News!! MD&A
PETRO VISTA ENERGY CORP.
Management Discussion and Analysis (“MD&A”)
for the nine months ended June 30, 2011
The following discussion and analysis of the operations, results, and financial position of the Company for
the nine months ended June 30, 2011 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 August 29, 2011. All figures are presented in Canadian dollars, unless
otherwise indicated.
THE COMPANY
Petro Vista Energy Corp. (the “Company” or “PVE” or “Petro Vista”) currently has an interest in one
development and two exploration blocks in Brazil (respectively, Tartaruga, Block 169 and Block 170) and
one development and two exploration blocks in Colombia (respectively, Morichito, La Maye and SSJN-5).
Petro Vista Energy Corp., 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 and
Tartaruga, 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 and development activities in Brazil and Colombia. The
following is a summary of the Company’s oil and gas interests (additional details are provided throughout
the MD&A):
Exploration and Development
Brazil
As of June 30, 2011, the Company held an interest in one development and two exploration blocks in
Brazil. Summary is as follows:
a) Tartaruga Block, 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 a cost of 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. In February 2011 the Company has fulfilled its farm-in obligations by paying its
remaining share of drilling costs.
The farm in and corresponding assignment of working interest in the Tartaruga Block is subject to
several conditions, including approval from the consortium members and the ANP. The Company
is in the process of applying for these approvals.
As of June 30, 2011, the Company had accumulated $6,921,213 (September 30, 2010 -
$6,592,911) of deferred exploration costs related to this block, net of $350,443 of depletion costs.
Tartaruga Operations Update
The Tartaruga Block is located in Brazil's prolific Sergipe-Alagoas Basin, north-eastern Brazil.
One existing well on the block (well SES-107D) 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
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logs. In December 2009, a fluid treatment was performed on this well to increase production. An
additional workover is planned for this well during 2011, aimed at increasing the wells rate of
production.
UPB as the operator of the Tartaruga Block and drilled a new sidetrack development well (7-
TTG-1DP-SES) which reached total depth (3,445m) in April 2010. This 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).
In December 2010, environmental and production permits were received for well 7-TTG-1DPSES.
In February 2011 the deepest Penedo reservoir (P13) interval was perforated from 3400-
3407.5 meters (measured depth). Although the well initially flowed, after various mechanical
issues it ceased producing and, despite further efforts, would not flow again. Although it appears
to be a zone that will produce with the assistance of mechanical lift, it was decided to move
uphole and test the Penedo P6 reservoir. That zone was perforated from 3235-3268 meters
overall and swabbed until it started flowing. Initial restricted flow rates on a 10/64 inch choke
were 744 barrels of 41.50 API oil per day. The block’s operator is in the process of upgrading
existing facilities to enable it to handle higher production rates.
Five other prospective Penedo zones remain to be tested and produced at a later date.
The operator has proposed a workover of the SES-107D well during the fourth quarter of
calendar year 2011. The Company’s share of that work will be approximately $214,500.
Tartaruga Production
Production from the new Tartaruga well 7-TTG-1DP-SES commenced on February 14, 2011.
During the nine month period ended June 30, 2011, the Company has accrued gross production
revenue from both producing wells of $2,134,491 (quarter ended June 30, 2011 - $1,393,196),
less royalty expense of $446,197 (quarter ended June 30, 2011 - $290,839) and $785,463
(quarter ended June 30, 2011 - $580,450) of operating costs for net production income before
depletion of $902,831 (quarter ended June 30, 2011 - $521,907). The Company’s 37.5% share of
gross production for the nine months ended June 30, 2011 was 19,626 (quarter ended June 30,
2011 – 12,674) barrels of oil at an average price of $108.76 per barrel (quarter ended June 30,
2011 – $109.93). This revenue will be realized, and payment will be received, upon approval of
the Agencia Nacional do Petroleo, Gas Natural e Biocombustiveis (“ANP”).
The farm in and corresponding assignment of interests is subject to the approval from the
consortium members and the ANP. The Company is in the process of applying for these
approvals.
b) 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 due to the
inability to negotiate land access from the landowner’s estate. 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 June 30, 2011, the Company had accumulated
$103,168 (September 30, 2010 – $103,168) of acquisition and exploration costs on these blocks.
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Colombia
As of June 30, 2011, the Company held an interest in one development and two exploration blocks in
Colombia. Summary is as follows:
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.
Petropuli is the operator of the Morichito Block. During the nine months ended June 30, 2011,
the Company incurred $6,354,486 (September 30, 2010 - $6,520,730) of drilling and other
exploration costs, and has recovered $2,764,073 (September 30, 2010 - $4,425,064) of these
costs from its partners. As of June 30, 2011, the Company has accumulated $6,740,305
(September 30, 2010 – $6,740,305) of acquisition costs, $9,603,567 (September 30, 2010 -
$6,013,154) of net exploration costs, and $2,366,519 (September 30, 2010 - $2,366,519) of
deferred future income tax costs related to the Morichito Block. As at June 30, 2011, Petropuli
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 first US$1,050,000 of drilling costs of
M1N well.
This option agreement is conditional upon Petropuli obtaining approval from the Agencia Nacional
de Hibrocarburos (“ANH”) to assign a 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.
Farmout of a 35% interest in the Morichito Block to Golden Oil Corp.
By an agreement dated March 6, 2009, Golden Oil Corp. (“Golden”) acquired the 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.
5
Morichito Operations Update
Under the terms of the E&P 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, the Company completed Phase 4 by drilling the third exploratory well 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 18 feet.
Swab testing and drill stem tests have been carried out on one Mirador and on Carbonera C7
reservoir. 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). 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. A third potential pay zone,
the Carbonera C1 formation, was also identified and is productive in the area.
The Company has completed initial production testing of the M5 well 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. Last production test utilizing a hydraulic pump was at a rate of 684 bbls of 23.50
crude. The well was then shut in to obtain bottom hole pressures which will help the Company
evaluate the type and size of pump to be used for production. Production from well M5 is
expected to commence in the 4th quarter of calendar year 2011.
In March 2011, the Company completed its Phase V work commitment by drilling a fourth deeper
pool exploratory well, the M5B well. The M5B well was drilled from the same pad as the
Company’s M5 well. The well was deviated approximately 1,200 feet to the southwest of the
original well M5 well and was drilled to a T.D. of 6855 feet in the Paleozoic. During drilling, mudlog
shows and petrophysical analysis of electric and porosity logs indicate potential pay zones in
the Carbonera C7, Guadalupe and Ubaque. Seven inch casing was run with the plan to test the
Ubaque and C7 zones; however a failed cement job precluded such testing and the well has
been temporarily suspended. The company is in discussions with the contractor regarding a
replacement well or sidetrack of the existing well at their sole cost.
The Company is currently in Phase 6, the final exploration phase under the E&P Contract. In this
Phase, the Company will complete a 3D seismic program in lieu of drilling another well at an
estimated cost to the Company of U$1,750,000. Due to flooding prohibiting operations on the
Block, Phase 6 completion deadline has been extended by ANH by 60 days, and the new expiry
date is now November 29, 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 this 25%
interest, the Company agreed to pay to New Horizon an aggregate of US$2,062,500,
representing 25% of estimated costs of a four well / four phase 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 contribution of US$1,146,197 is to 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.
6
As of June 30, 2011, the Company has accumulated $802,009 (September 30, 2010 - $785,190)
of deferred exploration costs on the La Maye Block. As of June 30, 2011, 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.
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 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. This was completed
with the Noelia 1 well which 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. Access to the location has been restricted due
to flooding and testing has been postponed, probably until the end of 2011. The operator is
meeting with the National Hydrocarbon Agency and Ministry of Mines and Energy to maintain all
permits and licenses.
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 well commitments during phases 2
through 6. The second exploration well M-4 (Phase II) is planned to be drilled in the southern part
of the Block. New Horizon, the operator, has been working with the Colombia Ministries of Mines
and Environment to receive the environmental permit for the well, after which access roads to the
location will be built and a rig mobilized to drill the prospect. 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. The second well (M-4) was to be drilled by November 30,
2010, however, due to extremely poor weather conditions the operator has received from the
ANH extensions of this deadline. In May 2011, the drilling deadline was suspended due to
extensive flooding until the Ministry of Environment is able to access the proposed well site as
part of its permitting process. Once the Ministry of Environment gains access to the site, the ANH
will provide the operator with the new completion deadline for Phase II. The Company expects,
based on seasonal weather, that drilling of second well M-4 will now take place in the 1st or 2nd
calendar quarter of 2012.
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 initially each held 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 25% share of net commitments consist of
US$3,621,000 for seismic 3D, US$1,368,000 for drilling of one exploratory well and $472,000 for
other costs. It is expected that the Company’s portion of seismic 3D costs will be financed by
Petroamerica pursuant to a farm-out of a 25% working interest in Block SSJN-5 (see below). As
of March 31, 2011, Petroamerica contributed U$8,291,965 towards the seismic 3D program,
including the Company’s 25% share of costs totalling US$3,379,980. In Phase 2, the Company’s
25% share of net commitments consist the cost of drilling of 4 additional exploratory wells for
7
US$1,250,000 per well (US$5,000,000 in total). 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 and ends on or before June 18, 2012.
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 Oil Corp.
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 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 and an option to purchase US$3,000,000
of Petroamerica common shares (as discussed in (iii) below). The US$3,000,000 is payable, at
the Company’s sole election, in either cash or common shares of Petroamerica at the 30 day
weighted average closing price of Petroamerica’s common shares 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 on the 3D seismic
program on Block SSJN-5. The 3D seismic report was provided to Petroamerica on July 11,
2011, therefore this option expires on September 9, 2011.
(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 common share that is 20% higher than the 30 day weighted average closing
price of the Petroamerica common shares 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.
As of June 30, 2011, the Company has accumulated $810,924 (September 30, 2010 - $774,388)
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 an economic fee to the ANH 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. In April 2011, a 3D seismic program was
completed over the highest potential prospect, La Mocha/Consuelo, located in the southeastern
portion of the block. The 3D seismic survey results are being analyzed and a final report was
received in mid July 2011. As part of the farm-out terms, Petroamerica Oil Corp. financed 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 the ANH because of creation of a
national park over the prospective sections of the Block. In May 2011, the Company received
8
notification from the ANH of its intent to nullify the E&P Contract by mutual agreement.
Cancellation of the E&P Contract is expected to be completed over the next few months. No
significant funds were invested on this block.
Summary of Exploration and Development Costs
The summary of deferred oil and gas costs as of June 30, 2011 is as follows:
As of June 30, 2011 Brazil Colombia Total
Acquisition costs $ - $ 6,740,305 $ 6,740,305
Exploration and development costs 7,374,823 11,216,499 18,591,322
Future income tax related to above - 2,366,519 2,366,519
Costs 7,374,823 20,323,323 27,698,146
Depletion (350,443) - (350,443)
Net book value $ 7,024,380 $ 20,323,323 $ 27,347,703
Details of activities for the nine months ended June 30, 2011 are as follows:
Brazil Colombia Total
Balance – September 30, 2010 $ 6,696,079 $ 16,679,557 $ 23,375,636
2011 exploration and development costs
Consulting 14,757 25,345 40,102
Camp and general - 635,185 635,185
Easement - 24,935 24,935
Geological and geophysical 94,657 7,012,950 7,107,607
Office and administration - 623,677 623,677
Salaries and benefits 17,062 362,772 379,834
Security - 120,002 120,002
Travel 4,490 63,440 67,930
Stock based compensation 692 13,616 14,308
Drilling 489,143 3,842,737 4,331,880
Platform constructions - 260,503 260,503
Well testing - 207,008 207,008
Workover - 362,015 362,015
Crude oil - 67,089 67,089
Asset retirement obligation 57,943 - 57,943
Depletion (350,443) - (350,443)
Cost recovery from partners - (9,977,508) (9,977,508)
Total exploration and development costs 328,301 3,643,766 3,972,067
Balance – June 30, 2011 $ 7,024,380 $ 20,323,323 $ 27,347,703
During the nine months ended June 30, 2011, the Company capitalized $623,677 (September 30, 2010 –
$308,191) of general and administrative costs related to exploration activities.
The depletion calculation included future development costs of $450,000. There were no costs related to
unproved properties that were excluded from the depletion calculation.
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SUMMARY OF QUARTERLY RESULTS
The following is a summary of the results from the eight previously completed financial quarters (in
thousands of Canadian dollars, except per barrel of oil and per share amounts):
30-Jun-11 31-Mar-11 31-Dec-10 30-Sep-10 30-Jun-10 31-Mar-10 31-Dec-09 30-Sep-09
Production
(boe) 12,674 6,952 - - - - - -
Revenue
($/boe) $109.93 $106.63 - - - - - -
Oil & Gas
revenue $1,393 $741 - - - - - -
Royalties $291 $155 - - - - - -
Production
costs $581 $205 - - - - - -
Interest
revenue $14 $7 $5 $5 $7 $6 $9 $8
Expenses $1,743 $896 $602 $644 $588 $864 $566 $689
Net loss $641 $310 $472 $456 $581 $858 $557 $486
Weighted
average
shares
outstanding
in '000 144,793 121,511 113,179 112,105 111,584 105,985 76,028 57,200
Loss per
share
.00
.00
.00
.01
.01
.01
.01
.01
Petroleum
and gas
expenditures
(recovery) $2,676 $802 $2,458 $1,719 $3,677 $1,259 $1,626 $(33)
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 any of its last three financial years, the
following is a breakdown of the material costs incurred:
Year ended
September 30,
2010
Year ended
September 30,
2009
Year ended
September 30,
2008
Petroleum and Natural Gas Exploration and
Development Costs, net cash payments
$8,729,053 $2,884,615 $5,807,597
Deferred Acquisition Costs $Nil $Nil $Nil
General and Administrative Expenses $1,855,700 $2,548,387 $2,890,749
Any Material Costs (capitalized, deferred or
expensed) not referred to above:
Exploration Advances (Recovery), net cash
payments
$215,515 $(204,412) $894,636
10
DISCLOSURE OF OUTSTANDING SHARE DATA
The following table summarizes the maximum number of common shares outstanding as at June 30,
2011 and as of the date of this MD&A if all outstanding options and warrants were converted to common
shares:
June 30, 2011
As of the date of
this MD&A
Common shares 145,436,617 147,485,882
Warrants to purchase common shares 75,122,282 67,379,145
Options to purchase common shares 5,765,000 5,765,000
Convertible loans payable – shares 13,529,412 13,529,412
Convertible loans payable – warrants 13,529,412 13,529,412
253,382,723 247,688,851
Escrow Shares
As of June 30, 2011, there were Nil (September 30, 2010 – 2,285,000) shares remaining in escrow.
.
RESULTS OF OPERATIONS
Quarter ended June 30, 2011 (“Q3 2011”) compared with the quarter ended June 30, 2010 (“Q3
2010”).
The loss for the quarter ended June 30, 2011 was $639,727 compared to $588,012 during the quarter
ended June 30, 2010. The $51,715 increase in the Q3 2011 net loss versus Q3 2010 is mainly due to
increase in capital tax, accretion of convertible debt and depletion expense, as offset by revenue from
Tartaruga production and decrease in general and administrative costs and foreign exchange loss.
Significant differences between Q3 2011 and Q3 2010 include:
- Current quarter gross production revenue from the Tartaruga Block was $1,393,196. The
Company’s 37.5% share of gross production this period was 12,674 barrels of oil (“boe”) at an
average price of $109.93 per barrel. There was no production in the comparative period
because production from the new well 7-TTG7-TTG-1DP-SES commenced on February 14,
2011. The Company’s working interest in the Tartaruga Block and the rights to production from
this Block are specifically subject to the approval of the assignment of the working interest by the
Tartaruga consortium and the approval of the ANP;
- Royalty expense for the current quarter was $446,197. There was no production and
corresponding royalty expense in the comparative quarter;
- Accretion of convertible loans discount was $162,225 in Q3 2011 due to issuance of convertible
loans in Q4 2010. There were no convertible loans outstanding in Q3 2010;
- Depletion of oil and gas costs was $214,802 in Q3 2011 compared to $Nil in Q3 2010, as there
was no production in the comparative period;
- Capital tax expense of $420,783 was recorded during the current period for Colombian
subsidiaries. This was a one-time expense based on the share capital of Colombian subsidiaries
and it is not expected to be incurred in the near future.
- Foreign exchange gain of $36,138 in Q3 2011 increased by $95,857 from foreign exchange loss
of $62,719 in Q3 2010 due to the revaluation of subsidiaries operations from their home
currencies to the Canadian functional and reporting currency;
- General and administrative expenses were $289,936 in Q3 2011, compared with $369,173 in Q3
2010. The significant variances were (1) a decrease in in public relations fees from $34,481 in
Q3 2010 to $8,798 in Q3, 2011 due to spending less efforts on promoting the Company, and (2)
a decrease in salaries and benefits from $41,186 in Q3 2010 to $16,119 in Q3 2011 due to
closing down of the US office on December 31, 2010; and
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- Operating expenses related to the Tartaruga production was $785,463. There was no production
and corresponding operating expenses in the comparative quarter.
Nine months ended June 30, 2011 compared with the nine months ended June 30, 2010.
The loss for the nine months ended June 30, 2011 was $1,422,083 compared to $2,003,639 during the
nine months ended June 30, 2010. The $581,556 decrease in net loss for the period is mainly due to (1)
commencement of Tartaruga production in February 2011, (2) reduction of foreign exchange losses, (3)
reduction of interest expense and financing fees, which was partially offset by (4) an increase in accretion
of convertible debt discount on convertible loan issued in August 2010, (5) an increase in capital tax and
an increase in depletion expense. Significant differences between the nine months ended June 30, 2011
and 2010 include:
- Current period gross production revenue from the Tartaruga Block was $2,134,491. The
Company’s 37.5% share of gross production this period was 19,626 boe at an average price of
$108.76 per barrel. There was no production in the comparative period because production from
the new well 7-TTG7-TTG-1DP-SES commenced on February 14, 2011. The Company’s
working interest in the Tartaruga Block and the rights to production from this Block are
specifically subject to the approval of the assignment of the working interest by the Tartaruga
consortium and the approval of the ANP;
- Royalty expense for the current period was $446,197. There was no production and
corresponding royalty expense in the comparative period;
- Accretion of convertible loans discount was $483,175 in the current period due to issuance of
convertible loans in Q4 2010. There were no convertible loans outstanding in the comparative
period;
- Depletion of oil and gas costs was $350,443 in the current period compared to $Nil in the
comparative period, as there was no production in the comparative period;
- Capital tax expense of $420,783 was recorded during the current period for Colombian
subsidiaries. This was a one-time expense based on the share capital of Colombian subsidiaries
and it is not expected to be incurred in the near future.
- Foreign exchange gain of $192,190 was recorded in the current period, compared with $369,987
foreign exchange loss in the comparative period. Foreign currency gains and losses fluctuate
from period to period due to the revaluation of subsidiaries operations from their home
currencies to the Canadian functional and reporting currency;
- Interest and financing fees of $359,070 were incurred in the prior period on bonus shares valued
at $180,000 that were issued to obtain a $1,000,000 short-term loan and $72,796 of interest
expense on short-term loans. In the current quarter the interest expense of $98,038 was paid on
overdue accounts payable.;
- Stock based compensation of $59,698 in 2011 was lower than the $188,834 expensed in the
prior period due to fewer options vesting.
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 from operations, through the issuance of common
shares pursuant to private placements, the exercise of warrants and stock options, short term or long
term loans and farm-outs. 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 June 30, 2011, the Company’s working capital deficiency was $1,306,160, compared with a
$1,826,649 working capital deficiency as of September 30, 2010. The $520,489 decrease in working
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capital deficiency is mainly due to in accounts payable of $1,567,910 which was offset by an increase in
restricted funds of $2,083,303.
Cash and Cash Equivalents
On June 30, 2011, the Company had cash and cash equivalents of $464,746 (September 30, 2010 -
$738,300). The $273,554 decrease in cash position is mainly due to receiving $5,244,682 of cash from
issuance of shares and exercise of warrants, and generating $1,749,624 of cash from operating activities,
which was offset by spending $5,326,064 of cash on oil and gas explorations and placing $2,083,303 of
cash in restricted fund for oil and gas explorations.
Cash Used in Operating Activities
Cash generated from the operating activities during the nine months ended June 30, 2011 was $1,769,000,
compared with using $3,108,000 of cash in operating activities during the six months ended June 30, 2010.
The $4,857,000 decrease in cash spent on operating activities is mainly due to a $2,629,000 increase in
accounts payable during the nine months ended June 30, 2011, compared with a $1,440,000 reduction in
accounts payable for the nine months ended June 30, 2010, as well as generating Tartaruga production
revenue commencing in Q2 2011.
Cash Used in Investing Activities
Total cash used in investing activities during the nine months ended June 30, 2011 was $7,261,000
compared to $9,875,000 of cash used during the nine months ended June 30, 2010. The main reasons
for the decrease in cash used in investing activities are spending less cash on oil and gas explorations
and placing less cash in the restricted funds account.. During the nine months ended June 30, 2011, the
Company spent $5,326,064 (June 30, 2010 – $6,403,000) of cash on oil and gas explorations in
Colombia and Brazil, and $2,083,303 (June 30, 2010 - $3,414,000) of cash was placed in restricted
funds.
Cash Generated by Financing Activities
During the nine months ended June 30, 2011, the Company received $5,245,000 (June 30, 2010 –
8,880,000) from the issuance of shares, and $Nil (June 30, 2010 - $3,600,000) from loans payable.
Requirement of Additional Equity Financing
The Company relies primarily on production revenue, 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 on-going 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
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 nine months ended June 30,
2011, the Company reported a loss of $1,422,083 and as at that date had an accumulated deficit of
$13,417,406. In addition, the Company is committed to incur minimum exploration expenditures on
several of the areas in which it holds an interest. The Company’s ability to continue as a going concern is
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dependent upon its ability to generate profitable production and to obtain additional funding from loans,
equity financings or through other arrangements. The Company commenced production from the
Tartaruga Block in Brazil during 2011, generating cash flow from operations (subject to the Tartaruga
consortium and ANP approvals), and is actively seeking additional private or institutional financing or a
property farm-out or sale. 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 not disclosed elsewhere in these financial statements are as
follows:
(a) During the nine months ended June 30, 2011, the Company paid or accrued $511,273 (June 30, 2010 -
$456,079) of salaries and consulting fees to directors, officers, and companies controlled by directors
and officers of the Company. Out of total amount paid/accrued, $177,499 (June 30, 2010 - $198,122)
has been included in deferred petroleum and natural gas costs, $109,285 (June 30, 2010 - $107,629)
has been expensed on the statement of loss as salaries, and $224,489 (June 30, 2010 - $150,328) has
been expensed on the statement of loss as consulting fees.
(b) During the nine months ended June 30, 2011, the Company paid $24,750 (June 30, 2010 - $24,750) for
office rent to a company controlled by a director and officer of the Company.
(c) During the nine months ended June 30, 2011, the Company paid/accrued $46,691 (June 30, 2010 -
$63,000) in directors fees to directors of the Company.
(d) As of June 30, 2011, amount due to related parties of $56,672 (September 30, 2010 - $16,212) was
payable to directors of the Company. This liability is non-interest bearing and has no terms of
repayment.
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
There are no material subsequent events.
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.
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RISK AND UNCERTAINTIES
Petroleum and Natural Gas Prices – The Company’s future success is linked to 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.
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 June 30, 2011, a 1% increase (decrease) in the exchange
rates on that date would have resulted in a (decrease) increase of approximately $507 (September 30,
2010 - $13,863) 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
15
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
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.
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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
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.
17
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).
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
18
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.
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.
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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.
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,
20
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 interim consolidated financial statements for the nine months ended
June 30, 2011 and the audited consolidated financial statements for the year ended September 30, 2010.
Additional information about the Company can also be found on www.sedar.com.
21
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 906 Legal Counsel, Brazil
Vancouver, BC V6C 2T5, Canada
Machado Meyer Sendacz Opice e Biscardi
Advogados
Tel: 604-638-8062 Avenida Rio Branco, 1 - 9º andar - Bloco B
Fax: 604-688-9620 CEP: 20090-003 | Rio de Janeiro, RJ, Brasil
Email: info@pvecorp.com
Website: www.pvecorp.comLegal Counsel, Barbados
Hampton Chambers, Hampton House
Officers and Directors Erdiston Hill, St. Michael, Barbados
Steve Benedetti, (Acting President and
CEO)
Darren Devine, (EVP, Corp. Secr. and
Director) Legal Counsel, Colombia
Keith Hill, (Chairman and Director) Sanclemente Fernandez Abrogado SA
Ian Baron, (Director) Carrera 9, No. 69-70
Ian Gibbs, (Director) Bogota, Colombia
Adam Kniec, (Chief Financial Officer)
Auditors
Audit Committee PricewaterhouseCoopers, LLP
Ian Gibbs (Chairman) Suite 700, 250 Howe Street.