Petro Vista Energy Corp. PTVYF

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PETRO VISTA ENERGY CORP.

Management Discussion and Analysis (“MD&A”)

for the year ended September 30, 2010

The following discussion and analysis of the operations, results, and financial position of the Company for

the year ended September 30, 2010 should be read in conjunction with the Company’s audited

consolidated financial statements and related notes for the year ended September 30, 2010. The

effective date of this report is January 21, 2011. All figures are presented in Canadian dollars, unless

otherwise indicated.

THE COMPANY

Petro Vista currently has an interest in three hydrocarbon exploration blocks in Brazil (169, 170 and

Tartaruga) and three exploration blocks in Colombia (Morichito, La Maye and SSJN-5).

Petro Vista Energy Corp., (the “Company” or “PVE” or “Petro Vista”) was a Capital Pool Company

(“CPC”) as defined by Policy 2.4 of the TSX Venture Exchange (the “Exchange”) until April 9, 2008. The

terms “Company”, “PVE” and “Petro Vista” used in this MD&A refer to Petro Vista Energy Corp. on a

consolidated basis, which includes the parent company and all of its subsidiaries.

Petro Vista has from its inception chosen countries offering positive fiscal regimes, high resource

potential, and low cost environments. The selection of our main projects, starting with the Morichito,

Tartaruga, La Maye and Recôncavo Basin blocks were based on several screening criteria including

mature or semi mature infrastructure, high contractual netbacks to contractor or high contractor take,

lower cost drilling and operations and located in areas with proven resources.

PETROLEUM AND NATURAL GAS PROPERTIES

The Company is currently conducting exploration activities in Brazil and Colombia. The following is a

summary of the Company’s oil and gas interests (additional details provided throughout MD&A):

Country Block Onshore /

Offshore

Interest Current

Contractual

Stage

Expiry Date of

Current

Contractual

Stage

Current Stage

Commitment ($

net PVE share)

Operated /

Nonoperated

Brazil Block 169 Onshore 50%

Exploration –

Phase 1

Oct 2011 (1)

One well

US$520,000

Nonoperated

Brazil Block 170 Onshore 25%

Exploration –

Phase 1

- (2)

One well

US$880,000

Nonoperated

Brazil Tartaruga

Offshore/

Onshore

37.5% (3) Development 27 years

One well

US$6,648,000.

Workover well

US$286,000

Nonoperated

Colombia Morichito Onshore 50%

Exploration –

Phase 5

Mar 2011

One well

US$1,750,000

Operated

Colombia La Maye Onshore 25% (4)

Exploration –

Phase 2

Oct 2010

Two wells

US$646,000

Nonoperated

Colombia SSJN-5 Onshore 25% (5)

Exploration –

Phase 1

June 2012

3D Seismic

US$Nil

One well

US$1,250,000 (6)

Nonoperated

(1) The due date to drill a well on Block 169 was June 5, 2010, however, Agencia Nacional do Petroleo, Gas Natural e

Biocombustiveis (“ANP”) has extended the deadline to October 21, 2011.

(2) Due to death of a landowner, expiry of Block 170 exploration period was suspended. Block 170 well will need to be drilled within

6 months from the date access to the block is arranged.

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(3) The Company is earning a 37.5% working interest (27.23% revenue interest net of royalties) by funding 100% of the first US$5.6

million of costs of drilling and completing one sidetrack development well and 50% of expenditures over US$5.6 million. As of

September 30, 2010, the Company paid approximately US$5.9 million towards drilling of the sidetrack development well, and

subsequent to September 30, 2010 the Company paid an additional amount of approximately U
.34 million. It is expected that

the Company’s portion of the remaining costs to complete this well will be approximately US
.4 million. In addition, the

Company agreed to fund 50% of the workover costs of an existing producing well estimated at US
.27 million. The Company’s

working interest in the new well and the existing producing well is subject to consortium and regulatory approval and fulfilling its

funding and work commitments. The Company will apply for the regulatory approval of the transfer of interest to the Tartaruga

Block upon completion of the earn-in.

(4) The Company has paid US
.9 million of exploration advances which will be used to pay for the Company’s 25% share of drilling

costs of the second well and a portion of the third well. The Company needs to make US
.65 million of remaining contributions

to the drilling of the third and forth wells in order to earn its 25% participating interest in the La Maye Block.

(5) The 25% working interest is net of pending Petroamerica farmout. Petroamerica is farming into a 25% working interest in the

Block SSJN-5 by funding its 25% share and the Company’s 25% share of costs of the planned Phase 1 3D seismic program. The

Petroamerica farmin is subject to regulatory approval in Colombia. (note – there is also a share consideration) Additionally,

Petroamerica has the right to acquire the Company’s remaining 25% interest in Block SSJN-5 for US$3 million. Petroamerica

may exercise this option within 60 days of Petroamerica receiving a copy of the final report of the 3D seismic program on the

block.

(6) The Company’s 25% share of Phase 1 3D budgeted seismic program for Block 5 for calendar year 2011 is US$4.6 million. This

obligation is being carried by Petroamerica as part of their farmout agreement. The Company’s 25% share of drilling costs of

one well is US$1.25 million.

Exploration and Development

The Company is actively investigating, evaluating and conducting exploration activities in Brazil and

Colombia. The summary of deferred oil and gas costs as of September 30, 2010 is as follows:

As of September 30, 2010 Brazil Colombia Total

Acquisition costs $ - $ 6,740,305 $ 6,740,305

Exploration costs 6,696,079 7,572,733 14,268,812

Future income tax related to above - 2,366,519 2, 366,519

Net book value $ 6,696,079 $ 16,679,557 $ 23,375,636

Details of activities for the year ended September 30, 2010 are as follows:

Brazil Colombia Total

Balance – September 30, 2009 $ 306,197 $ 13,956,594 $ 14,262,791

2010 exploration costs

Consulting 20,117 136,197 156,314

Camp and general - 535,325 535,325

Geological and geophysical 50,820 473,493 524,313

Office and administration - 1,195,920 1,195,920

Salaries and benefits 56,540 761,277 817,817

Security - 83,298 83,298

Travel - 62,634 62,634

Stock based compensation 22,058 77,424 99,482

Drilling 6,160,281 3,484,004 9,644,285

Platform construction - 372,758 372,758

Cementing - 31,822 31,822

Equipment rental - 43,441 43,441

Production test - 210,032 210,032

Asset retirement obligation - 90,509 90,509

Cost recovery from partners - (4,699,026) (4,699,026)

Total exploration costs, net 6,309,816 2, 859,108 9, 168,924

Future income tax (recovery) - (136,145) (136,145)

Production costs, net 80,066 - 80,066

Balance – September 30, 2010 $ 6,696,079 $ 16,679,557 $ 23,375,636

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During the year ended September 30, 2010, the Company incurred $9,168,924 of exploration costs.

As of September 30, 2010, the accumulated balance of petroleum and natural gas acquisition and

exploration costs was $23,375,636. During the year ended September 30, 2010, the Company

capitalized $1,195,920 of general and administrative costs related to exploration activities.

Brazil

As of September 30, 2010, the Company held an interest in three hydrocarbon exploration blocks in

Brazil. Summary is as follows:

a) Blocks 169 and 170, Recôncavo Basin

The Company holds a 50% working interest in Block 169 and a 25% working interest in Block

170. The Company’s share of the committed work program for Blocks 169 and 170 includes the

drilling of one well on each block estimated at US$520,000 and US$880,000 respectively. Due to

the death of a landowner, expiry of Block 170 exploration period was suspended. The Block 170

well will need to be drilled within 6 months from the date access to the block is arranged. The

due date to drill a well on Block 169 is October 21, 2011. As of September 30, 2010, the

Company had accumulated $103,168 (September 30, 2009 – $104,125) of acquisition and

exploration costs on these blocks.

b) Tartaruga Block (SES-107 D), Sergipe Alagoas Basin, Brazil

On October 15, 2009, the Company signed an option agreement with UP Petroleo Brasil Ltda.

(“UPB”) to farm into and acquire a 37.5% working interest (27.23% revenue interest net of

royalties) in the Tartaruga offshore hydrocarbon exploration block, located in the Sergipe Alagoas

Basin, Brazil. To earn its interest, the Company was required to fund 100% of the costs of drilling

and completing a sidetrack development well on the Block up to US$5,595,771, with expenditures

over US$5,595,771 being shared equally by the Company and UPB (50% each). On October 21,

2009, the Company advanced to UPB US$4,000,000 for drilling, at which point, the Company

became entitled to a 37.5% gross revenue interest in the existing production from the Block. As

of September 30, 2010, the Company has paid to UPB approximately US$5,900,000 towards

earning its interest in the Tartaruga block.

The Company also agreed to finance 50%, being US$286,100, of the work-over costs of the

existing well, which work-over is planned to be completed in 2011.

The farm in and corresponding assignment of interests is subject to several condition, including

the approval from the consortium members and the Agencia Nacional do Petroleo, Gas Natural e

Biocombustiveis (“ANP”). The Company will apply for regulatory approval upon completion of the

farm-in.

As of September 30, 2010, the Company had accumulated $6,592,911 (September 30, 2009 -

$202,072) of deferred exploration costs related to this block.

Tartaruga Operations Update

The Tartaruga Block is located in Brazil's prolific Sergipe-Alagoas Basin, north-eastern Brazil.

One existing well on the block has been producing for over 12 years at an average rate of 90

boe/d from one zone. This well has multiple additional pay zones identified on logs. In December

2009, a fluid treatment was performed on this well increasing production to over 400 boe/d. An

additional workover is planned for this well during 2011, aimed at increasing the wells rate of

production. Production from this well was suspended from January to April 2010 due to the

drilling of a new sidetrack development well on the block.

UPB is the operator of the Tartaruga Block and managed the drilling of a new sidetrack

development well (7-TTG-1DP-SES) which reached total depth (3,445m) in April 2010. This

4

deviated well was drilled off of an existing well pad capable of accommodating up to an additional

four wells. A total estimated potential net pay interval of 101 feet (31m), across eleven zones of

interest, has been identified based on mudlog shows, electrical logs and by petrophysical

analysis. Strong oil and gas shows identified on mudlog and oil in cuttings were observed

throughout the reservoir section (2,900m MD to 3,445m MD). The Penedo reservoir P13 interval

at a depth of approximately 3,400 m MD will be perforated first during completion. Depending on

results, the well may be initially placed on production from this reservoir or additional reservoirs

may be tested and produced. The oil from the Tartaruga Field is good quality 41 degree API.

In December 2010, environmental and production permits were received, a work over rig

mobilized and testing and completion operating commenced. . Completion is expected during the

first calendar quarter of 2011. Assuming commercial rates of production, this well may be brought

immediately into production using existing facilities.

An oil sales contract with Petrobras exists at current market prices less US$1.60 per barrel. The

crude oil is currently trucked to a nearby refinery. Once sufficient production rates are

established, a tie-in pipeline into the nearby main line within 5 km of the Tartaruga Block may be

constructed.

Tartaruga Production

On October 21, 2009, the Company earned its right to apply for a 37.5% share of gross

production revenue from the Tartaruga Block. The production from the existing Tartaruga well

was temporarily suspended from January to April 2010 due to drilling of the new sidetrack

development well on the block. The Company’s cumulative 37.5% share of gross production for

the year ended September 30, 2010 was 6,001 boe at an average price of $77.87 per barrel for

gross proceeds of $467,291, with royalty expenses of $124,798 and operating costs of $422,559,

resulting in net production loss of $80,066. The net loss of $80,066 was capitalized to oil and gas

costs. The Company realized loss from operations due to shutting down production from this well

in February, March and April 2010 to allow for drilling of the new sidetrack development well.

During the quarter ended September 30, 2010, the Company’s 37.5% share of gross production

was 2,317 boe at an average price of $77.48 per barrel for gross proceeds of $179,521, with

royalty expenses of $47,944 and operating costs of $129,735, resulting in net production income

of $1,842.

Colombia

a) Morichito Block, Llanos Basin, Colombia

Between July 1, 2008 and August 29, 2008, the Company acquired a 51.96% working interest in,

and operatorship of, the Exploration and Production Contract (the “E&P Contract”) governing the

Morichito Block located in the Llanos basin, Colombia, by acquiring 99.535% of the issued capital

of Petropuli Ltda. (“Petropuli”), a Colombian private limited liability company and the concession

owner and operator of the Morichito Block. As consideration for the acquisition of Petropuli, the

Company paid $5,470,194 and granted to the sellers an aggregate 4% net production royalty on

the Company’s production from the Morichito block.

On October 10, 2008, the Company’s subsidiary Petropuli acquired the remaining 47.8% interest

in the Morichito Block from its joint venture partner, thereby increasing Petropuli’s interest in the

Morichito Block to 100%. As consideration, the Company agreed to pay the following:

(i) US$500,000 on November 26, 2008 (paid);

(ii) US$2,500,000 out of 40% of the net revenue received by Petropuli or any of its

assignees from the future production of the Morichito Block; and

(iii) A royalty of 1% of net production received by Petropuli from the Morichito Block.

5

Under the terms of the Exploration and Production Contract, the exploration period is for six years

and is divided into six exploration phases. The exploitation period is for 24 years. In March 2010,

Petropuli completed Phase 4, by successfully drilling and completing the third exploratory well

(M5). Testing of well M5 and commencement of production is anticipated by March 2011. The

Company is now in Phase 5, which requires drilling a fourth exploratory well (M5B) by January

31, 2011, but the Company requested an automatic 60 day extension which is guaranteed under

the concession contract. The Company may seek additional extensions as a result of flooding

prohibiting operations on the block. The Company’s 50% share of drilling costs of exploratory

well M5B is estimated at US$1,750,000.

Petropuli, the Company’s Colombian subsidiary, is the operator of the Morichito Block. During

the year ended September 30, 2010, the Company has incurred $6,520,730 of drilling and other

exploration costs, and has recovered $4,425,064 of these costs from its partners. As of

September 30, 2010, the Company has accumulated $6,740,305 (September 30, 2009 –

$6,740,305) of acquisition costs, $4,969,087 (September 30, 2009 - $2,873,282) of net

exploration costs, and $2,366,519 (September 30, 2009 - $2,502,664) of deferred future income

tax costs related to the Morichito Block. As at September 30, 2010, the Company has a 50%

interest in the Morichito block.

Farmout of a 15% interest in the Morichito block to Green Power Corporation

By an option agreement dated January 16, 2009 between Petropuli and Green Power

Corporation (“Green Power”), Green Power earned a 15% working interest in the Morichito Block

by paying to Petropuli US$250,000 paying 50% of the completion work on the existing well that

was drilled by Petropuli in 2006 (M2 well), and paying the next US$1,050,000 of drilling costs of

M1N well.

This option agreement is conditional upon Petropuli obtaining from the ANH an approval to assign

the 15% working interest in the Morichito Block to Green Power. Petropuli will commence the

application process for the assignment of the 15% interest to Green Power upon receiving from

Green Power all requested information needed for the application process. The ANH approval

should be obtained within 240 working days from the date when the assignment request is filed

with the ANH by Petropuli.

Farmout of a 35% interest in the Morichito Block to Golden Oil Corp.

By an agreement dated March 6, 2009, Golden Oil Corp. (“Golden”) had a right to earn a 35%

working interest in the Morichito Block by paying to Petropuli a US$500,000 signing bonus and

financing US$3,900,000 of Morichito exploration costs. Golden completed its funding obligation

in the Morichito Block in January 2010. Petropuli will commence the application process for the

assignment of the 35% interest to Golden upon receiving from Golden all requested information

needed for the application process.

Morichito Operations Update

In April 2009, the Company completed exploratory well M2, however quantities of oil discovered

were not sufficient to commence commercial production. The Morichito M1N exploration well was

drilled in May 2009 (Phase 3) to a depth of 6,829 feet and six zones were tested in June 2009,

however, these zones proved to be water wet.

In March 2010 the Company drilled Morichito M5 to a depth of 6,160 feet. Logging has identified

three potential pay zones at the location with a combined net pay thickness (based on detailed

petrophysical analysis) of approximately 16 feet. Swab testing and drill stem tests have been

carried out on one eMirador and on Carbonera C7 reservoir so far. The lower Mirador reservoir

was swabbed at a rate of 375 barrels of oil per day of 23 degree API oil with no water cut. This

zone exhibits excellent reservoir quality including high porosities and permeabilities as evidenced

by excellent pressure build-up (shut in pressure of 2069 psi). Engineering analysis indicates that

6

this zone has the potential to produce at rates of up to 1,000 bopd using artificial lift methods The

other zone that tested oil is in the upper Carbonera C7 reservoir that shows similar excellent log

characteristics and potential as the lower zone. The other potential pay zone identified is in the

Carbonera C1 formation that is also productive in the area. The full production potential of this

zone will be evaluated at a later date.

The Company is preparing for testing, and workover of well M5 at an estimated cost to the

Company of US$550,000. The Company’s share of production facilities costs is estimated at

US$672,000. If successful, production from well M5 is expected to commence in March 2011.

b) La Maye Block, Lower Magdalena Basin, Colombia

Pursuant to a Joint Operating Agreement dated July 7, 2008 and a Participation Agreement dated

July 7, 2008 as amended June 30, 2009 and July 30, 2009 with New Horizon Exploration Inc.

(“New Horizon”), the Company has an option to earn a 25% participation interest in the

Exploration and Production Contract governing the La Maye Block. As consideration for the 25%

interest, the Company agreed to pay to New Horizon US$2,062,500, representing 25% of

estimated costs of the current exploration program. On July 16, 2008 the Company paid

US$916,958. On July 30, 2009, the Company and New Horizon agreed that the remaining

contributions of US$1,146,197 will be made by the Company as follows:

(i) US$300,000 within 3 business days from the signing of the agreement (paid);

(ii) US$200,000 within 10 calendar days of the spudding of the first well (paid);

(iii) US$196,491 within 10 calendar days of the spudding of the third well;

(iv) US$224,853 within 10 calendar days of the date when the participating partners agree to

set production casing for the third well;

(v) US$224,853 within 10 calendar days of the spudding of the fourth well.

As of September 30, 2010, the Company has accumulated $785,190 (September 30, 2009 -

$1,423,204) of deferred exploration costs on the La Maye Block. As of September 30, 2010, the

Company also had advanced $905,739 of exploration advances which will be used to pay for the

Company’s 25% share of drilling costs of the second well and a portion of the third well. New

Horizon is the operator of the block. New Horizon has drilled one well (Noelia 1) and is in the

process of evaluating the next drilling location (Mike 4). The second well had to be drilled by

November 30, 2010, however, due to poor weather conditions, the operator applied to ANH for a

further extension of this deadline.

La Maye Operations Update

The La Maye Block, consisting of 73,959 acres (29,930 gross hectares), is located within the

Lower Magdalena Valley, Colombia, and adjoins the Cicuco Oil Field that has produced over 44

million barrels of oil and 181 billion cubic feet of gas, through June 2000, from 28 wells. Initial

production rates from the area ranged from 600 to 4,000 barrels of oil per day. Oil from the

Cicuco Oil Field is light, sweet crude, at 43 to 55 degrees API.

The Phase 1 minimum exploration program mandated by the Exploration and Production contract

was 12 months in duration and consisted of the reprocessing of 138 kilometers of existing seismic

data (completed) and the drilling of one exploration well to a minimum total depth of 5,000 feet

(completed). The first well Noelia 1 was drilled in November 2009 to a total depth of 3,341 feet

into basement. The top of the prospective Cienaga de Oro Cicuco Limestone was encountered

at 3,290 feet measured depth, 82 feet high to our prognosis. The well encountered several oil

and gas shows and has been cased for future testing.

Phases 2 through 6 of the Exploration and Production contract are 12 months each in duration.

One exploration well to be drilled through the prospective Cienega de Oro reservoir to an

approximate drilled depth of 4,200 feet is required during each phase. Currently, five drilling

prospects have been identified providing targets for the four well commitments during phases 2

through 6. The second exploration well M-4 (Phase 2) is planned to be drilled in the southern part

7

of the block. New Horizon, the Operator, expects to receive the environmental permit for the well

in the first calendar quarter of 2011, after which access roads to the location will be built and a rig

mobilized to drill the well. The M-4 well will be drilled in a stratigraphic structural trap and we

expect to encounter thick Cienega de Oro carbonates as well as potential clastic reservoir

intervals. After drilling of the second well, both wells are planned to be tested.

c) Block SSJN-5, Lower Magdalena Basin, Colombia

On December 18, 2008, the Company’s Colombian subsidiary, Petropuli, and SK Energy Co Ltd.

("SK Group") signed an Exploration and Production Contract with ANH for Block SSJN-5, located

in the Lower Magdalena Basin of Colombia. Petropuli and SK Group each hold a fifty percent

(50%) participating interest in Block SSJN-5, with SK Group acting as operator. The minimum

exploration program consists of two phases. Phase 1 and Phase 2 can last up to 36 months

each. In Phase 1, the Company’s net commitments consist of US$3,350,000 for seismic 3D and

US$2,500,000 for drilling of one exploratory well. In Phase 2, the Company’s net commitments

consist the cost of drilling of 4 additional exploratory wells for US$2,500,000 per well

(US$10,000,000 in total) and reprocessing of 2D seismic data for US$50,000. The Company has

the right to terminate its interest in Block SSJN-5 after fulfilling its minimum obligation of Phase 1.

Phase 1 commenced on June 18, 2009.

In January 2010, the Company provided a US$2,925,000 Standby Letter of Credit in favor of SK

Group as a security for Phase 1 exploration stage as required under the term of the Exploration

and Production Contract. In July 2010, upon closing of the farm-out agreement with

Petroamerica, the Company’s US$2,925,000 Standby Letter of Credit was replaced by an

equivalent Standby Letter of Credit provided by Petroamerica.

Farmout of a 25% interest in Block SSJN-5 to Petroamerica Oil Corp.

On October 6, 2009, the Company signed a farmout agreement with Petroamerica. Details are as

follows:

(i) The Company agreed to farmout to Petroamerica a 25% participating interest in Block

SSJN-5. In consideration for the farm in, Petroamerica has agreed to fund 100% of Petropuli's

participating interest share of the costs to complete the Phase 1 seismic program obligations on

the block.

The completion of this farm-out is subject to the receipt of approval from ANH. The Company will

apply for the ANH approval of the transfer of the 25% interest in Block SSJN-5 to Petroamerica

upon completion of the earn-in by Petroamerica.

(ii) The Company granted to Petroamerica an option to purchase Petropuli's remaining 25%

participating interest in Block SSJN-5 for US$3,000,000. That amount is payable, at the

Company’s sole election, in either cash or common shares of Petroamerica at the 30 day

weighted average closing price prior to the date the option is exercised. Petroamerica may

exercise the option by providing a written notice of exercise to the Company within 60 days of

Petroamerica receiving a copy of the final report of the 3D seismic program on Block SSJN-5.

(iii) Should Petroamerica exercise the option to purchase the remaining 25% interest they will

also grant to the Company an option to purchase US$3,000,000 of Petroamerica’s common

shares at a price per share being 20% higher than the 30 day weighted average closing price

immediately prior to date on which Petroamerica exercises its option to acquire the remaining

25% participating interest in Block SSJN-5. The Company may exercise this option at any time,

in whole or in part, within three years from the date the parties enter into the definitive agreement

to sell the initial 25% participating interest in Block SSJN-5. The Company’s right to exercise the

option is conditional upon the receipt of an independent third party reserve report stating that

gross proven and probable reserves of Block SSJN-5 exceed 50,000,000 barrels of oil or oil

equivalent.

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As of September 30, 2010, the Company has accumulated $1,818,455 (September 30, 2009 -

$417,139) of net exploration costs on Block SSJN-5.

Block SSJN-5 Operations Update

During the year ended September 30, 2009, the Company and SK Group incurred expenditures

on this block consisting mainly of paying to ANH an economic fee for Phase 1 and training

support costs. During the year ended September 30, 2010, technical data was acquired and

seismic reprocessing and testing was completed. All permits have been received for the planned

3D seismic program to be shot over the highest potential prospect, La Mocha Consuelo, located

in the southeastern portion of the block. The 3D seismic survey is planned to be completed by

March 31, 2011, at an estimated cost of US$18,450,000. As part of the farm-out terms,

Petroamerica Oil Corp. is committed to financing 50% of the total cost of the Phase 1 3D seismic

program, including the Company’s 25% share.

d) Block VMM-13, Middle Magdalena Basin, Colombia

On March 16, 2009, the Company’s Colombian subsidiary Petropuli signed an E&P Contract with

the ANH for Block VMM-13, located in the Middle Magdalena Basin in Colombia. The Company

is currently in discussions with ANH to return this block to ANH because of creation of a national

park over the prospective sections of the blockThe ANH is currently considering the proposal to

return this block. No significant amounts were spent to date on this block.

SUMMARY OF QUARTERLY RESULTS

The following is a summary of the results from the eight previously completed financial quarters (in

thousands of Canadian dollars, except per share amounts):

30-Sep-10 30-Jun-10 31-Mar-10 31-Dec-09 30-Sep-09 30-Jun-09 31-Mar-09 31-Dec-08

Interest

revenue $5 $7 $6 $9 $8 $18 $8 $80

Expenses $644 $588 $864 $566 $689 $567 $603 $689

Net loss $456 $581 $858 $557 $486 $596 $710 $834

Weighted

average

shares

outstanding

in '000 112,105 111,584 105,985 76,028 57,200 43,516 43,504 43,504

Loss per

share
.00
.01
.01
.01
.01
.01
.02
.02

Petroleum

and gas

expenditures

(recovery) 2,458 1,719 3,677 1,259 $1,626 $(33) $(499) $2,300

The Company’s operating losses are due to travel expenses, consulting, financing, administrative,

professional and legal fees incurred during the process of investigation, acquisition and developing of

numerous business opportunities and maintaining of assets in Brazil and Colombia, as well as financing

of head office operations.

ADDITIONAL DISCLOSURE FOR VENTURE ISSUERS WITHOUT SIGNIFICANT REVENUE

As the Company has no significant revenue from operations in either of its last three financial years, the

following is a breakdown of the material costs incurred:

9

Year ended

September 30,

2010

Year ended

September 30,

2009

Year ended

September 30,

2008

Petroleum and Natural Gas Exploration

and Development Costs, cash payments,

net

$8,729,053 $2,884,615 $5,807,597

Deferred Acquisition Costs $Nil $Nil $Nil

General and Administrative Expenses $1,525,255 $2,548,387 $2,890,749

Any Material Costs (capitalized, deferred or

expensed) not referred to above:

Exploration Advances (Recovery), cash

payments, net

$215,515 $(204,412) $894,636

DISCLOSURE OF OUTSTANDING SHARE DATA

The following table summarizes the maximum number of common shares outstanding as at September

30, 2010 and as of the date of this MD&A if all outstanding options and warrants were converted to

shares:

September 30,

2010

As of the date of

this MD&A

Common shares 112,146,115 118,125,526

Warrants to purchase common shares 56,782,744 57,862,155

Options to purchase common shares 6,165,000 5,865,000

Convertible loans payable – shares 17,647,059 14,117,647

Convertible loans payable – warrants 17,647,059 14,117,647

210,387,977 210,087,975

Escrow Shares

On September 11, 2006, 5,000,000 common shares were issued to directors and/or officers of the

Company at
.05 per share for total proceeds of $250,000. These shares were placed in escrow. On

the date of the Qualifying Transaction (April 9, 2008), an additional 2,616,667 shares held by the

Company’s directors and officers were placed in escrow, for a total of 7,616,667. These shares are being

released from escrow as follows: 10% upon completion of the Qualifying Transaction, and 15% every six

months following the Qualifying Transaction over the period of thirty six months. As of September 30,

2010, there were 2,285,500 shares remaining in escrow. Subsequent to September 30, 2010, additional

1,142,750 shares were released from escrow leaving 1,142,750 shares to be released on April 9, 2011.

RESULTS OF OPERATIONS

Quarter ended September 30, 2010 (“Q4 2010”) compared with the quarter ended September 30,

2009 (“Q4 2009”).

The loss for the quarter ended September 30, 2010 was $456,113 compared to $486,243 during the

quarter ended September 30, 2009. The decrease in the Q4 2010 net loss versus Q4 2009 is due to a

reduction of travel, consulting, salaries and benefits, stock based compensation, which were offset by an

increase in foreign exchange losses, office and administration costs and accretion of convertible loans

discount. Major differences between Q4 2010 and Q4 2009 include:

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- Accretion of convertible loans discount increased from $Nil in Q4 2009 to $61,457 in Q4 2010

due to issuance of $3,000,000 convertible loans in Q4 1010;

- director’s fees decreased from $73,516 in Q4 2009 to $19,332 in Q4 2010 as the 2009 annual

directors fees were accrued in Q4 2009 whereas 2010 directors fees have been accrued each

quarter during the fiscal year ended September 30, 2010;

- foreign exchange loss of $63,644 in Q4 2010 compared to a gain of $20,233 in Q4 2009 was

recorded due to the revaluation of subsidiaries operations from their home currencies to the

Canadian functional and reporting currency;

- Stock based compensation of $48,719 in Q4 2010 compared to $185,145 in Q4 2009 was lower

due to fewer options vesting during the period; and

Year ended September 30, 2010 compared with the year ended September 30, 2009.

The loss for the year ended September 30, 2010 was $2,452,752 compared to $2,625,829 during the

year ended September 30, 2009. The decrease in the current year net loss versus the prior year is due

to a reduction in many general and administrative costs (legal, salaries and benefits, public relations,

travel) in an effort to reduce corporate overhead, which was offset by an increase in interest and financing

fees due to obtaining various loans, as well as an increase in foreign exchange losses and a reduction of

interest income. Major differences between the years ended September 30, 2010 and 2009 include:

- legal fees decreased by $106,061 from $223,645 in 2009 to $117,584 in 2010 due to efforts to

reduce general and administrative costs by processing more legal work internally;

- salaries and benefits decreased by $194,690 from $439,999 in 2009 to $245,309 in 2010 due to

efforts to reduce general and administrative by reducing number of employees in Colombia and

USA;

- Interest and financing fees increased by $334,351 from $52,941 in 2009 to $387,292 in 2010

due to (1) the issuance of bonus shares valued at $180,000 to obtain a $1,000,000 short-term

loan and related interest expense, and (2) interest expense on a short-term loans and financing

fees related to arranging and maintaining of the US$2,925,000 Letter of Credit in favour of SK

Group as a security for block SSJN-5 Phase 1 exploration commitment. There were no debt

financings in the prior year;

- foreign exchange loss increased by $140,784 from $292,847 in 2009 to $433,631 in 2010 due to

fluctuation of foreign exchange rates impacting the revaluation of subsidiaries operations from

their home currencies to the Canadian functional and reporting currency;

- Stock based compensation decreased by $274,583 from $512,136 in 2009 to $237,553 in 2010

due to fewer options vesting during the current year; and

- Property evaluation costs decreased by $91,912 from $101,019 in 2009 to $9,107 in 2010 as the

Company focused on its existing projects portfolio and expended less effort investigating new

projects.

LIQUIDITY AND CAPITAL RESOURCES

The Company’s ability to meet its obligations and its ability to finance exploration and development

activities depends on its ability to generate cash flow through the issuance of common shares pursuant to

private placements, the exercise of warrants and stock options, short term or long term loans, farm-outs

and production. Capital markets may not always be receptive to offerings of new equity from treasury or

debt, whether by way of private placements or public offerings. This may be further complicated by the

limited liquidity for the Company’s shares, restricting access to some institutional investors. The

Company’s growth and success is dependent on additional external sources of financing which may not

be available on acceptable terms.

Working Capital

As of September 30, 2010, the Company’s working capital deficiency was $1,826,648, compared with a

$2,290,914 working capital deficiency as of September 30, 2009. The $464,266 decrease in working

capital deficiency is mainly due to decrease in accounts payable of $601,794 and decrease in amounts due

11

to related parties by $170,150, which was offset by decreased cash balance of $295,135 compared with

prior year.

Cash and Cash Equivalents

On September 30, 2010, the Company had cash and cash equivalents of $738,300 (September 30, 2009 -

$1,033,435). The $295,135 decrease in cash position is mainly due to spending $8,729,053 of cash on oil

and gas explorations, spending $215,515 on exploration advances, and spending $2,077,879 of cash on

operating activities, paying off $913,965 of accounts payable and $170,150 of amounts due to related

parties, which was offset by raising $8,870,356 through equity financing and $3,000,000 in loans.

Management of cash balances is conducted in-house based on internal investment guidelines, which

generally specify that investments be made in conservative money market instruments that bear interest

and carry a low degree of risk.

Cash Used in Operating Activities

Cash used in the operating activities during the year ended September 30, 2010 was $3,160,964,

compared with $475,805 of cash used in operating activities during the year ended September 30, 2009.

Cash was mostly spent on consulting, investor relations, administrative, legal, salaries, office rent and

accounting and audit costs. The $2,685,159 increase in cash spent on operating activities is mainly due to

current year payments of accounts payable and amounts due to related parties totaling $1,084,115,

compared with accumulation of payables in 2009 totaling approximately $1,765,000.

Cash Used in Investing Activities

Total cash used in investing activities during the year ended September 30, 2010 was $9,004,527

compared to $3,144,254 of cash used during the year ended September 30, 2009. The main increase in

cash used in investing activities is due to spending more cash on oil and gas explorations. During the

year ended September 30, 2010, the Company spent $8,729,053 (September 30, 2009 – $2,884,615) of

cash on oil and gas explorations in Colombia and Brazil, $215,515 (September 30, 2009 - $204,412

recovered) was spent on exploration advances, $2,147 (September 30, 2009 - $207,856) on property,

plant and equipment), and invested $57,812 (September 30, 2009 - $256,195) in short-term investments.

Cash Generated by Financing Activities

During the year ended September 30, 2010, the Company received $8,870,356 (September 30, 2009 –

($2,084,098) from the issuance of shares and $3,000,000 (September 30, 2009 - $Nil) from issuance of

convertible loans.

Requirement of Additional Equity Financing

The Company relies primarily on equity financings and farm-out transactions for all funds raised to date for

its operations. The Company needs more funds to finance its exploration and development programs and

ongoing operating costs. Until the Company starts generating profitable operations from extraction of

petroleum and natural gas, the Company intends to continue relying upon the issuance of securities to

finance its operations and acquisitions.

GOING CONCERN

The recoverability of any amounts shown for deferred oil and gas properties is dependent upon the

existence of and ability to monetize economically recoverable mineral oil and gas reserves, the ability of

the Company to obtain the necessary financing to complete the exploration and development of its

properties, and upon future profitable production or proceeds from the disposition of its properties.

While the Company’s consolidated financial statements have been prepared using Canadian generally

accepted accounting principles applicable to a going concern, which contemplates the realization of

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assets and settlement of liabilities in the normal course of business as they come due, certain conditions

and events cast significant doubt on the validity of this assumption. For the year ended September 30,

2010, the Company reported a loss of $2,452,752 and as at that date had a working capital deficiency of

$1,828,000 and an accumulated deficit of $11,995,323. In addition, the Company is committed to incur

minimum exploration expenditures on the Morichito and SSJN-5 Blocks in Colombia, and Blocks 169 and

170 in Brazil. The Company’s ability to continue as a going concern is dependent upon its ability to

obtain additional funding from loans or equity financings or through other arrangements. To raise funds

for operations, in August 2010, the Company completed a $3,000,000 convertible debt financing, the

Company is actively seeking additional private or institutional financing, and is in the process of farming

out a portion of its interest in Block SSJN-5 in Colombia. However, there can be no assurance that these

activities will be successful.

The Company’s consolidated financial statements do not reflect the adjustments to the carrying values of

assets and liabilities and the reported expenses and balance sheet classifications that would be

necessary were the going concern assumption deemed to be inappropriate. These adjustments could be

material.

OFF BALANCE SHEET ARRANGEMENTS

The Company does not have any off-balance sheet arrangements.

TRANSACTIONS WITH RELATED PARTIES

Related party transactions and balances are as follows:

(a) During the year ended September 30, 2010, the Company paid or accrued $608,249 (September 30,

2009 - $654,053) of salaries and consulting fees to directors, officers, and companies controlled by

directors and officers of the Company. Out of total amount paid/accrued, $264,241 (September 30,

2009 - $281,473) has been included in deferred petroleum and natural gas costs, $143,538 (September

30, 2009 - $168,907) has been expensed on the statement of loss as salaries, and $200,469

(September 30, 2009 - $203,673) has been expensed on the statement of loss as consulting fees. The

Company paid $33,000 (September 30, 2009 - $45,000) for office rent to a company controlled by a

director and officer of the Company. The Company also paid/accrued $82,332 (September 30, 2009 -

$73,516) in directors fees to directors of the Company.

(b) As of September 30, 2010, amount due to related parties of $16,212 (September 30, 2009 - $186,362)

was payable to directors of the Company. This liability is non-interest bearing and has no terms of

repayment.

(c) On December 10, 2009, the Company borrowed $1,000,000, including $500,000 from a spouse of a

director of the Company. As a bonus to the lenders, the Company issued 1,000,000 bonus shares,

which for accounting purposes were valued at
.18 per share using the Company’s closing stock

trading price on the date of issuance of these shares. The loans were unsecured, bearing interest at

12% per annum and were due on April 30, 2010. $500,000 of the loans plus interest were repaid in

March 2010, and the remaining $500,000 balance plus interest were repaid in August 2010. Total

amount of interest paid to a spouse of a director of the Company was $29,157.

(d) On August 27, 2010, the Company completed a $3,000,000 financing of convertible promissory notes

(“Convertible Notes”). The Convertible Notes are unsecured, bear interest at 10% per annum, and

are due within two years from the date of issuance. At the option of the lenders, the principal amount

of the Convertible Notes can be converted into units of the Company at the rate of one unit for each

.17 of principal amount. Each unit will be comprised of one common share of the Company and

one transferable warrant, with each such warrant being exercisable to purchase one common share

of the Company at a price of
.20 per share on or before August 27, 2012. Accrued interest is not

compounded, and is payable in cash upon maturity date, conversion date or repayment date of the

Convertible Notes, whichever is earlier. $500,000 of the Convertible Notes was issued to a spouse of

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the Company’s director. As of September 30, 2010, accrued interest on the $500,000 loan from the

related party was $4,658.

The above transactions occurred in the normal course of operations, are measured at the exchange

amount, which is the amount of consideration established and agreed to by the related parties.

SUBSEQUENT EVENTS

In addition to subsequent events described elsewhere in this MD&A, the following significant subsequent

events took place:

a) On December 10, $600,000 of the Convertible Notes, including $500,000 of the Convertible Notes

held by a spouse of the Company’s director, were converted to 3,529,411 shares and 3,529,411

share purchase warrants. On the same date, 1,750,000 share purchase warrants were exercised at

.20 per share for total cash proceeds of $350,000.

b) On January 6, 2011, 700,000 warrants expiring on August 6, 2011 were exercised at
.15 per

share for total proceeds of $105,000.

FINANCIAL INSTRUMENTS

The Company recognizes financial assets that are held for trading or available for sale, financial liabilities

that are held for trading and all derivative financial instruments at fair value. Other financial assets, such

as loans and receivables and investments that are held to maturity and other financial liabilities are

measured at their carrying value. The Company is exposed to potential loss from various risks including

credit risk, currency risk, interest rate risk, liquidity risk, market risk, political risk and commodity price risk.

These risks are described in more details in Risk and Uncertainties section of this MD&A.

RISK AND UNCERTAINTIES

Petroleum and Natural Gas Prices – The Company’s future success is linked to the price of petroleum

and natural gas prices, because its future revenues will be derived from the extraction and sale of

petroleum and natural gas reserves. The Company estimates the future price of petroleum and natural

gas based on historical trends and published forecasted estimates. The prices are affected by numerous

factors beyond the Company’s control, including the relative exchange rate of the US dollar with the

Brazilian, Colombian and Canadian currencies, global and regional demand for petroleum and natural

gas, and political and economic conditions. Worldwide production levels also affect the prices. The prices

of petroleum and natural gas are occasionally subject to rapid short-term changes due to speculative

activities.

Exploration and Development – Exploration activities require large amount of capital. There is a risk

that during the current difficult economic situation the Company will not be able to raise sufficient funds to

finance its projects to a successful development and production stage. While the Company’s

management and technical team carefully evaluate all potential projects prior to committing the

Company’s participation and funds, there is a high degree of risk that the Company’s exploration effort

will not result in discovering economically recoverable petroleum and natural gas reserves.

Environmental Risk - Exploration and development of oil and gas properties present environmental

hazard and are subject to environmental regulations in Brazil and Colombia. The Company hires qualified

individuals to ensure these regulations are complied with. However, there is a risk that these regulations

are not fully complied with, which may result in fines and penalties.

Political Risk – The Company conducts exploration activities in Colombia and Brazil. These operations

are potentially subject to a number of political, economic and other risks that may affect the Company’s

future operations and financial position.

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Credit Risk – Credit risk is the risk that one party to a financial instrument will fail to fulfil an obligation

and cause the other party to incur a financial loss. The Company’s credit risk consists primarily of cash

and cash equivalents and short-term investments. The credit risk is minimized by placing cash and cash

equivalents and short-term investments with major Canadian, United States, Brazilian and Colombian

financial institutions. The Company does not invest in asset–backed commercial papers.

Currency Fluctuations - The Company operates in numerous countries, mainly Canada, US, Colombia

and Brazil; therefore the Company’s operations are affected by currency fluctuations in these

jurisdictions. Based on the balances as at September 30, 2010, a 1% increase (decrease) in the

exchange rates on that date would have resulted in a (decrease) increase of approximately $13,863

(September 30, 2009 - $27,000) in earnings before income taxes.

Liquidity Risk – There is a risk that the Company will not be able to meet its financial obligations when

they become due if additional capital is not available to the Company when required. To mitigate this risk,

the Company has a planning and budgeting process in place to determine the funds required to support

its ongoing operations and capital expenditures. The Company actively searches for equity or debt

financings to meet its operating requirements.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with Canadian generally accepted accounting

principles requires management to make estimates and assumptions that affect the reported amounts of

assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial

statements and the reported amounts of revenues and expenses during the reported years. Actual

results could differ from those estimates.

The amounts recorded for amortization of property, plant and equipment, the provision for asset

retirement obligations, the provision for future income taxes, impairment analysis of petroleum and natural

gas properties, valuation allowance for future income taxes, purchase price allocation between assets

and liabilities of acquired subsidiaries, stock based compensation and valuation of warrants are based on

estimates. By their nature, these estimates are subject to measurement uncertainty and the effect on the

financial statements of changes in such estimates in future periods could be significant.

All stock-based awards made to employees and non-employees are measured and recognized using a

fair value based method. Accordingly, the fair value of the options at the date of the grant is accrued and

charged to operations, with the offsetting credit to contributed surplus, on a straight-line basis over the

vesting period. If and when the stock options are ultimately exercised, the applicable amounts of

contributed surplus are transferred to share capital.

The proceeds from the issue of units is allocated between shares and warrants on a prorated basis on

relative fair values as follows: the fair value of common shares is based on the market close on the date

the units are issued; and the fair value of the common share purchase warrants is determined using the

Black-Scholes pricing model.

NEW ACCOUNTING POLICIES

A detailed summary of all the Company's significant accounting policies is included in Note 2 to the

audited annual consolidated financial statements for the year ended September 30, 2010. The following

are recent and future accounting pronouncements:

Business Combinations/Consolidated Financial Statements / Non-Controlling Interests - The

AcSB adopted CICA sections 1582 Business Combinations, 1601 Consolidated Financial Statements,

and 1602 Non-Controlling Interests which superseded current sections 1581 Business Combinations and

1600 Consolidated Financial Statements. Section 1601 provides revised guidance on the preparation of

consolidated financial statements and Section 1602 addresses accounting for non-controlling interests in

consolidated financial statements subsequent to a business combination. These new sections replace

existing guidance on business combinations and consolidated financial statements to harmonize

Canadian accounting for business combinations with IFRS. These Sections will be applied prospectively

15

to business combinations for which the acquisition date is on or after the beginning of the first annual

reporting period beginning on or after January 1, 2011. Earlier adoption is permitted. The Company will

be required to adopt these Sections effective October 1, 2011. The Company is currently evaluating the

impact of the adoption of these changes on its consolidated financial statements.

International Financial Reporting Standards (“IFRS”) - In 2006, the Canadian Accounting Standards

Board ("AcSB") published a new strategic plan that will significantly affect financial reporting requirements

for Canadian companies. The AcSB strategic plan outlines the convergence of Canadian generally

accepted accounting principles (“GAAP”) with IFRS over an expected five year transitional period. In

February 2008, the AcSB announced that the changeover date for publicly-listed companies to use IFRS,

replacing Canada's own GAAP, is for interim and annual financial statements relating to fiscal years

beginning on or after January 1, 2011.

The Company will be required to adopt IFRS effective October 1, 2011. The transition date of October 1,

2010 will require the restatement for comparative purposes of amounts reported by the Company for the

year ended September 30, 2011.

IFRS transition plan:

The Company has established a comprehensive IFRS transition plan. There are four phases that will be

followed to ensure compliance with IFRS as follows: (1) Impact Assessment (2) Detailed Planning (3)

Implementation and (4) Post Implementation Review. The Company is currently in Detailed Planning and

Implementation stages.

Impact of adopting IFRS on the Company’s financial statements

The adoption of IFRS will result in some changes to the Company’s accounting policies that are applied in

the recognition, measurement and disclosure of balances and transactions in its financial statements.

IFRS requires additional disclosures in a number of areas including estimates, related party transactions,

income taxes and impairment. In the year of adoption of IFRS, additional disclosures are required to

show the transition from GAAP to IFRS for the opening balance sheet figures as of October 1, 2010.

Reconciliations of equity and earnings (loss) are required with disclosure of the key differences. The

opening balance sheet figures will also need to be audited by the Company’s auditors. To comply with

these requirements, the Company will gather additional information and the current reporting processes

will be modified to provide the appropriate level of detail in order to prepare the Company’s consolidated

financial statements under IFRS.

The following provides a summary of the Company's evaluation of potential changes to accounting

policies in key areas based on the current standards and guidance within IFRS. This is not intended to be

a complete list of areas where the adoption of IFRS will require a change in accounting policies, but to

highlight the areas the Company has identified as having the most potential for a significant change.

First Time Adoption (IFRS 1)

IFRS 1 provides guidance to entities on the general approach to be taken when first adopting IFRS. The

underlying principle of IFRS 1 is retrospective application of IFRS standards in force at the date an entity

first reports using IFRS. IFRS 1 acknowledges that full retrospective application may not be practical or

appropriate in all situations and prescribes:

- Optional exemptions from specific aspects of certain IFRS standards in the preparation of the

Company’s opening balance sheet; and

- Mandatory exceptions to retrospective application of certain IFRS standards.

The Company has not yet decided which optional exemptions available under IFRS 1 it will adopt in

preparation of its opening IFRS statement of financial position as of October 1, 2010, the Company’s

16

transition date. The Company will make its decision prior to reporting interim financial statements in

accordance with IFRS for the quarter ended December 31, 2011.

IFRS 1 does not permit changes to estimates that have been made previously. Accordingly, estimates

used in the preparation of the Company’s opening IFRS statement of financial position will be consistent

with those made when preparing the Company’s financial statements under current GAAP.

Business combinations completed prior to October 1, 2010 will not be retrospectively restated using IFRS

principles.

Impairment (IAS 36 and IFRS 6)

IAS 36 provides guidance for impairment of assets and IFRS 6 provides guidance for impairment of

exploration and evaluation costs of mineral resources and oil and gas costs. Under IFRS, impairment

losses are recognized when the carrying value exceeds the recoverable amount (higher of value in use or

fair value less costs to sell). IFRS requires the use of a one-step impairment test (impairment testing is

performed using discounted cash flows) rather than the two-step test under GAAP (using undiscounted

cash flow as a trigger to identify potential impairment loss), consequently, under IFRS, recognition of

impairment losses may be more frequent than under GAAP. IFRS requires reversal of impairment losses

where previous adverse circumstances have changed; this is prohibited under GAAP. Impairment testing

should be performed at the asset level for long-lived assets and intangible assets. Where the recoverable

amount cannot be estimated for individual assets, it should be estimated as part of a Cash Generating

Unit.

The Company’s accounting policies related to impairment test will be changed to reflect these differences;

however, the Company does not expect this change will have an impact to the carrying value of its

assets. The Company will perform impairment assessments as at the transition date in accordance with

IFRS.

Share-based payments (IFRS 2)

Under GAAP (CICA 3870 – Stock-based Compensation and Other Stock-based Payments), the

Company grants share options to directors, officers, employees and non-employees and accounts of

them using the fair value method of accounting. The fair value of the options at the date of the grant is

determined using the Black-Scholes option pricing model and stock-based compensation (“SBC”) is

accrued and charged to operations, with an offsetting credit to contributed surplus, on a straight-line basis

over the vesting periods. The fair value of stock options granted to non-employees is re-measured at the

earlier of each financial reporting or vesting date, and any adjustment is charged or credited to operations

on re-measurement. If and when the stock options are exercised, the applicable amounts of contributed

surplus are transferred to share capital. The Company has not incorporated an estimated forfeiture rate

for stock options that will not vest; rather the Company accounts for actual forfeitures as they occur.

Per IFRS (IFRS 2 – Share-based Payments), the forfeiture rate, with respect to share options, needs to

be estimated by the Company at the grant date instead of recognizing the entire compensation expense

and only record actual forfeitures as they occur. The estimated forfeiture rate should be revised if

subsequent information indicates that actual forfeitures are likely to differ from previous estimates.

Under IFRS, for graded-vesting of options, each instalment needs to be treated as a separate share

option grant, because each instalment has a different vesting period, and hence the fair value of each

instalment will differ.

The definition of “employees and others providing similar services” in IFRS 2 is a broader concept than

that of employees and non-employees under GAAP. The IFRS definition includes individuals who render

services to the entity similar to those rendered by employees (this includes non-executive directors).

17

IFRS requires equity instruments issued to employees be measured on the grant date. Equity

instruments granted to parties other than employees should be measured on the date that the goods or

services are received.

The Company does not expect that changes to the Company’s accounting policies related to share-based

payments will result in a significant change to line items within its financial statements.

Income taxes (IAS 12)

The basic principles of accounting for income tax are the same under both IFRS (IAS 12 – income Taxes)

and GAAP (CICA 3465 – Income Taxes). However, there are some differences.

Under IFRS, the recognition of future income tax assets or liabilities that arise from the initial recognition

of assets or liabilities that do not impact profit or loss and other than in a business combination is

prohibited. There is no initial recognition exception under GAAP.

Under IFRS, all deferred tax assets and liabilities are classified as non-current. Under GAAP, future

income tax assets and liabilities are classified as either current or non-current depending upon the

classification of the underlying asset or liability.

IFRS requires the tax effects of items credited or charged to equity during the current year also be

allocated directly to equity. Subsequent changes in those amounts should also be allocated to equity

where practical. Under GAAP, the cost (benefit) of current and future income taxes is recognized as

income tax expense included in the determination of net income or loss for the period before discontinued

operations and extraordinary items. However, under GAAP, specific exemptions include taxes related to

discontinued operations, extraordinary items, capital transactions and items charged or credited directly

to shareholder’s equity.

The Company does not presently have any current future income tax assets or liabilities, therefore the

requirement to classify all future tax assets and liabilities as non-current items will not have any impact of

the Company’s current working capital position. The disclosure requirements of IAS 12 are more

extensive than existing Canadian GAAP. However, no major restatements of opening balance sheet are

expected on the transition date.

Property plant and equipment (“PP&E”) (petroleum and natural gas properties) - (IFRS 6)

Under GAAP, the Company uses full cost accounting in which all costs directly associated with the

acquisition of, the exploration for, and the development of natural gas and crude oil reserves are

capitalized on a country-by-country cost center basis. Under GAAP, costs accumulated within each

country cost center would be depleted using the unit-of-production method based on proved reserves

determined using estimated future prices and costs. Upon transition to IFRS, the Company will be

required to adopt new accounting policies for pre-exploration costs, exploration and evaluation costs and

development costs.

Pre-exploration costs are those expenditures incurred prior to obtaining the legal right to explore and

must be expensed under IFRS. Currently, the Company capitalizes pre-exploration costs within the

country cost center. To date, capitalized pre-exploration costs are not material to the Company.

Exploration and evaluation costs are those expenditures for an area or project for which technical

feasibility and commercial viability have not yet been determined. Under IFRS, the Company will initially

capitalize these costs as Intangible Exploration Assets on the balance sheet. When the area or project is

determined to be technically feasible and commercially viable, the costs will be transferred to PP&E.

Unrecoverable exploration and evaluation costs associated with an area or project will be expensed.

18

Development costs include those expenditures for areas or projects where technical feasibility and

commercial viability have been determined. Under IFRS, the Company will capitalize these costs within

PP&E on the balance sheet, as is currently required by Canadian GAAP.

Under IFRS, depletion and depreciation of property and equipment ("PP&E") will be calculated at a

"significant component level" as opposed to the current country cost center level under existing GAAP.

The existing full cost pool of deferred oil and gas costs under Canadian GAAP will be separated into

components and depleted individually at the “significant component level”. Although depletion will

continue to be calculated using the unit-of-production method under IFRS, the Company has the option to

calculate depletion using proven plus probable reserves. The Company has yet to determine geographic

or geologic areas and other inputs to be utilized in determining “significant component level” which will be

used in the unit-of-production depletion calculation.

Under Canadian GAAP, proceeds from sale of interest in oil and gas properties are normally deducted

from the full cost pool without recognition of a gain or loss unless the deduction would result in a change

to the depletion rate of 20 percent or greater, in which case a gain or loss would be recorded. Under

IFRS, sale of Intangible Exploration Assets follow the same treatment as GAAP while producing

properties will generally result in a gain or loss recognized in net earnings.

The Company expects to adopt the IFRS 1 exemption, which allows the Company to deem its oil and gas

costs to be equal to its current GAAP historical net book value. On October 1, 2010, the IFRS Intangible

Exploration Assets are expected to be equal to the Company’s current Petroleum and Natural Gas

Properties costs balance and the IFRS Development costs will be $Nil as the Company is currently in the

exploration stage.

Asset retirement obligations (“ARO”) (IAS 37)

IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” provides guidance for ARO under

IFRS. IFRS defines site restoration and environmental provisions as legal or constructive obligations;

Canadian GAAP limits the definition primarily to legal obligations. IFRS requires the liability to be the

present value of the forecast expenditures at each reporting date and therefore a discount rate reflecting

current market assessments of the time value of money and the risks specific to the liability must be used.

Accretion expense is recorded as a financing cost under IFRS rather than as an element of operating

costs. IFRS requires translation of ARO denominated in currencies other than the functional currency of

the Company at the current exchange rate at each reporting date rather than the historic rate used under

Canadian GAAP. Increased efforts will be required to update provisions at each balance sheet date for

changes in the estimate of the discount rate, which will increase the volatility of the provision. Additional

AROs may be recorded to include constructive obligations increasing the provision.

Convertible loans (IAS 32)

IAS 32, “Financial Instruments – Presentation” provides guidance for financial instruments, to distinguish

between equity and non-equity instruments, and to account for compound financial instruments such as

convertible loans. Under IFRS, fair value of convertible loans is allocated between liability and equity by

first determining fair value of the liability component, with the residual value being allocated to the equity

component. GAAP provides multiple measurement choices in determining allocation of proceeds

between liability and equity components. Under GAAP, the Company used relative fair value methods by

allocating proceeds from convertible loans financings between liability and equity components using a

pro-rata method based on the fair value of loans and fair value of warrants on the date of issuance of the

convertible loans. The fair value of warrants was estimated using the Black-Scholes pricing model. This

method is not allowed under IFRS; consequently, the Company will need to restate the liability and equity

components of the convertible loans on the opening balance sheet date as of October 1, 2010 to comply

with IFRS using IAS 32 guidance. The Company did not yet determine impact of this restatement on the

liability, equity and deficit components of its financial statements.

19

Impact on the internal controls over financial reporting

The Company will make the appropriate changes to maintain the integrity of the Company’s internal

controls over financial reporting for the initial transition to IFRS, including the related note disclosures, as

well as on-going financial reporting. The Company will ensure that the appropriate management oversight

in place and appropriate management review and approval is obtained for all additional financial and

other material disclosures. The Company’s accounting personnel will be trained in IFRS, and the Audit

Committee is assessing the Board of Director’s IFRS knowledge and any additional training that may be

required.

Impact on the business

The Company has reviewed its significant business activities to date and believes that none of these will

be impacted by the transition to IFRS. The Company does not currently have any compensation

arrangements tied to earnings, any hedging activities, any debt with covenants or Stock Option Plan tied

to financial performance, ratios or financial targets; therefore the Company does not expect business

activities to be impacted by the transition to IFRS. Business process will be monitored during the following

months to detect and address any previously not identified IFRS conversion issues.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this MD&A may constitute forward-looking statements. These

statements relate to future events or the Company's future performance. All statements, other than

statements of historical fact, may be forward-looking statements. Forward-looking statements are often,

but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate",

"expect", "may", "will", "project", "predict", “propose”, "potential", "targeting", "intend", "could", "might",

"should", "believe" and similar expressions. These statements involve known and unknown risks,

uncertainties and other factors that may cause actual results or events to differ materially from those

anticipated in such forward-looking statements. The Company believes that the expectations reflected in

those forward-looking statements are reasonable but no assurance can be given that these expectations

will prove to be correct and such forward-looking statements included in this MD&A should not be unduly

relied upon by investors as actual results may vary. These statements speak only as of the date of this

MD&A and are expressly qualified, in their entirety, by this cautionary statement.

In particular, this MD&A contains forward-looking statements, pertaining to the following: capital

expenditure programs, development of resources, treatment under governmental regulatory and taxation

regimes, expectations regarding the Company's ability to raise capital, expenditures to be made by the

Company to meet certain work commitments, and work plans to be conducted by the Company.

With respect to forward-looking statements listed above and contained in this MD&A, the Company has

made assumptions regarding, among other things: the legislative and regulatory environment, the impact

of increasing competition, unpredictable changes to the market prices for oil and natural gas, that costs

related to development of the oil and gas properties will remain consistent with historical experiences,

anticipated results of exploration activities, and the Company's ability to obtain additional financing on

satisfactory terms.

The Company's actual results could differ materially from those anticipated in these forward-looking

statements as a result of the risk factors set forth in this MD&A: volatility in the market prices for oil and

natural gas, uncertainties associated with estimating resources, geological problems, technical problems,

drilling problems, processing problems, liabilities and risks including environmental liabilities and risks

inherent in oil and natural gas operations, fluctuations in currency and interest rates, incorrect

assessments of the value of acquisitions, unanticipated results of exploration activities, competition for

capital, competition for acquisitions of reserves, competition for undeveloped lands, competition for skilled

personnel, political risks and unpredictable weather conditions.

ADDITIONAL INFORMATION

For further detail, see the Company’s audited consolidated financial statements for the year ended

September 30, 2010. Additional information about the Company can also be found on www.sedar.com.

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CORPORATE DIRECTORY

Trading Symbol – PTV
Legal Counsel, Canada

Exchange - TSX-V
DuMoulin Black LLP

10th Floor 595 Howe St

Head Office
Vancouver, BC

Petro Vista Energy Corp.

595 Howe Street, Suite 900
Legal Counsel, Brazil

Vancouver, BC V6C 2T5, Canada
Leite, Tosto e Barros Advogados Associados

Tel: [phone]
52, 23 ander, sala 2302

Fax: [phone]
Centro, Rio de Janeiro, RJ, Brazil

Legal Counsel, Barbados

Hampton Chambers, Hampton House

Officers and Directors
Erdiston Hill, St. Michael, Barbados