GRAN TIERRA ENERGY INC. - FORM 8-K/A - EX-99.1

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8-K/A - GRAN TIERRA ENERGY INC.	v224796_8ka.htm
EX-99.2 - GRAN TIERRA ENERGY INC.	v224796_ex99-2.htm
EX-23.1 - GRAN TIERRA ENERGY INC.	v224796_ex23-1.htm

Exhibit 99.1

INDEPENDENT AUDITOR’S REPORT

To the Shareholders of Petrolifera Petroleum Limited:

We have audited the accompanying consolidated financial statements of Petrolifera Petroleum Limited, which comprise the consolidated balance sheets as at December 31, 2010 and 2009, and the consolidated statements of operations and retained earnings, comprehensive loss, accumulated other comprehensive income (loss) and cash flows for the years then ended, and the notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Petrolifera Petroleum Limited as at December 31, 2010 and 2009 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

/s/ DELOITTE & TOUCHE LLP

Independent Registered Chartered Accountants

Calgary, Alberta

March 9, 2011 (except for Note 15, which is as of June 2, 2011)

PETROLIFERA PETROLEUM LIMITED

CONSOLIDATED BALANCE SHEETS

As at December 31	2010			2009
($000)
ASSETS
Current
Cash	$	11,046		$	35,732
Accounts receivable		25,667			20,871
Restricted cash		1,502			3,247
Inventory (Note 3)		937			958
Financial instrument - debt agreement option (Note 6)		4,817			-
Income taxes receivable		2,163			4,636
Prepaid expenses		296			464
Deferred financing costs		-			706
		46,428			66,614
Long-term investments (Note 6)		18,670			19,395
Properties and equipment (Note 4)		263,969			263,056
	$	329,067		$	349,065
LIABILITIES
Current
Accounts payable and accrued liabilities	$	12,439		$	15,850
Income taxes payable		1,026			913
Bank debt (Note 5)		19,879			52,330
Due to a related company (Note 7)		46			29
		33,390			69,122
Long-term bank debt (Note 5)		36,589			27,464
Asset retirement obligations (Note 8)		9,952			9,552
Future income taxes (Note 9)		10,027			10,801
		89,958			116,939
SHAREHOLDERS’ EQUITY
Share capital and warrants (Note 10(a))		167,210			148,264
Contributed surplus (Note 10(f))		23,146			20,453
Accumulated other comprehensive loss		(8,817	)		(3,753	)
Retained earnings		57,570			67,162
		239,109			232,126
	$	329,067		$	349,065

Commitments and guarantees (Note 13)

Subsequent events (Note 14)

PETROLIFERA PETROLEUM LIMITED

CONSOLIDATED STATEMENTS OF

OPERATIONS AND RETAINED EARNINGS

Years Ended December 31	2010			2009
$000 (except per share amounts)
REVENUE
Petroleum and natural gas	$	63,090		$	83,752
Interest and other income		265			39
		63,355			83,791
Royalties		(9,053	)		(12,017	)
		54,302			71,774
EXPENSES
Operating		21,046			22,930
General and administrative		7,769			8,285
Finance charges (Note 5)		4,204			5,097
Taxes other than income taxes		1,466			1,874
Foreign exchange loss		834			115
Depletion, depreciation and accretion (Note 4)		28,951			33,546
Fair value impairment (increase) (Note 6)		(4,817	)		2,104
Stock-based compensation (Note 10(e))		2,695			4,674
		62,148			78,625
Loss before income taxes		(7,846	)		(6,851	)

Current income tax provision (Note 9)		1,933			3,362
Future income tax provision (recovery) (Note 9)		(187	)		612
		1,746			3,974
NET LOSS		(9,592	)		(10,825	)

RETAINED EARNINGS, BEGINNING OF YEAR		67,162			77,987

RETAINED EARNINGS, END OF YEAR	$	57,570		$	67,162
NET LOSS PER SHARE (NOTE 12(A))
Basic and diluted	$	(0.07	)	$	(0.14	)

PETROLIFERA PETROLEUM LIMITED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

Years Ended December 31	2010			2009
($000)
Net loss	$	(9,592	)	$	(10,825	)
Foreign currency translation adjustment		(5,064	)		(19,859	)
Comprehensive loss	$	(14,656	)	$	(30,684	)

CONSOLIDATED STATEMENTS OF ACCUMULATED

OTHER COMPREHENSIVE INCOME (LOSS)

Years Ended December 31	2010			2009
($000)
Accumulated other comprehensive income (loss), beginning of year	$	(3,753	)	$	16,106
Foreign currency translation adjustment		(5,064	)		(19,859	)
Accumulated other comprehensive loss, end of year	$	(8,817	)	$	(3,753	)

PETROLIFERA PETROLEUM LIMITED

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31	2010			2009
($000)
Cash provided by (used in) the following activities:
OPERATING
Net loss	$	(9,592	)	$	(10,825	)
Items not involving cash:
Depletion, depreciation and accretion (Note 4)		28,951			33,546
Fair value impairment (increase) (Note 6)		(4,817	)		2,104
Amortization of deferred & other charges		2,890			868
Stock-based compensation (Note 10(e))		2,695			4,674
Unrealized foreign exchange loss		912			1,428
Future income tax provision (recovery) (Note 9)		(187	)		612
Cash flow from operations before non-cash working capital changes		20,852			32,407
Changes in non-cash working capital (Note 12(b))		(658	)		8,989
		20,194			41,396
FINANCING
Issue of common shares and common share purchase warrants (Note 10(a))		20,148			58,768
Repayment of bank debt and long-term bank debt		(19,897	)		(21,938	)
Deferred financing costs		(2,078	)		-
Share issue costs (Note 10(b))		(1,254	)		(3,060	)
Proceeds of bank debt or long-term bank debt		-			19,896
		(3,081	)		53,666
INVESTING
Exploration and development of petroleum and natural gas properties		(50,506	)		(71,623	)
Proceeds from farmout and property sale agreements (Note 4)		13,817			2,767
Proceeds from restricted cash		2,475			2,965
Investment in restricted cash		(158	)		(4,674	)
Receipt of interest and capital recoveries on long-term investment (Note 6)		19			1,789
Changes in non-cash working capital (Note 12(b))		(7,198	)		(14,158	)
		(41,551	)		(82,934	)
INCREASE (DECREASE) IN CASH		(24,438	)		12,128
Impact of foreign exchange on foreign currency denominated cash balances		(248	)		(7,097	)
CASH, BEGINNING OF YEAR		35,732			30,701
CASH, END OF YEAR	$	11,046		$	35,732

Supplementary cash flow information (Note 12(c))

PETROLIFERA PETROLEUM LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2010

1. FINANCIAL STATEMENT PRESENTATION

The financial statements include the accounts of Petrolifera Petroleum Limited and its wholly-owned subsidiaries and foreign branches (collectively “Petrolifera” or the “company”) and are presented in accordance with Canadian generally accepted accounting principles in Canadian dollars, unless otherwise noted. Petrolifera is engaged in petroleum and natural gas exploration, development and production activities in South America.

2. SIGNIFICANT ACCOUNTING POLICIES

Inventory

Crude oil inventory is measured at the lower of cost (on a weighted average cost basis) and net realizable value.

Income taxes

The company follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributed to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs. Future tax assets are assessed by management at each balance sheet date and recognized when realization is more likely than not.

Petroleum and natural gas operations

The company follows the full cost method of accounting whereby all costs relating to the exploration for and development of petroleum and natural gas reserves are capitalized on a country by country cost centre basis.

Capitalized costs of petroleum and natural gas properties and related equipment within a cost centre are depleted and depreciated using the unit-of-production method based on estimated proved petroleum and natural gas reserves, as determined by independent consulting engineers. For the purpose of this calculation, production and reserves of natural gas are converted to equivalent units of crude oil based on relative energy content (6:1).

The company applies, at least annually, a “ceiling test” to the net book value of petroleum and natural gas properties for each cost centre to determine if an impairment loss should be recognized when the carrying value of each cost centre is not recoverable and exceeds its fair value. The carrying value is assessed to be recoverable when the sum of each cost centre’s undiscounted cash flows expected from the production of proved reserves exceeds its carrying value less impairment, unproved properties and major development project costs. If the carrying value is assessed to not be recoverable, the calculation then compares each cost centre’s carrying value less impairment, unproved properties and major development project costs to the sum of the discounted cash flows expected from the production of proved and probable reserves. Should the carrying value exceed this sum, an impairment loss is recognized. The cash flows are estimated using projected future commodity prices and costs and are discounted using a risk-free interest rate.

Costs of acquiring and evaluating unproved properties and major development projects are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves are attributable to the properties, the project becomes commercial, or impairment occurs. These costs are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to losses.

Gains or losses on sales of properties are recognized only when crediting the proceeds to cost would result in a change of 20 percent or more in the depletion rate.

Asset retirement obligations

The company provides for the costs of retirement obligations associated with long-lived assets, including the abandonment of petroleum and natural gas wells, related facilities, compressors and gas plants and the removal of equipment from leased acreage. The estimated fair value of each asset retirement obligation is recorded in the period a well or related asset is drilled and evaluated, constructed or acquired. Fair value is estimated using the present value of the estimated future cash outflows, as adjusted for the expected inflation rate, to abandon such assets using the company’s credit adjusted risk-free interest rate. The obligation is reviewed regularly by management based upon current regulations, costs, technologies and industry standards. The discounted, recognized obligation is initially capitalized as part of the carrying amount of the related petroleum and natural gas properties. The liability is accreted to losses, as included as a component of depletion and depreciation expense, until it is settled or the property is sold. The increase in petroleum and natural gas properties is depleted on the same basis as the remainder of the petroleum and natural gas properties. Actual restoration expenditures are charged against the accumulated obligation as incurred.

Revenue recognition

Crude oil, natural gas liquids and natural gas sales are recognized as revenue when the respective commodities are delivered to purchasers at the point of sale.

Stock-based compensation

The company uses the fair value method for valuing stock option grants. Compensation costs attributed to share options granted are measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon exercise of the stock options, consideration paid by the option holder together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.

Financial instruments

Financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods depends on the following financial instruments classification:

(a) Held-for-trading financial instruments are subsequently measured at fair value with changes in those fair values chargedimmediately to losses.

(b) Other financial liabilities are subsequently measured at amortized cost using the effective interest method. The company does not have available for sale financial assets.

The company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange and interest rates in the normal course of operations. The company has not entered into any financial derivative contracts to reduce its exposure to fluctuations in market risks, does not enter into these contacts for speculative purposes and has not recorded any assets or liabilities as a result of embedded derivatives.

Measurement uncertainty

The timely preparation of the Consolidated Financial Statements in conformity with Canadian generally accepted accounting principles requires that management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depreciation, depletion and accretion, amounts used for the ceiling test and impairment calculations and amounts used in the determination of the future tax liability are based, in part, on estimates of petroleum and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs and the related future cash flows are subject to measurement uncertainty. Long-term investments and the debt agreement option fair valuations are based on probabilistic valuation models. Asset retirement obligations are based, in part, on estimates of future costs to settle the obligation, in addition to estimates of the useful lives of the underlying assets, the rate of inflation and the credit adjusted risk-free interest rate. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are accrued and eventually charged to losses only when management is able to determine the amount and the likelihood of the future obligation. Stock-based compensation is based upon volatility, expected lives and risk-free interest rates. Actual results could differ materially from estimated amounts.

Per share amounts

Basic per share amounts are calculated using the weighted average number of common shares outstanding for the period. The company follows the treasury stock method to calculate diluted per share amounts. The treasury stock method assumes that any proceeds from the exercise of in-the-money share options and share purchase warrants, in addition to the fair value of granted options not yet recognized as stock-based compensation, would be used to purchase common shares at the average market price during the period.

Foreign currency translation

Colombia, Peru, Barbados and the US subsidiaries are considered to be “integrated foreign operations” for accounting purposes and, therefore, these foreign operations’ financial statements are translated into Canadian dollars using the temporal method. Under the temporal method, the company translates foreign denominated monetary assets and liabilities at the exchange rate prevailing at year-end; non-monetary assets, liabilities and related depletion, depreciation and accretion are translated at historic rates; revenues and expenses are translated at the average rate of exchange for the period; and any resulting foreign exchange gains or losses are included in the net loss as shown in the Consolidated Statements of Operations and Retained Earnings.

As a “self-sustaining foreign operation”, the Argentinean financial statements are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate of exchange in effect at the balance sheet date; revenues and expenses are translated at the average monthly rates of exchange during the period; and gains or losses on translation are included as a foreign currency translation adjustment in the Consolidated Statements of Comprehensive Losses and Accumulated Other Comprehensive Income (Loss).

Impact of New Accounting Standards

In January 2009, the CICA issued section 1582, “Business Combinations”, which replaces CICA section 1581 of the same name. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. The new guidance will require all costs of the acquisition to be expensed, which currently are capitalized as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and re- measured at fair value through earnings until settled. Currently only contingent liabilities that are resolved and payable are included in the cost to acquire the enterprise. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation. Section 1582 is effective on January 1, 2011, with prospective application, and early adoption is permitted. To date, the adoption of this standard has not impacted the company’s Consolidated Financial Statements as the company has not acquired a business.

In January 2009, the CICA issued section 1601, “Consolidated Financial Statements”, which will replace CICA section 1600 of the same name. This guidance requires consistent application of accounting policies throughout all consolidated entities. Section 1601 is effective on January 1, 2011, with prospective application, and early adoption is permitted. The adoption of this standard will have no impact on the company’s Consolidated Financial Statements as the company had previously applied consistent application of accounting policies throughout its branches and subsidiaries.

In January 2009, the CICA issued section 1602, “Non-controlling Interests”, which will replace CICA section 1600, “Consolidated Financial Statements”. This standard establishes the accounting for a non-controlling interest in a subsidiary in the Consolidated Financial Statements subsequent to a business combination. This standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net losses and components of other comprehensive losses are attributed to both the parent and non-controlling interest. Section 1602 is effective on January 1, 2011, with prospective application, and early adoption is permitted. To date, the adoption of this standard has not impacted the company as there are no non-controlling interests of its subsidiaries.

3. INVENTORY

As at December 31	2010		2009
($000)
Crude oil	$	937	$	958

The company maintains inventory as a consequence of the sales process for crude oil which has been produced and not delivered to customers for periods of up to several days, during which time it must be held in storage at the company’s facilities and in transportation pipelines. Crude oil inventory was measured at December 31, 2010 and 2009 using a weighted average cost basis and is carried at the lower of cost and net realizable value.

4. PROPERTIES AND EQUIPMENT

			Accumulated
			Depletion and
($000)	Cost		Depreciation			Net Book Value
As at December 31, 2010
Petroleum and natural gas properties and equipment	$	368,861	$	(105,990	)	$	262,871
Furniture, equipment and leaseholds		2,590		(1,492	)		1,098
	$	371,451	$	(107,482	)	$	263,969
As at December 31, 2009
Petroleum and natural gas properties and equipment	$	345,119	$	(83,294	)	$	261,825
Furniture, equipment and leaseholds		2,149		(918	)		1,231
	$	347,268	$	(84,212	)	$	263,056

Included in the cost of petroleum and natural gas properties and equipment are estimated future asset retirement costs of $8.4 million (2009 - $8.5 million). In 2010, the company capitalized $5.3 million (2009 - $4.7 million) of general and administrative expenses related to exploration and development activities.

Depletion, depreciation and accretion expense includes a charge of $0.6 million (2009 - $0.6 million) to accrete the company’s estimated asset retirement obligations (Note 8).

In December 2010, the company entered into a purchase and sale agreement (“Purchase and Sale Agreement”) with Gran Tierra Energy Colombia Ltd. (“Gran Tierra Energy Colombia”), a wholly-owned subsidiary of Gran Tierra Energy Inc. (“Gran Tierra Energy”), to sell a 25 percent working interest in the company’s Sierra Nevada License in Colombia in consideration for cash of US$10.0 million. If the Agencia Nacional de Hidrocarburos (“ANH”), does not acknowledge Gran Tierra Energy Colombia’s working interest, through a written resolution, within 180 days after all required documentation is submitted, either the company or Gran Tierra Energy Colombia may terminate the Purchase and Sale Agreement, unless this condition is waived by both parties.

During 2010, the company received cash proceeds of $3.7 million on the company’s Vaca Mahuida, Argentinean exploratory property from third parties, which was recognized as a recovery of property costs from the company’s Argentinean full cost pool, in addition to being reimbursed for all incurred expenditures in consideration for a 75 percent working interest in the aforementioned proved property.

During 2009, the company received cash proceeds of $2.8 million and a commitment to spend an additional US$1.9 million on the company’s Turpial Colombian unproven property from a third party in consideration for a 50 percent working interest in the aforementioned property. A portion of the $2.8 million in cash proceeds was recognized as a recovery of unproven properties cost from the company’s Colombian full cost pool.

Capital costs of $5.9 million (2009 - $14.0 million) incurred for an unproven property and other assets in Argentina and $57.9 million (2009 - $56.1 million) and $77.3 million (2009 - $47.5 million) for major development projects, unproved properties and other assets in a pre-production stage located in Peru and Colombia, respectively, have been excluded from the calculation of depletion expense. These costs have been separately evaluated by management for impairment. No impairment has been recorded at December 31, 2010 or 2009.

Petrolifera’s petroleum and natural gas reserves, as used in the ceiling test, were evaluated by independent reservoir engineers as at December 31, 2010 in a report dated March 4, 2011. The evaluation was conducted in accordance with Canadian Securities Administrators’ National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook, using the following price assumptions for Argentina and Colombia:

	Argentina				Colombia
	Crude Oil Price ($/bbl)		Natural Gas Price ($/mcf)		Crude Oil Price ($/bbl)		Natural Gas Price ($/mcf)
2011		61.22		2.58		89.90		2.04
2012		62.45		2.70		90.82		2.08
2013		63.70		2.76		91.84		2.12
2014		64.97		2.81		93.88		2.17
	+ approximately 2%		+ approximately 2%		+ approximately 2%		+ approximately 2%
	thereafter		thereafter		thereafter		thereafter

5. BANK DEBT AND LONG-TERM BANK DEBT

As at	Dec. 31, 2010			Dec. 31, 2009
($000)
Current bank debt
Reserve-backed credit facility	$	14,919		$	52,330
Second ABCP line-of-credit		4,960			-
	$	19,879		$	52,330
Long-term bank debt
Reserve-backed credit facility	$	15,665		$	-
ABCP line-of-credit		22,496			27,464
Deferred financing costs		(1,572	)		-
	$	36,589		$	27,464
Total bank debt
Reserve-backed credit facility	$	30,584		$	52,330
Combined ABCP line-of-credit facilities		27,456			27,464
Deferred financing costs		(1,572	)		-
	$	56,468		$	79,794

In 2007, the company entered into a US$100.0 million reserve-backed credit facility with availability as at December 31, 2010 of US$30.8 million. In August 2010, the company signed a revised reserve-backed credit facility (“Revised Credit Facility”) agreement with a syndicate of banks, which expires on June 30, 2012. In August 2010, the company made a one-time payment of US$11.7 million prior to signing the Revised Credit Facility agreement and subsequent thereto, made two quarterly permanent debt repayments totaling US$7.5 million. These payments had the effect of reducing the availability under the facility from US$50.0 million as at December 31, 2009 to US$30.8 million as at December 31, 2010. The company agreed to make scheduled permanent debt repayments of US$3.8 million per quarter through to expiry of the Revised Credit Facility agreement in June 2012, at which time all borrowings under this Revised Credit Facility will be due and payable. Under the terms of the Revised Credit Facility agreement, one-half of any potential farmout proceeds received by the company up to a maximum of US$5.0 million are to be first allocated to reduce the final US$12.0 million permanent debt repayment as due and payable upon expiry of the revised agreement in June 2012 with any excess farmout proceeds to then be evenly allocated to reduce the company’s quarterly debt repayments. The Revised Credit Facility bears interest at LIBOR plus a margin, is partially secured by the pledge of the shares of Petrolifera’s subsidiaries and has a provision for a borrowing base adjustment every six months, with the next adjustment, which is in progress, to be calculated based on information as at June 30, 2010.

As at December 31, 2010, the outstanding Revised Credit Facility was $30.6 million (US$30.8 million) less approximately $1.6 million in deferred financing costs, which were recognized on the Revised Credit Facility agreement and are being amortized through to expiry of the facility in June 2012. As the terms of the Revised Credit Facility agreement were substantially changed, $0.7 million of deferred financing costs related to the previous agreement were amortized during the year. For 2010, total deferred financing costs amortization is $1.1 million (2009 - $0.9 million).

During 2009, the company secured from a Canadian chartered bank an expansion of its Asset Backed Commercial Paper (“ABCP”) line-of-credit (“ABCP line-of-credit”), to a maximum of $23.2 million, with an initial expiry in April 2012. The company can make up to four extension requests, with each extension for an additional one-year period. Of this line-of-credit, a maximum of $13.9 million is secured by the eligible master asset vehicles Classes A1 through C (“MAV A1 to C”) notes as received by the company in exchange for a portion of the long term notes formerly known as ABCP, whereas a maximum of $9.3 million is unsecured under the existing terms of this ABCP line-of-credit. The ABCP line-of-credit bears interest at a floating rate. The company has classified as long-term bank debt the $22.5 million in borrowings under this facility as at December 31, 2010 and 2009.

The company also has a second line-of-credit agreement (“Second ABCP line-of-credit”) with the same Canadian chartered bank to a maximum of $5.0 million, which was fully drawn as at December 31, 2010 and 2009. This Second ABCP line-of-credit, which expires on April 8, 2011, is secured by the ineligible master asset vehicles Classes 1 & 2 (“MAV IA 1 & 2”) notes received by the company in 2009, in exchange for a portion of the ABCP. During 2010, the company advised its lender it will exercise its option to deliver to the lender the MAV IA 1 & 2 notes, which at the time of acquisition in 2007 had a face value of $6.6 million but through subsequent impairment provisions had no carrying value in the company’s accounts, as at December 31, 2010 and 2009. As the company has the option to settle its $5.0 million in borrowings as drawn on this Second ABCP line-of-credit agreement through delivery to its lender of the MAV IA 1 & 2 notes, the company advised its lender that it intends to settle such borrowings with the MAV IA 1 & 2 notes and accordingly, the company has classified the $5.0 million in borrowings as at December 31, 2010 made under this facility as a current liability. At December 31, 2009 this amount of $5.0 million was classified as long-term bank debt.

Interest expense on the facilities for 2010 was $3.0 million (2009 - $4.2 million). These amounts are disclosed on the Consolidated Statements of Operations and Retained Earnings as finance charges which also include the amortization of deferred finance charges, debt facilities administration fees and vendor interest charges. The combined effective interest rate on the company’s facilities was 4.1 percent for 2010 (2009 - 4.2 percent). The unused credit on the ABCP line-of-credit facility, as primarily secured by the ABCP, was $0.7 million as at December 31, 2010 and 2009.

6. FINANCIAL INSTRUMENTS

Summary

The company is exposed to various risks that arise from its business environment and the financial instruments it holds. The Audit Committee of the Board of Directors assists the Board in the discharge of its responsibility for overseeing the process that management has in place to identify, assess and manage financial risks. The following outlines the company’s risk exposures, quantifies these risks, and explains how these risks and its capital structure are managed.

Capital management

The company’s objective is to maintain a strong capital position in order to execute its business plans and maximize value to shareholders. The company defines its capital as shareholders’ equity, bank debt and long-term bank debt. Changes to the relative weighting of the capital structure is driven by the company’s business plans, changes in economic conditions and risks inherent in the global petroleum and natural gas industry. Although during the year ended December 31, 2010, there were changes in the relative weighting of capital, there have been no material changes to the company’s processes and objectives related to capital management compared to prior periods. Methods to adjust the company’s capital structure could include any or all of the following activities:

•	Repurchase shares pursuant to a normal course issuer bid;

•	Issue new shares through a public offering or private placement, such as occurred in the second quarter of 2010 and the third quarter of 2009 (Note 10(b));

•	Raise fixed or floating rate debt; and

•	Refinance existing debt facilities to change amounts or terms (Note 5).

The company periodically reviews certain quantitative measures of its capital structure, in order to understand its position relative to industry peers. These measures include calculations such as return on equity, return on capital employed and the debt to equity ratio. The company does not set certain limits or ranges with respect to these quantitative measures.

The company is subject to external restrictions in its Revised Credit Facility. As at December 31, 2010, this facility was fully drawn and had an overall limit of US$30.8 million, based on producing petroleum and natural gas reserves as at December 31, 2009. This facility has a provision for a borrowing base adjustment every six months, with the next adjustment, which is in progress, to be calculated based on information as at June 30, 2010. The company’s financial covenants include a debt-to-EBITDA ratio whereby outstanding bank debt and long-term debt, as defined by the terms of the Revised Credit Facility to exclude amounts secured by the long term notes formerly known as ABCP, cannot exceed two and a half times (“2.5X”) the 12 month trailing EBITDA in addition to a minimum working capital ratio of 1.25:1.00. EBITDA is defined by the Revised Credit Facility agreement as net loss prior to deduction of interest, income taxes, depletion, depreciation and accretion expense, stock-based compensation, unrealized foreign exchange losses and any other non-cash expenses and is reconciled to the net loss as follows:

Year Ended December 31	2010
($000)
Net loss	$	(9,592	)
Add (deduct) Interest, income taxes, depletion, depreciation
and accretion expense and other non-cash expenses:
Depletion, depreciation, and accretion		28,951
Fair value increase		(4,817	)
Finance charges		4,204
Stock-based compensation		2,695
Income tax provision		1,746
Unrealized foreign exchange loss		912
EBITDA	$	24,099

As at December 31, 2010, relevant outstanding draws were $39.2 million and EBITDA was $24.1 million, for a debt-to-EBITDA financial covenant ratio of 1.6:1.0, which was in compliance with the 2.5X imposed limit.

Fair values of financial instruments

Financial instruments are recognized initially at fair value on the balance sheet and include cash, accounts receivable, restricted cash, debt agreement option, long-term investments, accounts payable and accrued liabilities, bank debt, due to a related company and long-term bank debt. The company has classified all of its financial instruments as held for trading, with the exception of the bank debt and long-term bank debt, which are classified as other liabilities. Held for trading instruments continue to be measured at fair value, while other liabilities are subsequently measured at amortized cost.

The fair value measurement of each of the company’s significant held for trading financial assets is summarized in the following fair value hierarchy table that reflects the lowest level input of significance as used in the measurement as the basis of the assigned level. The three levels of the fair value hierarchy are as follows:

•	Level 1 includes financial assets with fair value measurements based upon quoted prices (unadjusted) in active markets for identical assets.

•	Level 2 includes financial assets from inputs other than quoted prices included in Level 1 that are observable for the asset, either directly or indirectly.

•	Level 3 includes fair value measurements from inputs for the financial assets that are not based on observable market date.

As at December 31, 2010	Fair Value Hierarchy
($000)	Total		Level 1		Level 2		Level 3
Held for trading financial assets:
Cash	$	11,046	$	11,046	$	-	$	-
Accounts receivable		25,667		-		25,667		-
Restricted cash		1,502		-		1,502		-
Debt agreement option		4,817		-		-		4,817
Long-term investments		18,670		-		-		18,670
Total held for trading financial assets	$	61,702	$	11,046	$	27,169	$	23,487

As no active market exists for the company’s accounts receivable and restricted cash, these financial assets have been classified as Level 2. As at December 31, 2010, long-term investments is comprised of notes received in exchange for ABCP with a face value of $30.9 million (2009 - $34.6 million) and a carrying value of $18.7 million (2009 - $18.7 million). As at December 31, 2010, the debt agreement option represents the company’s option to settle $5.0 million in borrowings through the delivery of its MAV IA 1 & 2 notes. The fair and face values for the Level 3 financial assets is explained below.

During 2010, the company advised its lender that upon the expiry of the $5.0 million Second ABCP line-of-credit agreement, the company will deliver to the lender the MAV IA 1 & 2 notes that were issued to the company in 2009 in replacement for a portion of its investment in ABCP. The lender’s recourse on the company’s borrowings of $5.0 million is limited to the MAV IA 1 & 2 notes. As the company has the option to settle its $5.0 million in borrowings through delivery to its lender of the MAV IA 1 & 2 notes and has advised its lender that during the year ended December 31, 2010 it will settle the $5.0 million in borrowings through delivery of the MAV IA 1 & 2 notes, the company has recognized the fair value of the debt agreement option of $4.8 million as at December 31, 2010 using a probabilistic valuation model.

In January 2009, the Pan-Canadian Investors Committee for Third-Party Structured ABCP announced that the Superior Court of Ontario granted the Plan Implementation Order and that, accordingly, the plan for restructuring ABCP had been fully implemented. In exchange for the shorter-term ABCP, the company has now received the longer term notes with maturities that generally approximate those of the assets previously contained in the underlying conduits.

During 2010, the company was advised the ineligible master asset vehicle Class 1 (“MAV IA 1”) notes, with total pledged market collateral of $500.0 million, incurred several credit events within its market portfolio, resulting in losses greater than the pledged market collateral. The company had an investment in the MAV IA 1 notes with an original face value of $3.7 million and a carrying value as at December 31, 2009 of nil. The company has removed the MAV IA 1 notes from its reported portfolio of longer-term notes previously known as ABCP, thereby reducing the outstanding principal amount of its portfolio by $3.7 million for the year ended December 31, 2010.

During 2009, the company reported a $2.1 million fair value impairment on its MAV IA 1 and ineligible master asset vehicle Class 2 (“MAV IA 2”) notes, which when combined forms the MAV IA 1 & 2 notes as previously defined, that reduced the December 31, 2009 carrying value of its MAV IA 1 & 2 notes to nil. The recognition of the fair value impairment during 2009 was accompanied by the removal of the original face value of the MAV IA 2 notes of $2.9 million from the company’s reported portfolio of longer-term notes previously known as ABCP.

Despite the permanent impairment in the MAV IA 1 & 2 notes as at December 31, 2010, the company still retains the right, subject to the terms of the Second ABCP line-of-credit agreement between the company and its lender, to exercise its debt agreement option in April 2011 to settle $5.0 million in borrowings through the delivery to its lenders of its MAV IA 1 & 2 notes.

Although there have been some third party transactions during 2010, no transparent active market quotations have developed for the MAV A1 to C notes. As a result, management has estimated the fair value of the company’s investment in the MAV A1 to C notes at December 31, 2010, based on a probabilistic recovery of principal and interest, after taking into account all available information. Under this valuation method, several different outcomes of the recovery of the principal and interest are estimated, considering the information available as at December 31, 2010. A weighted average recovery is then calculated. This weighted average recovery is used to determine the discounted cash flows that are expected from these investments. The discount rate used to discount the expected cash flows from the MAV A1 to C notes approximates the risk-free rate over the expected life of the MAV A1 to C notes. As the rate used for discounting was an approximation of the risk-free rate, all other risks have been incorporated in the estimated probability-adjusted expected outcomes. This methodology applied all risking information into the various scenarios and discounted the fully-risked cash flow stream only for the time value of money. The recovery factors used were as follows:

			Risk-adjusted			Risk-adjusted			Capital			Interest
			Capital			Interest			Weighted			Weighted
Class of	Face Value of		Recovery			Recovery			Average			Average					Risk-free
Notes	Notes ($000s)		Range			Range			Recovery			Recovery			Term (years)		Discount Rate
A-1	$	13,970		30 - 85	%		10 - 70	%		81	%		67	%		2 - 6		3	%
A-2		13,543		0 - 70	%		0 - 30	%		64	%		27	%		6		3	%
B		2,459		0 - 40	%		0 - 10	%		36	%		9	%		6		3	%
C		928		0 - 10	%		0	%		10	%		0	%		6		3	%
Total	$	30,900

Based on the above approach the fair value of the investment in the MAV A1 to C notes was $18.7 million as at December 31, 2010 and 2009 as reconciled in the following table:

Years Ended December 31	2010			2009
($000)
Notes formerly known as ABCP, beginning of year	$	18,689		$	22,582
Fair value impairment		-			(2,104	)
Interest received and capital recoveries previously included in fair value of investment		(19	)		(1,789	)
MAV A1 to C notes, end of year	$	18,670		$	18,689

Since 2007, the total recognized impairment on the MAV A1 to C and MAV IA 1 & 2 notes is approximately 46 percent of the original cost of the investment, including impairments recognized on the ABCP.

The theoretical fair value of the company’s MAV A1 to C notes could range from $13.8 million to $23.1 million, using the valuation methodology described above, with reasonably possible alternative assumptions. The outcome of the actual timing and amount ultimately recoverable from these notes may differ materially from this estimate, which would impact the company’s losses.

Credit risk

The company’s maximum credit exposure on cash, accounts receivable, restricted cash, debt option agreement and long-term investments is equal to each financial asset’s carrying value as at December 31, 2010.

Cash, restricted cash and the debt agreement option are held with highly rated international banks and therefore the company considers these assets to have negligible credit risk.

The company’s accounts receivable are primarily with multinational purchasers, oil and gas marketers and local government agencies. The credit risk from joint venturers is considered to be low as generally the company requires that funding from joint venture partners is received prior to the company incurring the related work commitment expenditures. The company’s production base is entirely located in Argentina and is heavily weighted to crude oil. The company has a concentration of credit risk, as it sold US$52.7 million of crude oil production to one multinational purchaser and US$3.4 million in natural gas production to a reputable local gas marketing company during 2010. Receivables with local government agencies of $11.7 million mainly pertain to excise taxes paid on certain expenditures and can take several months prior to receipt after filing the appropriate returns. The company had a $5.0 million receivable from Gran Tierra Energy for partial consideration of the disposition of the company’s Sierra Nevada License in Colombia (see Note 4), which was subsequently received in January 2011. The company has not experienced nor is it aware of any collection problems with its counterparties. The company does not have an allowance for doubtful accounts with respect to credit risk, nor did it write off any receivables during 2010.

Refer to the fair values of financial instruments contained herein for further discussion regarding the credit risk of the MAC A1 to C notes recognized as at December 31, 2010 on the Consolidated Balance Sheet as long-term investments.

Liquidity risk

The company manages the risk of not meeting its financial obligations through management of its capital structure, annual budgeting of its revenues, expenditures and cash flows, cash flow forecasting and maintaining availability of credit facilities where practicable.

Accounts payable, as disclosed on the Consolidated Balance Sheet, fall due within the next year and are anticipated to be funded through the company’s cash, collections of accounts receivable and/or cash flow from operations.

During 2010, the company agreed to the terms of a Revised Credit Facility, resulting in a reduction to this facility’s availability from US$50.0 million to the current available limit of US$30.8 million, all of which is drawn at December 31, 2010. Changes in the availability of the Revised Credit Facility are anticipated to occur, from time-to-time, through significant reserve additions, disposals or revisions. The company also agreed to the following quarterly permanent debt repayments through to expiry of the agreement in June 2012 at which time all borrowings under this Revised Credit Facility will be due and payable:

As at
(US$000)
March 31, 2011	$	3,750
June 30, 2011	$	3,750
September 30, 2011	$	3,750
December 31, 2011	$	3,750
March 31, 2012	$	3,750
June 30, 2012	$	12,000

The quarterly repayments hereafter are anticipated to be funded from existing cash balances, collections of accounts receivable and/or cash flow from operations.

The company holds a combined ABCP line-of-credit availability of $28.2 million, of which $27.5 million is drawn at December 31, 2010. Of the $27.5 million drawn against the ABCP line-of-credit facilities, $5.0 million, as secured by the MAV IA 1 & 2 notes, received in exchange for a portion of ABCP, expires in April 2011 and $22.5 million, primarily secured on a recourse basis by the MAV A1 to C notes received in exchange for the other portion of ABCP, expires in April 2012.

The company’s Canadian and US dollar credit agreements have change-of-control provisions, such that upon being triggered they would require the consent of the company’s Canadian dollar lender and at least two-thirds of the syndicated US dollar lenders, respectively, for the company to retain continued access to the rights and benefits pursuant to each of its credit agreements.

Market risk

Changes in commodity prices, interest rates and foreign currency exchange rates can expose the company to fluctuations in its net loss and in the fair value of its financial instruments.

Commodity price risk

Price fluctuations for crude oil, natural gas liquids and natural gas are a risk to the company over which the company has little influence. Due to pricing controls present in Argentina and a domestic crude oil sales agreement with a multinational purchaser, crude oil selling prices reflect both current market conditions in Argentina and the movement of crude oil prices in international markets. Natural gas prices are impacted by the policy of the Argentine government and local demand with historic prices at low levels compared to world prices.

Interest rate risk

Floating rate debt exposes the company to fluctuations in cash flows and net losses due to changes in market interest rates. Based on the existing debt balance, a one percent increase (decrease) in the underlying market interest rates would have increased (decreased) the net loss by approximately $0.6 million on an annual basis.

Foreign currency exchange rate risk

Substantially all of the company’s operations are conducted in foreign jurisdictions, so the company is exposed to foreign currency exchange rate risk on most of its activities as reported in Canadian Dollars (“CAD”). Oil and natural gas sales contracts are denominated in US Dollars (“USD”) and settled in Argentine Pesos (“ARS”). Operating and capital expenditures are incurred in USD, ARS and Colombian Pesos (“COP”), and to a lesser extent in Peruvian Nuevos Soles (“PEN”). The Revised Credit Facility is denominated in USD, which partially limits the company’s exposure in terms of cash outflows (interest expense as classified as financing charges on the Consolidated Statement of Operations and Retained Earnings) which are of the same denomination to cash inflows (oil and gas revenues). The table below details the company’s financial instruments’ exposure to foreign currencies:

	Per
	Balance			CAD			USD			ARS			PEN			COP
($000)	Sheet			CAD $ equivalent amounts
Cash	$	11,046		$	1,824		$	4,293		$	4,435		$	10		$	484
Accounts receivable		25,667			86			5,999			4,848			354			14,380
Restricted cash		1,502			-			1,502			-			-			-
Debt option agreement		4,817			4,817			-			-			-			-
Long-term investments		18,670			18,670			-			-			-			-
Accounts payable and accrued liabilities		(12,439	)		(752	)		(4,733	)		(4,041	)		(12	)		(2,901	)
Bank debt		(19,879	)		(4,960	)		(14,919	)		-			-			-
Long-term bank debt		(36,589	)		(22,496	)		(14,093	)		-			-			-
Net financial assets (liabilities)	$	(7,205	)	$	(2,811	)	$	(21,951	)	$	5,242		$	352		$	11,963

The company estimates a 15 percent change in the CAD against the above listed foreign currencies could be reasonably possible over a twelve month period. A 15 percent strengthening in the CAD would result in a change to loss before taxes and other comprehensive loss as follows (an equal but opposite impact to loss before taxes and other comprehensive loss would result if the CAD weakened by 15 percent):

	USD			ARS		PEN			COP
($000)	CAD $ equivalent amounts
Increase in loss before taxes	$	(536	)	$	-	$	(46	)	$	(1,560	)
Decrease in other comprehensive loss	$	2,715		$	-	$	-		$	-

7. RELATED PARTY TRANSACTIONS

Under the terms of an administrative agreement with Connacher Oil and Gas Limited (“Connacher”), which has been in effect since January 1, 2008, Connacher provided certain administrative services at the direction of the company. The fee for this service was $0.2 million for 2010 and 2009. Connacher also paid bills on behalf of the company, for which it is reimbursed, in addition to providing office space for the company’s Canadian Corporate office, for which it was paid at the exchange amounts. These transactions gave rise to the company recognizing an amount owing to Connacher as at December 31, 2010 and 2009.

During 2010, the company paid professional legal fees and common share issue costs of $0.6 million (2009 - $0.5 million), to a law firm in which an officer of the company is a partner. Transactions with the related party occurred within the normal course of business and have been measured at the exchange amount on normal business terms. The exchange amount is the amount of consideration established and agreed with the related party.

Connacher purchased 13,556,000 units for gross proceeds to the company of $11.9 million pursuant to a public equity financing from treasury which closed on August 28, 2009, representing a portion of the issuance of a total of 65,343,000 units, for gross proceeds of approximately $57.5 million (see Note 10(b)). Connacher is a significant shareholder of the company with a 18.5 percent equity interest as at December 31, 2010 and the Executive Chairman of the company is the Chairman and Chief Executive Officer of Connacher.

Directors and officers of the company purchased 1,137,500 units for gross proceeds of $1.0 million pursuant to a private placement (see Note 10(c)), which closed on September 15, 2009. The issuance of units to the directors and officers of the company pursuant to the private placement was completed on the same terms as units sold pursuant to a public offering and over-allotment option, which respectively closed on August 28 and September 4, 2009.

8. ASSET RETIREMENT OBLIGATIONS

At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $18.0 million (December 31, 2009 - $17.3 million). These obligations are expected to be settled upon completion of the useful lives of the underlying assets, which currently extend up to 15 years into the future. This amount has been discounted using a credit- adjusted risk-free interest rate of six percent and an annual inflation rate of two percent. Changes to asset retirement obligations were as follows:

Years Ended December 31	2010			2009
($000)
Asset retirement obligations, beginning of year	$	9,552		$	10,106
Liabilities incurred		236			406
Changes to estimate		102			-
Cumulative translation adjustment		(496	)		(1,529	)
Accretion expense		558			569
Asset retirement obligations, end of year	$	9,952		$	9,552

9. INCOME TAXES

The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes:

Years Ended December 31	2010			2009
($000)
Loss before income taxes	$	(7,846	)	$	(6,851	)
Statutory income tax rate		28.00	%		29.00	%
Expected income tax recovery	$	(2,197	)	$	(1,987	)
Foreign tax rate changes		2,225			73
Future tax rate changes		1,036			3,355
Non-taxable portion of gains		(791	)		(923	)
Stock compensation		755			1,355
Valuation allowance increase		505			1,635
Future tax recoveries from prior periods		162			(682	)
Current tax adjustments from prior periods		32			1,123
Other		19			25
Tax expense	$	1,746		$	3,974

Current tax expense	$	1,933		$	3,362
Future tax expense (recovery)		(187	)		612
	$	1,746		$	3,974

Future income taxes relate to the following temporary differences:

Years Ended December 31	2010			2009
($000)
Property and equipment	$	1,784		$	16,758
Net operating loss carryforwards		(3,326	)		(17,708	)
Future foreign tax credit		9,192			10,080
Finance fees		(138	)		(128	)
Asset retirement obligation		(127	)		(140	)
Valuation allowance		3,029			2,291
Other		(387	)		(352	)
Future income tax liability	$	10,027		$	10,801

10. SHARE CAPITAL, WARRANTS AND CONTRIBUTED SURPLUS

(a) Authorized:

The authorized capital is comprised of an unlimited number of common shares and 33,239,600 warrants.

Issued common shares:
	Number of		Amount
Year Ended December 31, 2010	Common Shares			($000	)
($000)
Common shares, beginning of year		121,758,510	$	143,610
Issuance of common shares through public offering (b)		23,678,500		20,127
Issued common shares upon exercise of options (e)		40,000		20
Assigned value of options exercised (f)				2
Issued common shares upon exercise of warrants		650		1
Issue costs net of tax-effect (b)				(1,204	)
Common shares, end of year		145,477,660	$	162,556

	Number of		Amount
Year Ended December 31, 2009	Common Shares			($000	)
($000)
Common shares, beginning of year		54,948,010	$	92,408
Issuance of common shares through public offering (b)		65,343,000		52,928
Issuance of common shares through private placement (c)		1,137,500		921
Issued common shares upon exercise of options (e)		330,000		265
Assigned value of options exercised (f)				67
Issue costs (b)				(2,979	)
Common shares, end of year		121,758,510	$	143,610

Issued warrants:
	Number of			Amount
Year Ended December 31, 2010	Warrants				($000	)
($000)
Warrants, beginning of year		33,240,250		$	4,654
Exercise of warrants		(650	)		-
Warrants, end of year		33,239,600		$	4,654

	Number of		Amount
Year Ended December 31, 2009	Warrants		($000)
($000)
Warrants, beginning of year		-	$	-
Issuance of warrants through public offering (b) (d)		32,671,500		4,574
Issuance of warrants through private placement (c) (d)		568,750		80
Warrants, end of year		33,240,250	$	4,654

Share capital and warrants:
Years Ended December 31		2010		2009
Share capital and warrants	$	167,210	$	148,264

(b) Equity Financing:

2010

In March 2010, the company announced that it entered into an underwriting agreement with a syndicate of underwriters to issue on a “bought deal” basis 20,590,000 common shares at a price of $0.85 per common share for gross proceeds of approximately $17.5 million (“2010 Public Offering”). The underwriters were granted an over-allotment option (the “2010 Over-Allotment Option”), which included the right to purchase up to an additional 15 percent of the common shares, exercisable in whole or in part up to 30 days following closing of the 2010 Public Offering. The 2010 Over-Allotment Option was exercised in whole by the underwriters on April 14, 2010, the closing date of the 2010 Public Offering and resulted in a final total issuance of 23,678,500 common shares, raising gross proceeds to approximately $20.1 million. Issue costs of $1.3 million were incurred with respect to this 2010 Public Offering, less a $0.1 million tax effect.

2009

During August 2009, the company entered into an underwriting agreement with a syndicate of underwriters to issue 56,820,000 units (each, a “Unit”) at a price of $0.88 per Unit (“2009 Public Offering”), with each Unit consisting of one common share in the capital of the company (each, a “Common Share”) and one-half of one Common Share purchase warrant of the company (each whole Common Share purchase warrant, a “Warrant”), for gross proceeds of approximately $50.0 million. The price of $0.88 per Unit was allocated on the basis of $0.81 per Common Share and $0.07 per one-half warrant (Note 10(d)). The underwriters were granted an over-allotment option (the “2009 Over-Allotment Option”), which included the right to purchase up to an additional 15 percent of the Units, exercisable in whole or in part up to 30 days following closing on August 28, 2009. The 2009 Over-Allotment Option was exercised in whole by the underwriters, closed on September 4, 2009 and as a result there was a final total issuance of 65,343,000 Units, raising gross proceeds of approximately $57.5 million. Issue costs of $3.1 million were incurred with respect to this equity financing less a $0.1 million tax effect.

On September 15, 2009, the company closed a non-brokered private placement (“2009 Private Placement”) with certain directors and officers of the company to issue 1,137,500 Units at a price of $0.88 per Unit, with each Unit consisting of a Common Share and onehalf of one Warrant, for gross proceeds of approximately $1.0 million. The Units offered pursuant to the private placement were issued on the same terms as those offered pursuant to the company’s 2009 Public Offering, which closed on August 28, 2009.

(d) Warrants:

Each Warrant issued pursuant to the 2009 Public Offering and 2009 Private Placement, entitles the holder thereof to purchase one Common Share (each a “Warrant Share”) at an exercise price of $1.20 per Warrant Share until August 28, 2011. In the event that the 20-day volume weighted average price of the common shares on the Toronto Stock Exchange exceeds $2.50, the company may, within five business days after such an event, provide notice to the holders of the Warrants (“Warrantholders”) of early expiry and thereafter the Warrants can either be exercised or they will expire on the date which is 30 days after the date of the notice to the Warrantholders.

The fair value of each Warrant issued during 2009 was estimated on the date of issuance using the Black-Scholes option-pricing model with assumptions for Warrants as follows:

		Dividend yield				Risk-free interest rate			Expected life		Expected volatility
2009			-	%			1.5	%	2 years			90	%

The weighted average fair value of Warrants issued in 2009 was $0.14 per Warrant.

(e) Stock Options:

As at December 31, 2010 and 2009, the company had outstanding stock options to acquire common shares, as follows:

As at December 31	2010					2009
	Number of			Weighted Average		Number of			Weighted Average
	Options			Exercise Price		Options			Exercise Price
Outstanding, beginning of year		7,683,067		$	1.60		4,576,327		$	6.85
Granted		2,229,454			0.91		5,490,900			1.29
Exercised		(40,000	)		0.50		(330,000	)		(0.80	)
Forfeited or cancelled		(393,400	)		3.10		(2,054,160	)		(12.59	)
Expired		(452,667	)		1.04		-			-
Outstanding, end of year		9,026,454			1.40		7,683,067			1.60
Exercisable, end of year		5,518,089		$	3.42		3,349,135		$	1.70

Options granted under the company’s stock option plan are generally fully exercisable after two or three years and expire five years after the date granted. The table below summarizes outstanding stock options and the weighted average remaining contractual life, in years, by ranges of exercise prices as at December 31, 2010 and 2009:

As at December 31	2010				2009
			Weighted Average				Weighted Average
			Remaining				Remaining
	Number		Contractual Life		Number		Contractual Life
	Outstanding		(yrs)		Outstanding		(yrs)
$0.50		-				40,000		0.9
$0.86 - $1.09		6,518,954		3.9		4,892,567		4.4
$1.70 - $1.75		288,000		0.1		313,000		1.1
$2.00		932,000		2.9		977,000		3.9
$2.64 - $3.37		1,208,000		3.3		1,209,000		4.3
$5.40 - $19.20		79,500		2.0		179,500		1.9
Total		9,026,454		3.6		7,683,067		4.1

During 2010, a non-cash expense of $2.7 million (2009 - $3.6 million) was recorded as stock-based compensation expense, reflecting the amortization of the fair value of stock options over the vesting period.

During 2009, certain employees, officers and non-managerial directors of the company voluntarily surrendered 1,786,660 options with a weighted average exercise price of $13.79 per option. Any unvested options that were voluntarily surrendered were deemed to have become vested, resulting in the recognition of an additional non-cash stock-based compensation expense during 2009 of $1.1 million.

The fair value of each option granted for 2010 and 2009 is estimated on the date of grant using the Black-Scholes option-pricing model with assumptions for grants as follows:

				Risk-free
	Dividend Yield			Interest Rate			Expected Life	Expected Volatility
2010		-	%		2.0% - 2.8	%	4 years		81% - 82	%
2009		-	%		2.0% - 2.7	%	4 years		81% - 90	%

The weighted average fair value at the date of grant of all options granted for 2010 was $0.56 per option (2009 - $0.83 per option).

(f) Contributed Surplus:

Years Ended December 31	2010			2009
Contributed surplus, beginning of year	$	20,453		$	15,846
Stock-based compensation		2,695			4,674
Assigned value of options exercised		(2	)		(67	)
Contributed surplus, end of year	$	23,146		$	20,453

11. SEGMENTED INFORMATION

The company has corporate offices in Canada, the US and Barbados (combined to comprise the “Corporate” segment), petroleum and natural gas production in Argentina and exploration activities in Peru and Colombia. Financial information pertaining to these segments is presented below.

	Corporate			Argentina			Peru			Colombia			Total
($000)
Year Ended December 31, 2010
Revenue, gross	$	34		$	63,230		$	-		$	91		$	63,355
Net loss		(3,100	)		(6,390	)		(33	)		(69	)		(9,592	)
Property and equipment		115			128,218			57,901			77,735			263,969
Capital expenditures		111			7,983			1,732			40,680			50,506
Total assets	$	27,483		$	148,387		$	59,025		$	94,172		$	329,067
Year Ended December 31, 2009
Revenue, gross	$	9		$	83,760		$	22		$	-		$	83,791
Net earnings (loss)		(12,574	)		1,816			(18	)		(49	)		(10,825	)
Property and equipment		311			158,756			56,190			47,799			263,056
Capital expenditures		43			27,082			7,462			37,036			71,623
Total assets	$	44,180		$	183,986		$	60,327		$	60,572		$	349,065

Crude oil sales totaling US$52.7 million were made to one large international oil company and natural gas sales totaling US$3.4 million were made to one reputable local gas marketing company in 2010. In 2009, US$63.9 million in crude oil sales were made to another large international oil company and natural gas sales totaling US$4.7 million were made to the same gas marketing company.

12. SUPPLEMENTARY INFORMATION

(a) Per share amounts

The following table summarizes the calculation of basic and diluted common shares:

Years Ended December 31	2010		2009
Weighted average common shares outstanding		138,728,326		78,711,781
Dilutive effect of stock options and share purchase warrants		1,469		264,022
Weighted average common shares outstanding - diluted		138,729,795		78,975,803

As the company has net losses for 2010 and 2009, the dilutive effect of stock options and share purchase warrants became anti-dilutive causing 138,728,326 and 78,711,781 weighted average dilutive common shares outstanding to be used as the denominator in the diluted per share net loss calculation for 2010 and 2009, respectively.

(b) Net change in non-cash working capital

($000)	2010			2009
Accounts receivable	$	(5,478	)	$	14,127
Income taxes receivable		2,383			(668	)
Prepaid expenses		(1,601	)		52
Inventory		16			(129	)
Accounts payable and accrued liabilities		(3,316	)		(18,194	)
Income taxes payable		123			(344	)
Due to a related company		17			(13	)
	$	(7,856	)	$	(5,169	)

Operating	$	(658	)	$	8,989
Investing		(7,198	)		(14,158	)
	$	(7,856	)	$	(5,169	)

($000)	2010		2009
Interest paid	$	2,962	$	3,950
Income taxes paid	$	1,943	$	6,107

13. COMMITMENTS AND GUARANTEES

Work commitments

The Peruvian licenses have negotiated work programs through 2016, unless extended. The company has the right to withdraw from each license upon completion of its current period work commitment associated with the term of the license. Each work program has a specified minimum financial commitment that must be met for the company to maintain its rights to these licenses. Specifically, the immediate minimum work commitment of US$0.3 million for Block 133 as required to be met by February 2011 was primarily comprised of geological field studies. The company has met, or surpassed, all of its current work commitments for Blocks 106 and 107 in a timely manner. The company has received approval of its Block 107 Environmental Impact Assessment (“EIA”) for several potential drilling sites and is awaiting approval of its recently filed EIA amendment, at which time it can commence with the fourth period’s work commitment requiring one well to be completed by 2013. As at December 31, 2010, the company was completing its EIA for Block 106 prior to entering the fifth period’s work commitment requiring one well to be completed or 300 km of seismic to be acquired and processed by 2012 (see Note 14(b)).

The company has three Colombian exploration licenses: Sierra Nevada, Turpial, and Magdalena. The company anticipates it has completed the second phase of its Sierra Nevada License work program by drilling an exploratory well, Brillante SE-1X, and completing a 3D seismic program over the La Pinta structure. The completion of this phase is still to be acknowledged by the ANH. The company has notified the ANH that it will proceed with phase three of the Sierra Nevada License work program, which requires the drilling of one exploration well to the targeted depth of the reservoir prior to June 2011. While still to be acknowledged by ANH, the company recently completed the second phase 2D seismic acquisition and interpretation work program on its Turpial License. This was disproportionately financed by the company’s joint venturer. The company is in the first phase of its Magdalena License, which requires the drilling of an exploratory well prior to March 2011. The company spudded an exploratory well on its San Angel prospect in February 2011.

In Argentina, the company has farmed out its Puesto Guevara work commitment of US$0.6 million through an agreement reached in 2010. Once the company’s joint venturer has funded the work commitment requiring the drilling of an exploration well for the Puesto Guevara Concession, in addition to the drilling of a second exploration well, the company’s working interests therein will be reduced to 44 percent. The company’s remaining Argentinean work commitment of US$2.4 million on its Puesto Morales Este Concession requires the drilling of two development wells and associated facilities in 2011.

Operating lease commitments

The company’s gross operating lease commitments under service contracts for drilling, leases for office premises and other equipment and an administrative services agreement are as follows:

			Subsequent
	2011		to 2012		2012		Total
($000)
Drilling service contracts leases and administrative
Services agreement	$	4,227	$	1,072	$	781	$	6,080

Guarantees

As at December 31, 2010 the company has issued letters of credit in the total amount of US$1.4 million and $0.1 million, respectively, to secure the capital expenditure requirements associated with the Colombian and Peruvian work commitments (December 31, 2009 - US$2.1 million and US$1.7 million, respectively). As at December 31, 2009, a deposit of US$4.1 million was held in a trust account in Colombia which financed the 2010 work obligations on the Magdalena License as they occurred.

14. SUBSEQUENT EVENT

a) Arrangement Agreement with Gran Tierra Energy Inc.

On January 17, 2011, the company announced that it has entered into an arrangement agreement (the “Arrangement Agreement”) where Gran Tierra Energy will acquire all of the company’s outstanding common shares and Warrants pursuant to a plan of arrangement (the “Arrangement”). The Arrangement is subject to approval by at least two thirds of the company’s shareholders, either in person or by proxy, at a meeting to be held in Calgary, Alberta on March 17, 2011, in addition to being subject to other customary conditions, including the approval of the Court of Queen’s Bench of Alberta. Under the terms of the Arrangement Agreement, the company’s shareholders will receive from Gran Tierra Energy’s treasury 0.1241 of a share of Gran Tierra Energy for each Petrolifera share held. In addition, Warrantholders will receive 0.1241 of a common share purchase warrant of Gran Tierra Energy (“Replacement Warrants”) with an exercise price of $9.67 per share and an expiry date of August 28, 2011. Each Replacement Warrant will be exercisable for one Gran Tierra Energy common share and upon being exercised, holders would not be required to make a cash payment as they would receive a net number of Gran Tierra common shares equal to the intrinsic value of the Replacement Warrants.

All of the company’s directors and officers, together with the company’s largest shareholder, Connacher, representing in aggregate 21 percent of the issued and outstanding company shares as at January 31, 2011, have entered into agreements with Gran Tierra Energy to vote in favour of, and otherwise support the Arrangement, subject to customary exceptions.

In the event that the Arrangement Agreement is terminated due to a breach of representation, warranty or covenant by the company that has a material adverse effect on the company, the company will be required to pay to Gran Tierra Energy a termination fee in the amount of $7.9 million.

b) Relinquishment of Exploration License Rights to Peruvian Block 106

On March 4, 2011 Petrolifera issued a letter to Perupetro, the state agency of Peru, advising of its intention to surrender the license covering Block 106 in the Maranon Basin, Peru. The company’s Block 106 carrying value of approximately $21.3 million was included as an unproved property cost in properties and equipment in the Consolidated Balance Sheet as at December 31, 2010. The company retains licenses covering Blocks 107 and 133 in the Ucayali Basin, Peru.

15. RECONCILATION OF THE CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

These consolidated financial statements have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”) which, in most respects, conform to the United States Generally Accepted Accounting Principles (“US GAAP”). Any differences in accounting principles as they have been applied to the accompanying consolidated financial statements are not material except as described below. Items required for financial disclosure under US GAAP may be different from disclosure standards under Canadian GAAP; any such differences are not reflected here.

The application of US GAAP would have the following effects on net loss and comprehensive loss, basic and diluted loss per share as reported:

Year ended December 31, 2010 (in $'000's of Canadian dollars)

Net loss under Canadian GAAP	$	(9,592	)
Adjustments:
Write-down of properties and equipment, net of tax (a)		(23,035	)
Depletion, depreciation and accretion recovery, net of tax (b)		4,180
Capitalization of stock-based compensation (c)		237
Other future income tax expense (d)		(1,405	)
Net loss under US GAAP		(29,615	)

Other comprehensive loss under Canadian GAAP		(5,064	)
Adjustments:
Foreign currency translation gain		1,371
Other comprehensive loss under US GAAP		(3,693	)

Comprehensive loss under US GAAP	$	(33,308	)

Net loss per share under US GAAP, basic and diluted	$	(0.21	)

The application of US GAAP would have the following effect on the consolidated balance sheet as reported:

As at December 31, 2010
(in $'000's of Canadian dollars)	Canadian GAAP			US GAAP

ASSETS
Deferred financing fees (e)	$	-		$	1,572
Properties and equipment (a), (b), (c)	$	263,969		$	218,723

LIABILITIES
Long-term bank debt (e)	$	36,589		$	38,161
Future/deferred income tax liability (d)	$	10,027		$	-

SHAREHOLDERS' EQUITY (a), (b), (c), (d)
Retained earnings	$	57,570		$	20,810
Accumulated other comprehensive loss	$	(8,817	)	$	(7,277	)

(a) Under Canadian GAAP, Petrolifera performs an impairment test that limits the capitalized costs of its petroleum and natural gas assets to the estimated future net revenue, using expected future prices and costs, from proved and probable petroleum and natural gas reserves discounted at a risk free interest rate plus the cost of unproved properties less impairment. Under US GAAP, entities following the full cost method of accounting for petroleum and natural gas properties perform an impairment test on each cost centre by calculating future net revenue, using constant prices, from proved petroleum and natural gas reserves discounted at 10%. Constant prices are determined as a twelve month average price on the first date of each month. As at December 31, 2010, the application of the ceiling test under US GAAP resulted in a write down of approximately $23.0 million, net of tax. The cumulative effect of the application of the ceiling test on opening retained earnings as at January 1, 2010 was a decrease of $16.8 million.

(b) Under Canadian GAAP, proved reserves are estimated using expected future prices and costs. These proved reserves form the basis for the depletion calculation. Under US GAAP, proved reserves used for the depletion calculation are estimated using constant prices and costs as of the date the estimate of reserves is made. In the current year, there were differences in proved reserves under US GAAP and Canadian GAAP which resulted in differences in the depletion expense. Additionally, under US GAAP the depletable asset base was affected by other GAAP differences: the ceiling test write down required under US GAAP in prior years (see (a) above) and share-based payments capitalization (see (c) below). These GAAP differences resulted in lower depletion expense of approximately $4.2 million during the year ended December 31, 2010, net of tax. The cumulative impact of the adjustments on opening retained earnings as at January 1, 2010 was a decrease of $3.9 million, net of tax.

(c) Under Canadian GAAP, Petrolifera expensed all stock-based compensation costs. Under US GAAP, share-based payments directly attributable to the exploration and development of oil and gas properties are capitalized, together with any other directly attributable employee compensation costs. Stock-based compensation costs amounting to $0.2 million were capitalized to properties and equipment under US GAAP during the year ended December 31, 2010. Opening retained earnings as at January 1, 2010 increased by $4.2 million as a result of certain share-based payments being capitalized.

Petrolifera accounted for forfeitures on stock options granted as they occurred under Canadian GAAP. Under US GAAP an estimate of expected forfeitures is required to be made and updated each reporting period taking into account actual forfeitures. There is no adjustment to Petrolifera’s stock-based compensation expense due to this difference.

(d) Deferred income tax liability and expense under US GAAP is different from Canadian GAAP due to tax effects of GAAP adjustments discussed in notes (a), (b), (c).

The Canadian GAAP liability method of accounting for income taxes is similar to the Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) 740 Income Taxes, which requires the recognition of tax assets and liabilities for the expected future tax consequences of events that have been recognized in Petrolifera’s consolidated financial statements. Pursuant to US GAAP, enacted tax rates are used to calculate deferred income tax, whereas Canadian GAAP uses substantively enacted rates. There are no differences for the year ended December 31, 2010 relating to tax rate differences.

ASC 740 provides specific guidance on the recognition and measurement of uncertain tax positions. ASC 740 prescribes the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. It also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. US GAAP utilizes a two-step approach for evaluating tax positions. Recognition (step one) occurs when an enterprise concludes that a tax position, based solely on its technical merits, is more likely than not to be sustained upon examination. Measurement (step two) is only addressed if step one has been satisfied (i.e., the position is more likely than not to be sustained). Under step two, the tax benefit is measured as the largest amount of benefit, determined on a cumulative probability basis, that is more likely than not, defined as greater than 50%, to be realized upon ultimate settlement. The accounting methodology required by US GAAP is complex and different from Canadian GAAP. There are no significant differences for the years ended December 31, 2010 relating to uncertain tax positions.

(e) Debt transaction costs are recorded as deferred financing costs under US GAAP instead of being netted against the debt proceeds under Canadian GAAP.

(f) New accounting pronouncements:

Variable Interest Entities

In June 2009, the FASB issued revised accounting standards to improve financial reporting by enterprises involved with variable interest entities. The standards replace the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and: (1) the obligation to absorb losses of the entity; or, (2) the right to receive benefits from the entity. This standard was effective for interim and annual reporting periods beginning after November 15, 2009. The implementation of this standard did not materially impact the Company’s consolidated financial position, operating results or cash flows.

Stock Compensation

In April 2010, the FASB issued Accounting Standards Update (“ASU”) Compensation–Stock Compensation (Topic 718). The amendments clarify that an employee share based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The implementation of this update is not expected to materially impact the Company’s consolidated financial position, operating results or cash flows.

GRAN TIERRA ENERGY INC. - FORM 8-K/A - EX-99.1 - June 3, 2011

Attached files

GRAN TIERRA ENERGY INC. Reports