $0.2 million was capitalized as part of exploration and development costs (three months ended March 31, 2012$0.2 million).

At March 31, 2013, there was $6.0 million (December 31, 2012 - $8.2 million) of unrecognized compensation cost related to unvested stock options which is expected to be recognized over the next two years.

Net income per share
Basic net income per share is calculated by dividing net income attributable to common shareholders by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income per share is calculated by adjusting the weighted average number of shares of Common Stock and exchangeable shares outstanding for the dilutive effect, if any, of share equivalents. The Company uses the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume weighted average trading price of shares of Common Stock during the period.
 
 
 
Three Months Ended March 31,
 
 
2013
 
2012
Weighted average number of common and exchangeable shares outstanding
 
282,138,525

 
278,734,280

Shares issuable pursuant to stock options
 
5,482,456

 

Shares assumed to be purchased from proceeds of stock options
 
(2,594,798
)
 

Weighted average number of diluted common and exchangeable shares outstanding
 
285,026,183

 
278,734,280

 
For the three months ended March 31, 2013, 9,392,605 options (three months ended March 31, 2012 - 15,694,501 options and 6,098,224 warrants to purchase 3,049,112 shares of Common Stock) were excluded from the diluted income per share calculation as the options were anti-dilutive.
 


16



6. Asset Retirement Obligation
 
Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:
 
Three Months Ended
 
Year Ended
(Thousands of U.S. Dollars)
March 31, 2013
 
December 31, 2012
Balance, beginning of year
$
18,292

 
$
12,669

Settlements

 
(404
)
Liability incurred
237

 
5,190

Liability assumed in a business combination

 
410

Foreign exchange
(9
)
 
45

Accretion
410

 
998

Revisions in estimated liability

 
(616
)
Balance, end of period
$
18,930

 
$
18,292

 
 
 
 
Asset retirement obligation - current
$

 
$
28

Asset retirement obligation - long-term
18,930

 
18,264

Balance, end of period
$
18,930

 
$
18,292

 
Revisions to estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling the asset retirement obligation. At March 31, 2013, the fair value of assets that are legally restricted for purposes of settling asset retirement obligations was $2.0 million (December 31, 2012 - $1.3 million).


17



7. Taxes
 
The income tax expense reported differs from the amount computed by applying the U.S. statutory rate to income before income taxes for the following reasons:
 
Three Months Ended March 31,
(Thousands of U.S. Dollars)
2013
 
2012
Income (loss) before income taxes
 
 
 
United States
(2,091
)
 
634

Foreign
97,443

 
30,189

 
95,352

 
30,823

 
35
%
 
35
%
Income tax expense expected
33,373

 
10,788

Foreign currency translation adjustments
(1,878
)
 
8,718

Impact of foreign taxes
(224
)
 
(631
)
Stock-based compensation
686

 
1,003

Increase in valuation allowance
1,844

 
10,145

Branch and other foreign loss pick-up
(827
)
 
(622
)
Non-deductible third party royalty in Colombia
3,547

 
1,943

Other permanent differences
918

 
(208
)
Total income tax expense
$
37,439

 
$
31,136

 
 
 
 
Current income tax expense
 
 
 
United States
306

 
172

Foreign
44,583

 
36,214

 
44,889

 
36,386

Deferred income tax recovery
 
 
 
United States

 

Foreign
(7,450
)
 
(5,250
)
 
(7,450
)
 
(5,250
)
Total income tax expense
$
37,439

 
$
31,136



18



 
As at
(Thousands of U.S. Dollars)
March 31, 2013
 
December 31, 2012
Deferred Tax Assets
 

 
 

Tax benefit of operating loss carryforwards
$
54,136

 
$
51,920

Tax basis in excess of book basis
23,139

 
22,519

Foreign tax credits and other accruals
30,063

 
30,926

Tax benefit of capital loss carryforwards
4,674

 
4,779

Deferred tax assets before valuation allowance
112,012

 
110,144

Valuation allowance
(107,844
)
 
(106,226
)
 
$
4,168

 
$
3,918

 
 
 
 
Deferred tax assets - current
$
1,361

 
$
2,517

Deferred tax assets - long-term
2,807

 
1,401

 
4,168

 
3,918

Deferred tax liabilities - current
(668
)
 
(337
)
Deferred tax liabilities - long-term
(211,515
)
 
(225,195
)
 
$
(212,183
)
 
$
(225,532
)
Net Deferred Tax Liabilities
$
(208,015
)

$
(221,614
)

As at March 31, 2013, the Company had operating loss carryforwards of $223.4 million (December 31, 2012 - $213.1 million) and capital loss carryforwards of $35.0 million (December 31, 2012$35.9 million) before valuation allowance. Of these operating loss carryforwards and capital loss carryforwards, $224.8 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 2013 and 2017, while certain other jurisdictions allow operating losses to be carried forward indefinitely.

As at March 31, 2013, the total amount of Gran Tierra’s unrecognized tax benefit was approximately $21.8 million (December 31, 2012 - $21.8 million), a portion of which, if recognized, would affect the Company’s effective tax rate. There was no change in the Company's unrecognized tax benefit during the three months ended March 31, 2013, or 2012. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the consolidated statement of operations. As at March 31, 2013, the amount of interest and penalties on the unrecognized tax benefit included in current income tax liabilities in the consolidated balance sheet was approximately $3.6 million (December 31, 2012 - $3.6 million). The Company had no other material interest or penalties included in the consolidated statement of operations for the three months ended March 31, 2013, and 2012, respectively.
 
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 March 31, 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 acquisition of Petrolifera Petroleum Limited.
 


19



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 three months ended March 31, 2013, the Tribunal ruled in favor of Ecopetrol and awarded Ecopetrol 44,025 bbl of oil. GTEC has filed an appeal of the ruling to the Supreme Administrative Court (Consejo de Estado) in a second instance procedure. During the three months ended March 31, 2013, based on market oil prices in Colombia, we 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 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 initiated the dispute resolution process and filed an arbitration claim. As at March 31, 2013, total cumulative production from the Moqueta field was 1.2 MMbbl. The estimated compensation which would be payable on cumulative production to date if the ANH’s interpretation is successful is $20.0 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 March 31, 2013, the estimated compensation which would be payable if the ANH’s interpretation is successful is $15.7 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 March 31, 2013, the Company had provided promissory notes totaling $47.0 million (December 31, 2012 - $34.2 million) as security for letters of credit relating to work commitment guarantees contained in exploration contracts.

9. Financial Instruments, Fair Value Measurements and Credit Risk
 
At March 31, 2013, 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 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 March 31, 2013, and December 31, 2012. The fair value of the contingent liability was $4.4 million at March 31, 2013. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments. At March 31, 2013, and December 31, 2012, the Company held no derivative instruments.

20




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 March 31, 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 March 31, 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 governments and financial institutions with strong investment grade ratings, or the equivalent in the Company’s operating areas. Any foreign currency transactions are conducted on a spot basis, with major financial institutions in the Company’s operating areas.
 
Most of the Company’s accounts receivable relate to uncollateralized sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. For the three months ended March 31, 2013, the Company had three significant customers for its Colombian oil and three significant customers in Argentina.

For the three months ended March 31, 2013, 88% (three months ended March 31, 2012 - 89%) of our 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, 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 $113,000 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 Central Bank may require prior authorization and may or may not grant such authorization for Gran Tierra's Argentina subsidiaries to make dividends or loan payments to the company. At March 31, 2013, $22.8 million, or 10%, of our cash and cash equivalents was deposited with banks in Argentina. We expect to use to these funds for the work program and operations in Argentina in 2013.
 
10. Credit Facilities
 
At March 31, 2013, a subsidiary of Gran Tierra had a credit facility with Wells Fargo Bank National Association. 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 and the Company's subsidiary in Brazil.
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. The original credit facility became effective on July 30, 2010, for a three-year term. Under the terms of the facility, the Company is required to maintain and was in compliance with certain financial and operating covenants. As at March 31, 2013, and December 31, 2012, the Company had not drawn down any amounts under this facility. 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.



21



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 months ended March 31, 2013, $3.2 million (three months ended March 31, 2012 - $nil) was incurred and capitalized under this contract and at March 31, 2013, $2.3 million (December 31, 2012 - $1.1 million) was included in accounts payable relating to this contract.
 

22



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 in Colombia, Argentina, Peru and Brazil, and we are headquartered in Calgary, Alberta, Canada. For the three months ended March 31, 2013, 88% (three months ended March 31, 2012 - 89%) of our revenue and other income was generated in Colombia.

Highlights
 
 
 
Three Months Ended March 31,
 
 
2013
 
2012
 
% Change
Production (BOEPD) (1)
 
23,424

 
16,742

 
40

 
 
 
 
 
 


Prices Realized - per BOE
 
$
97.14

 
$
101.90

 
(5
)
 
 
 
 
 
 


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

 
$
155,951

 
32

 
 
 
 
 
 


Net Income (Loss) ($000s)
 
$
57,913

 
$
(313
)
 

 
 
 
 
 
 


Net Income (Loss) Per Share - Basic
 
$
0.21

 
$
(0.00
)
 

 
 
 
 
 
 


Net Income (Loss) Per Share - Diluted
 
$
0.20

 
$
(0.00
)
 

 
 
 
 
 
 


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

 
$
78,943

 
38

 
 
 
 
 
 


Capital Expenditures ($000s)
 
$
79,009

 
$
87,591

 
(10
)

 
As at
 
March 31, 2013
 
December 31, 2012
 
% Change
Cash & Cash Equivalents ($000s)
$
235,910

 
$
212,624

 
11
 
 
 
 
 
 
Working Capital (including cash & cash equivalents) ($000s)
$
246,822

 
$
222,468

 
11
 
 
 
 
 
 
Property, Plant & Equipment ($000s)
$
1,229,860

 
$
1,205,426

 
2

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

23



(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 or loss adjusted for depletion, depreciation, accretion and impairment (“DD&A”) expenses, deferred taxes, stock-based compensation,  unrealized foreign exchange loss or gain, settlement of asset retirement obligation and other loss. A reconciliation from net income to funds flow from operations is as follows:
 
 
Three Months Ended March 31,
Funds Flow From Operations - Non-GAAP Measure ($000s)
 
2013
 
2012
Net income (loss)
 
$
57,913

 
$
(313
)
Adjustments to reconcile net income (loss) to funds flow from operations
 
 
 
 
DD&A expenses
 
58,412

 
60,367

Deferred taxes
 
(7,450
)
 
(5,250
)
Stock-based compensation
 
2,067

 
3,192

Unrealized foreign exchange (gain) loss
 
(6,744
)
 
21,351

Settlement of asset retirement obligation
 

 
(404
)
  Other loss
 
4,400

 

Funds flow from operations
 
$
108,598

 
$
78,943


For the three months ended March 31, 2013, oil and gas production, NAR and adjusted for inventory changes, increased by 40% to 23,424 BOEPD compared with the comparable period in 2012. Alternative transportation arrangements to minimize the impact of pipeline disruptions in Colombia, a decrease in oil inventory in Colombia, and production from new wells in Colombia and Argentina all had a positive impact on production in 2013. The net inventory reduction accounted for 0.1 MMbl or 1,554 BOEPD of the reported increase in production in the three months ended March 31, 2013. In 2013, production was 75% from the Chaza Block in Colombia and 8% and 5% from the Puesto Morales and Surubi Blocks in Argentina, respectively.

For the three months ended March 31, 2013, revenue and other income increased by 32% to $205.4 million compared with $156.0 million in 2012. The positive contribution from higher production levels was partially offset by lower realized prices. The average price realized per BOE of $97.14, decreased by 5% from $101.90 in 2012.
 
Net income was $57.9 million, or $0.21 per share basic and $0.20 per share diluted, for the three months ended March 31, 2013, compared with a loss of $0.3 million, or $0.00 per share basic and diluted, in 2012. In 2013, increased oil and natural gas sales, decreased DD&A and general and administrative ("G&A") expenses and a foreign exchange gain were partially offset by increased operating and income tax expenses and other losses.

For the three months ended March 31, 2013, funds flow from operations increased by 38% from $78.9 million to $108.6 million primarily due to increased oil and natural gas sales, decreased G&A expenses and realized foreign exchange losses, partially offset by increased operating and income tax expenses and other losses.

Cash and cash equivalents were $235.9 million at March 31, 2013, compared with $212.6 million at December 31, 2012. The increase in cash and cash equivalents during 2013 was primarily the result of funds flow from operations of $108.6 million, partially offset by capital expenditures of $87.4 million.

Working capital (including cash and cash equivalents) was $246.8 million at March 31, 2013, a $24.4 million increase from December 31, 2012. The increase was primarily a result of the following: a $23.3 million increase in cash and cash equivalents; a $27.9 million increase in accounts receivable primarily related to increased volumes sold and increased prices for sales to Ecopetrol S.A. ("Ecopetrol") in Colombia, partially offset by the impact of a reduction in the number of days of sales outstanding in Argentina; and a $24.1 million decrease in accounts payable and accrued liabilities mainly in relation to our capital program and the timing of payments for drilling in Colombia. These increases in cash and working capital were partially offset by the following: a $15.1 million decrease in inventory primarily due to the timing of recognition of oil sales to a customer in Colombia where the sale is recognized when the

24



customer exports oil; a $25.6 million decrease in net taxes receivable due to the reimbursement of value added tax receivable and increased taxable income in Colombia; and a $9.0 million increase in taxes payable due to increased taxable income in Colombia.

Property, plant and equipment at March 31, 2013, was $1.2 billion, an increase of $24.4 million from December 31, 2012, as a result of $79.0 million of capital expenditures (excluding changes in non-cash working capital), partially offset by $54.6 million of depletion, depreciation and impairment expenses.

Our capital expenditures for the three months ended March 31, 2013, were $79.0 million compared with $87.6 million for the three months ended March 31, 2012. In 2013, capital expenditures included drilling of $58.1 million, geological and geophysical (“G&G”) expenditures of $8.0 million, facilities of $7.0 million and other expenditures of $5.9 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 demand growth.

We believe that our current operations and 2013 capital expenditure program can be funded from cash flow from existing operations, cash on hand and potential periodic draws from our revolving credit facility. 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, issuance of debt, disposition of assets, or issuance of equity. Continuing social uncertainty in the Middle East and North Africa, economic uncertainty in the United States, Europe and China 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.
 
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.



25



Consolidated Results of Operations

 
 
Three Months Ended March 31,
 
 
2013
 
2012
 
% Change
(Thousands of U.S. Dollars)
 
 
 
 
 
 
Oil and natural gas sales
 
$
204,780

 
$
155,248

 
32

Interest income
 
591

 
703

 
(16
)
 
 
205,371


155,951

 
32

 
 
 
 
 
 

Operating expenses
 
41,015

 
24,487

 
67

DD&A expenses
 
58,412

 
60,367

 
(3
)
G&A expenses
 
11,421

 
15,899

 
(28
)
Foreign exchange (gain) loss
 
(5,229
)
 
24,375

 
(121
)
Other loss
 
4,400

 

 

 
 
110,019

 
125,128

 
(12
)
 
 
 
 
 
 

Income before income taxes
 
95,352

 
30,823

 
209

Income tax expense
 
(37,439
)
 
(31,136
)
 
20

Net income (loss)
 
$
57,913

 
$
(313
)
 

 
 
 
 
 
 

Production
 
 
 
 
 

 
 
 
 
 
 

Oil and NGL's, bbl
 
2,052,737

 
1,461,404

 
40

Natural gas, Mcf
 
332,613

 
372,947

 
(11
)
Total production, BOE (1)
 
2,108,173
 
1,523,562
 
38

 
 
 
 
 
 

Average Prices
 
 
 
 
 

 
 
 
 
 
 

Oil and NGL's per bbl
 
$
99.17

 
$
105.36

 
(6
)
Natural gas per Mcf
 
$
3.61

 
$
3.42

 
6

 
 
 
 
 
 


Consolidated Results of Operations per BOE
 
 
 
 
 


 
 
 
 
 
 


Oil and natural gas sales
 
$
97.14

 
$
101.90

 
(5
)
Interest income
 
0.28

 
0.46

 
(39
)
 
 
97.42

 
102.36

 
(5
)
 
 
 
 
 
 


Operating expenses
 
19.46

 
16.07

 
21

DD&A expenses
 
27.71

 
39.62

 
(30
)
G&A expenses
 
5.42

 
10.44

 
(48
)
Foreign exchange (gain) loss
 
(2.48)

 
16.00

 
(116
)
Other loss
 
2.09

 

 

 
 
52.20
 
82.13
 
(36
)
 
 
 
 
 
 


Income before income taxes
 
45.22

 
20.23

 
124

Income tax expense
 
(17.76)

 
(20.44)

 
(13
)
Net income (loss)
 
$
27.46

 
$
(0.21
)
 

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

Net income for the three months ended March 31, 2013, was $57.9 million, compared to a loss of $0.3 million in the comparable period in 2012. On a per share basis, net income increased to $0.21 per share basic and $0.20 per share diluted from $0.00 per share basic and diluted in 2012. For the three months ended March 31, 2013, increased oil and natural gas sales, decreased DD&A and G&A expenses and a foreign exchange gain, were partially offset by increased operating and income tax expenses and other loss.

Oil and NGL production for the three months ended March 31, 2013, increased to 2.1 MMbbl compared with 1.5 MMbbl in 2012. The increase was due to the reduced impact of pipeline disruptions in Colombia, a decrease in oil inventory in the

26



Ecopetrol-operated Trans-Andean oil pipeline (the "OTA pipeline”) and associated Ecopetrol owned facilities in the Putumayo Basin, reduced oil inventory related to sales to a customer in Colombia with a protracted sales cycle whereby the transfer of ownership occurs upon export, and production from new wells in Colombia and Argentina. The net inventory reduction accounted for 0.1 MMbl or 1,554 BOEPD of the reported increase in production. Production during the three months ended March 31, 2013, reflected approximately 44 days of oil pipeline delivery restrictions in Colombia.

Average realized oil prices decreased by 6% to $99.17 per bbl from $105.36 per bbl for the three months ended March 31, 2013. Average Brent oil prices for the three months ended March 31, 2013, were $112.51 per bbl compared with $118.56 per bbl in 2012. WTI oil prices for the three months ended March 31, 2013, averaged $94.40 per bbl compared with $102.89 per bbl in 2012.

Revenue and other income for the three months ended March 31, 2013, increased to $205.4 million from $156.0 million in 2012 as a result of increased production, partially offset by decreased realized prices.

Operating expenses for the three months ended March 31, 2013, were $41.0 million, or $19.46 per BOE, compared with $24.5 million, or $16.07 per BOE, in 2012. The increase in operating expenses was primarily due to an increase of $13.5 million in Colombia related to increased production volumes, OTA pipeline oil transportation costs recorded as operating costs versus as a reduction of revenue effective February 1, 2012, pursuant to a change in the sales point on that date, and increased G&A allocations to operating costs.

DD&A expenses for the three months ended March 31, 2013, decreased to $58.4 million from $60.4 million in 2012. The impact of increased production was more than offset by the absence of impairment charges. DD&A expenses for the three months ended March 31, 2012, included a $20.2 million ceiling test impairment in our Brazil cost center related to seismic and drilling costs on Block BM-CAL-10. On a per BOE basis, the depletion rate decreased by 30% to $27.71 from $39.62. The decrease was mainly due to the Brazil impairment charge of $13.26 per BOE in 2012. Increased costs in the depletable base were partially offset by increased reserves.

G&A expenses for the three months ended March 31, 2013, of $11.4 million decreased by 28% from $15.9 million in 2012. Increased employee related costs reflecting expanded operations were more than offset by increased recoveries and higher G&A allocations to operating expenses and capital projects in all business units. G&A expenses per BOE in the three months ended March 31, 2013, of $5.42 were 48% lower compared with $10.44 in 2012 due to increased production and increased recoveries and higher G&A allocations in Colombia.

For the three months ended March 31, 2013, the foreign exchange gain was $5.2 million, comprising a $6.7 million unrealized non-cash foreign exchange gain, offset by realized foreign exchange losses of $1.5 million. The foreign exchange gain was a result of a net monetary liability position in Colombia combined with the weakening of the Colombian Peso; whereas, the foreign exchange losses resulted from a net monetary asset position in Argentina and the weakening of the Argentina Peso. For the three months ended March 31, 2012, there was a foreign exchange loss of $24.4 million, of which $21.4 million was an unrealized non-cash foreign exchange loss, as a result of a net monetary liability position in Colombia combined with the strengthening of the Colombian Peso.

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

Income tax expense was $37.4 million for the three months ended March 31, 2013, compared with $31.1 million in the comparable period in 2012. The increase was primarily due to higher income before tax. The effective tax rate was 39% in the three months ended March 31, 2013, compared with 101% in the comparable period in 2012. The change in the effective tax rate from the comparable period in 2012 was primarily due to a decrease in non-deductible foreign currency translation adjustments and a decrease in the valuation allowance, partially offset by an increase in non-deductible royalty payments.

For 2013, the differential between the effective tax rate of 39% and the 35% U.S. statutory rate was primarily attributable to
non-deductible third party royalty in Colombia, the change in valuation allowance, non-deductible foreign currency translation adjustments, and the foreign tax rate differential. The variance from the 35% U.S. statutory rate for 2012 was primarily attributable to the valuation allowance and non-deductible foreign currency translation adjustments.



27



2013 Work Program and Capital Expenditure Program
 
Our 2013 capital program has been revised to $424 million from $363 million. This includes: $223 million for Colombia; $77 million for Brazil; $20 million for Argentina; $101 million for Peru; and $3 million associated with corporate activities. The majority of the increase is associated with capital spending in Peru and relates to the Bretaña Norte 95-2-1XD sidetrack well and additional 2-D seismic. The capital spending program allocates $218 million for drilling, $73 million for facilities, pipelines and other; $130 million for G&G expenditures; and $3 million for corporate activities. Of the $218 million allocated to drilling, approximately $100 million is for exploration and the balance is for appraisal and development drilling.

Our 2013 work program is intended to create both growth and value by developing existing assets to increase reserves and
production levels, the construction of pipelines and facilities in the areas with proved reserves, and maturing our exploration prospects through seismic acquisition and drilling. We are financing our capital program through cash flows from operations, cash on hand and potential periodic draws from our revolving credit facility, while retaining financial flexibility to undertake further development opportunities and pursue acquisitions. However, as a result of the nature of the oil and natural gas exploration, development and exploitation industry, we regularly review our budgets with respect to both the success of expenditures and other opportunities that become available. Accordingly, while we currently intend that funds be expended as set forth in our 2013 work program, there may be circumstances where, for sound business reasons, actual expenditures may in fact differ.



28



Segmented Results – Colombia

 
 
Three Months Ended March 31,
 
 
2013
 
2012
 
% Change
(Thousands of U.S. Dollars)
 
 
 
 
 
 
Oil and natural gas sales
 
$
180,003

 
$
138,633

 
30

Interest income
 
161

 
204

 
(21
)
 
 
180,164


138,837

 
30

 
 
 
 
 
 
 
Operating expenses
 
29,952

 
16,474

 
82

DD&A expenses
 
45,956

 
32,286

 
42

G&A expenses
 
4,636

 
6,599

 
(30
)
Foreign exchange (gain) loss
 
(6,448
)
 
23,358

 
(128
)
Other loss
 
4,400

 

 

 
 
78,496

 
78,717

 

 
 
 
 
 
 
 
Income before income taxes
 
$
101,668

 
$
60,120

 
69

 
 
 
 
 
 
 
Production
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil and NGL's, bbl
 
1,746,326

 
1,249,581

 
40

Natural gas, Mcf
 

 
9,474

 
(100
)
Total production, BOE (1)
 
1,746,326

 
1,251,160

 
40

 
 
 
 
 
 
 
Average Prices
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil and NGL's per bbl
 
$
103.08

 
$
110.92

 
(7
)
Natural gas per Mcf
 
$

 
$
3.39

 
(100
)
 
 
 
 
 
 
 
Segmented Results of Operations per BOE
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas sales
 
$
103.08

 
$
110.80

 
(7
)
Interest income
 
0.09

 
0.16

 
(44
)
 
 
103.17

 
110.96

 
(7
)
 
 
 
 
 
 
 
Operating expenses
 
17.15

 
13.17

 
30

DD&A expenses
 
26.32

 
25.80

 
2

G&A expenses
 
2.65

 
5.27

 
(50
)
Foreign exchange (gain) loss
 
(3.69
)
 
18.67

 
(120
)
Other loss
 
2.52

 

 

 
 
44.95

 
62.91


(29
)
 
 
 
 
 
 
 
Income before income taxes
 
$
58.22

 
$
48.05

 
21

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

For the three months ended March 31, 2013, income before income taxes was $101.7 million compared with $60.1 million in 2012. The increase was due to higher oil and natural gas sales as a result of increased Production, decreased G&A expenses and a foreign exchange gain, partially offset by increased operating and DD&A expenses and other loss.


29



Oil and NGL Production for the three months ended March 31, 2013, increased to 1.7 MMbbl compared with 1.2 MMbbl for 2012 due to the reduced impact of pipeline disruptions, a decrease in oil inventory as previously discussed and increased production from new wells in the Costayaco and Moqueta fields in the Chaza Block. The net inventory reduction accounted for 0.1 MMbl or 1,554 BOEPD of the reported increase in production. Production during the three months ended March 31, 2013, reflected approximately 44 days of oil delivery restrictions in Colombia compared with 26 days of oil delivery restrictions in the comparable period in 2012. In 2013, the impact of OTA pipeline disruptions on production was mitigated by selling a portion of our oil through trucking and an alternative pipeline.

On February 1, 2012, the sales point for the majority of our oil sales in the Putumayo Basin changed. Ecopetrol now takes title at the Port of Tumaco on the Pacific coast of Colombia rather than at the entry into the OTA pipeline. As a result, our reported oil inventory increased during the first quarter of 2012, representing ownership of oil in the OTA pipeline and associated Ecopetrol owned facilities. The impact of the inventory increase on production in the first quarter of 2012 was a negative effect on production of 1,040 BOPD.

Revenue and other income increased by 30% to $180.2 million for the three months ended March 31, 2013, compared with $138.8 million in 2012.

For the three months ended March 31, 2013, the average realized price per bbl for oil decreased by 7% to $103.08 compared with $110.92 in 2012. Average Brent oil prices for the three months ended March 31, 2013, were $112.51 per bbl compared with $118.56 per bbl in 2012.

During the three months ended March 31, 2013, 28% of our oil and gas sales were to a customer to whom oil is delivered at the Costayaco battery and the sales point is where the oil is loaded into a truck at our loading facility. This oil is then trucked from the Costayaco field to the Atlántico Oil Terminal in Barranquilla, a distance of approximately 1,500 kilometers. Oil prices for sales to this customer are based on average WTI prices plus a Vasconia differential and premium, adjusted for trucking costs. The effect on the Colombian realized price was a reduction of approximately $5.10 per BOE as compared to delivering all of our Colombian oil through the OTA pipeline.

Until February 1, 2012, OTA transportation costs were factored into the price we received for oil sales in the Putumayo Basin to Ecopetrol, but, due to the change in sales point noted above, these costs are now invoiced separately and included in operating costs. This change resulted in a related increase in the average realized price per bbl starting February 1, 2012.

Operating expenses increased by 82% to $30.0 million for the three months ended March 31, 2013, from $16.5 million in 2012. On a per BOE basis, operating expenses increased by 30% to $17.15 for the three months ended March 31, 2013, from $13.17 in 2012. Operating expenses per BOE increased in 2013 primarily due to OTA pipeline oil transportation costs now recorded as operating costs, increased G&A allocations to operating costs and new wells with higher operating costs. The estimated net effect of OTA pipeline disruptions on Colombian transportation costs for the three months ended March 31, 2013 was neutral, with the increased trucking costs to an alternative pipeline offset by the absence of OTA pipeline charges relating to both these volumes and the volumes sold at the Costayaco battery. The trucking costs associated with the volumes sold at the Costayaco battery were a reduction of the realized price rather than recorded as transportation expenses and the effect on the realized price is as quantified above. Workover costs decreased by $0.42 per BOE compared with the comparable period in 2012. In 2013 and 2012, we performed workovers in the Costayaco and Juanambu fields and, in 2013, the Moqueta field.
 
DD&A expenses increased by 42% to $46.0 million for the three months ended March 31, 2013, from $32.3 million in 2012. On a per BOE basis, DD&A expenses increased by 2% to $26.32 for the three months ended March 31, 2013. The increase was due to increased costs in the depletable base being partially offset by increased reserves.

For the three months ended March 31, 2013, G&A expenses decreased by 30% to $4.6 million ($2.65 per BOE) from $6.6 million ($5.27 per BOE) in 2012 due to increased recoveries and G&A allocations to operating costs and capital projects, partially offset by increased salaries expense due to an increased headcount from expanded operations.

For the three months ended March 31, 2013, the foreign exchange gain was $6.4 million, which included a $6.7 million unrealized non-cash foreign exchange gain. In the three months ended March 31, 2012, we incurred a foreign exchange loss of $23.4 million, of which $21.4 million was an unrealized non-cash foreign exchange loss. The Colombian Peso weakened by 3% and strengthened by 8% against the U.S. dollar in the three months ended March 31, 2013 and 2012, respectively. Under GAAP, deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation is the main source of the unrealized foreign exchange losses or gains.


30



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

Capital Program - Colombia
 
Capital expenditures in our Colombian segment during the three months ended March 31, 2013, were $30.4 million. The following table provides a breakdown of capital expenditures in the three months ended March 31, 2013 and 2012:

 
 
Three Months Ended March 31,
(Millions of U.S. Dollars)
 
2013
 
2012
Drilling and completions
 
$
14.9

 
$
10.5

G&G
 
5.3

 
7.1

Facilities and equipment
 
6.2

 
1.8

Other
 
4.0

 
0.9

 
 
$
30.4

 
$
20.3


The significant elements of our first quarter 2013 capital program in Colombia were:

On the Chaza Block (100% working interest ("WI"), operated), we completed the Moqueta-8 development well as a producing well and drilled the Moqueta-9D development well in the Moqueta field. Testing of the Moqueta-9D development well is ongoing. On the Costayaco field, we continued completion work at the Costayaco-17 water injector well and commenced drilling the Costayaco-18D development well.
We commenced civil construction for one gross exploration well on the Guayuyaco Block (70% WI, operated).
We acquired 3-D seismic on the Garibay Block (50% WI, non-operated) and started acquiring 2-D seismic on the Magdalena Block (100% WI, operated).
We also continued facilities work at the Costayaco and Moqueta fields on the Chaza Block, the Llanos-22 Block (45% WI, non-operated) and the Guayuyaco Block.
Outlook - Colombia

The 2013 capital program in Colombia is $223 million with $109 million allocated to drilling, $48 million to facilities and pipelines and $66 million for G&G expenditures.

Our planned work program for the remainder of 2013 in Colombia includes drilling one oil exploration well on each of the Chaza and Putumayo-1 Blocks (100 % WI, operated) and two gross exploration wells on the Guayuyaco Block. We plan to finish the completion of the Costayaco-17 water injector well and complete drilling the Costayaco-18D development wells on the Chaza Block and drill two additional gross development wells on the Moqueta field of the Chaza Block, a development well on the Llanos-22 Block and convert an existing well on the Garibay Block to a water injector well.

We also plan to acquire 2-D seismic on the Cauca-7 (100% WI, operated), Putumayo-10 (100% WI, operated), Magdalena, Piedemonte Norte (70% WI, operated) and Piedemonte Sur (100% WI, operated) Blocks and 3-D seismic on the Putumayo-1 Block. Facilities work is also planned for the Chaza, Garibay and the Llanos-22 Blocks.


Segmented Results – Argentina
 

31



 
Three Months Ended March 31,
 
2013
 
2012
 
% Change
(Thousands of U.S. Dollars)
 
 
 
 
 
Oil and natural gas sales
$
18,540

 
$
15,369

 
21

Interest income
243

 
47

 
417

 
18,783

 
15,416

 
22

 
 
 
 
 
 
Operating expenses
8,971

 
7,346

 
22

DD&A expenses
7,950

 
5,925

 
34

G&A expenses
2,374

 
2,251

 
5

Foreign exchange loss
1,124

 
371

 
203

 
20,419

 
15,893

 
28

 
 
 
 
 
 
Loss before income taxes
$
(1,636
)
 
$
(477
)
 
243

 
 
 
 
 
 
Production
 
 
 
 
 
 
 
 
 
 
 
Oil and NGL's, bbl
242,577

 
199,300

 
22

Natural gas, Mcf
332,613

 
363,473

 
(8
)
Total production, BOE (1)
298,013

 
259,879

 
15