Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is
pleased to announce year end reserves and an operational update of our Heavy Oil
Business Unit ("HBU").
All references to $ are Canadian dollars unless otherwise noted. Total Company
share only includes Petrobank's 64% share of PetroBakken reserves and net
present values ("NPV") and 66% share of Petrominerales reserves and NPV.
HIGHLIGHTS
- Total Company share of proved plus probable ("2P") reserves increased by 26%
to 197.0 million barrels of oil equivalent ("boe") (2P + best estimate
contingent resources - 796.1 million boe).
- Total Company share of 2P NPV, before tax, increased by 40% to $4.3 billion
(2P + best estimate contingent resources - $7.1 billion).
- HBU 2P reserves plus best estimate contingent recoverable bitumen resources
totaled 669.1 million barrels with NPV, before tax, discounted at 8% of $3.3
billion.
- McDaniel and Associates Consultants Ltd. ("McDaniel") completed the first
comprehensive evaluation (the "Transition Report") of THAI(TM) at our Conklin
project as the initial step for assigning reserves and resources, concluding
that the Conklin Project is successfully proving the THAI(TM) process. The
Transition Report assigns a best estimate THAI(TM) exploitable bitumen-in-place
of 1.8 billion barrels on our Whitesands leases, exceeding the SAGD exploitable
bitumen-in-place by 17% or 259 million barrels.
- PetroBakken 2P reserves increased by 141% to 143.6 million boe at December 31,
2009.
- PetroBakken 2009 working interest production was replaced 9.9 times as a
result of increases in reserves from operations and acquisitions.
- PetroBakken NPV (before tax, discounted at 10%) of 2P reserves increased by
145% to $3.7 billion.
- Petrominerales total proved reserves increased by 43% to 36.0 million barrels
of oil and 2P reserves increased by 44% to 53.1 million barrels of oil.
- Petrominerales total proved reserve additions replaced 2009 production by 232%
and 2P reserve additions replaced 299% of 2009 production.
- Petrominerales NPV (before tax, discounted at 10%) of 2P reserves increased by
69% to US$2.1 billion.
CORPORATE RESERVES / RESOURCES SUMMARY BY BUSINESS UNIT
Working Interest, Forecast Prices
Total
PetroBakken Petrominerales HBU Company(1)
(mboe) (mbbls) (mbbls) (mboe)
----------------------------------------------------------------------------
Developed Producing 59,412 18,533 - 50,255
Total Proved 89,470 35,987 - 81,012
Proved + Probable (2P) 143,638 53,107 70,013 196,992
Best Estimate Contingent
Resources - - 599,081 599,081
2P + Best Estimate
Contingent Resources 143,638 53,107 669,094 796,073
(1) Total Company includes only Petrobank's 64% share of PetroBakken
reserves and 66% share of Petrominerales reserves, as at December 31,
2009.
Net Present Value, Before Tax, Forecast Prices (millions) (1)
Total
PetroBakken Petrominerales HBU Company(2)
($) (US$) ($) ($)
----------------------------------------------------------------------------
Developed Producing 1,921 844 - 1,812
Total Proved 2,456 1,458 - 2,579
Proved + Probable (2P) 3,651 2,082 482 4,257
Best Estimate Contingent
Resources - - 2,828 2,828
2P + Best Estimate
Contingent Resources 3,651 2,082 3,310 7,085
Net Present Value, After Tax, Forecast Prices (millions) (1)
Total
PetroBakken Petrominerales HBU Company(2)
($) (US$) ($) ($)
----------------------------------------------------------------------------
Developed Producing 1,719 715 - 1,594
Total Proved 2,090 1,134 - 2,121
Proved + Probable (2P) 2,969 1,555 370 3,344
Best Estimate Contingent
Resources - - 1,958 1,958
2P + Best Estimate
Contingent Resources 2,969 1,555 2,329 5,303
(1) Net present values are discounted at 10% for PetroBakken and
Petrominerales, and at 8% for the HBU.
(2) Total Company includes only Petrobank's 64% share of PetroBakken
reserves and 66% share of Petrominerales reserves, as at December 31,
2009 converted using a US$/$ exchange rate of 1.0466.
Price Forecasts
PBN PBN PMG HBU HBU
----------------------------------------------------------------------------
WTI Crude WTI Crude WTI Crude Hardisty
AECO Natural Oil(1) Oil(1) Oil(1) DilBit(1)
Year Gas(1)($/mcf) (US$/bbl) (US$/bbl) (US$/bbl) ($/bbl)
----------------------------------------------------------------------------
2010 5.36 79.17 80.00 80.00 70.60
2011 6.21 84.46 82.88 83.60 72.00
2012 6.44 86.89 85.83 87.40 72.60
2013 7.23 90.20 88.88 91.30 73.90
2014 7.98 92.01 92.01 95.30 77.20
2015 8.16 93.85 93.85 99.40 80.50
Thereafter inflation
% change 2% 2% 2% 2% 2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Actual prices used were adjusted for crude oil and bitumen quality
differentials, natural gas heat content, transportation and marketing
costs specific to the Company's operations. Price forecasts were
provided by McDaniel in respect of HBU, Sproule Associates Ltd.
("Sproule") in respect of PetroBakken and DeGoyler and MacNaughton
("D&M") in respect of Petrominerales.
The full reserve disclosure tables, as required under National Instrument
51-101, will be contained in the Company's Annual Information Form which will be
filed on the SEDAR website at www.sedar.com later in March.
HBU HIGHLIGHTS
- HBU SAGD 2P reserves on our Whitesands leases, which includes lands
encompassing our Conklin pilot project and May River commercial project,
increased by 1.5% to 70.0 million barrels with net present value, before tax,
discounted at 8% of $482 million.
- HBU 3P reserves plus high estimate contingent recoverable bitumen resources
totalled 817.7 million barrels with net present value, before tax, discounted at
8% of $4.3 billion.
- McDaniel has completed the Transition Report, concluding that the THAI(TM)
process is field proven. The Transition Report assigns a best estimate THAI(TM)
exploitable bitumen-in-place of 1.8 billion barrels on our Whitesands leases,
exceeding the SAGD exploitable bitumen-in-place by 17% or 259 million barrels.
- First oil sales from Kerrobert began on January 23, 2010.
HBU RESERVES / RESOURCES SUMMARY
The following tables summarize the McDaniel Whitesands leases reserves report as
at December 31, 2009. Reserves and contingent resources were assigned to the
Whitesands leases (62 sections) near Conklin Alberta and the report does not
include any reserves or recoverable resources associated with our Glover lease
(10 sections), the Sutton Creek lease (36 sections), our 50% interest in the
Dawson property (4 sections), or our 50% interest in the Kerrobert property (4.1
sections).
Reserves and Resources (1) as of December 31, 2009 2008 Change
(MMbbl) (MMbbl) %
----------------------------------------------------------------------------
Probable Reserves (2P) 70.0 69.0 1
Probable plus Possible Reserves (3P) (2) 78.8 77.7 1
Low Estimate Contingent Resources (3) (4) 483.2 485.0 -
Best Estimate Contingent Resources (3) (4) 599.1 599.0 -
High Estimate Contingent Resources (3) (4) 738.9 737.0 -
2P + Best Estimate Contingent Resources 669.1 668.2 -
3P + High Estimate Contingent Resources 817.7 814.7 -
(1) Gross reserves and/or resources include the working interest
reserves/resources before deductions of royalties payable to others.
(2) Possible reserves are those additional reserves that are less certain
to be recovered than probable reserves.
(3) Contingent resources, as evaluated by McDaniel, are those quantities of
bitumen estimated to be potentially recoverable using SAGD technology
from known accumulations but are classified as a resource rather than
a reserve primarily due to the absence of regulatory approvals,
detailed design estimates and near term development plans and are in
addition to 3P reserves.
(4) A low estimate means higher certainty (P90), a best estimate (P50)
means most likely and a high estimate means lower certainty (P10).
Whitesands Leases Before Tax Net Present Value - December 31, 2009 -
$ Millions (1) (2) (3)
Net Present Value Discounted at: 0% 5% 8% 10%
----------------------------------------------------------------------------
Probable Reserves (2P) 1,475 725 482 367
Probable plus Possible Reserves (3P) 1,912 918 613 474
Low Estimate Contingent Resources 9,833 3,672 1,996 1,286
Best Estimate Contingent Resources 14,236 5,102 2,828 1,904
High Estimate Contingent Resources 20,947 6,745 3,669 2,491
2P + Best Estimate Contingent Resources 15,711 5,826 3,310 2,272
3P + High Estimate Contingent Resources 22,859 7,663 4,283 2,965
(1) Based on McDaniel forecast bitumen netback prices.
(2) Interest expenses and corporate overhead, etc. were not included.
(3) The net present values may not necessarily represent the fair market
value of the reserves and/or resources.
Whitesands After Tax Net Present Value - December 31, 2009 -
$ Millions (1) (2) (3)
Net Present Value Discounted at: 0% 5% 8% 10%
----------------------------------------------------------------------------
Probable Reserves (2P) 1,150 562 370 279
Probable plus Possible Reserves (3P) 1,477 710 473 363
Low Estimate Contingent Resources 7,329 2,591 1,309 769
Best Estimate Contingent Resources 10,619 3,678 1,958 1,263
High Estimate Contingent Resources 15,639 4,914 2,601 1,718
2P + Best Estimate Contingent Resources 11,768 4,240 2,329 1,542
3P + High Estimate Contingent Resources 17,116 5,623 3,074 2,081
(1) Based on McDaniel forecast bitumen netback prices.
(2) Interest expenses and corporate overhead, etc. were not included.
(3) The net present values may not necessarily represent the fair market
value of the reserves and/or resources.
McDaniel Price Forecasts as of January 1, 2010
Hardisty
WTI Crude Oil (1) DilBit (1) AECO (1)
Year (US$/bbl) (C$/bbl) (C$/mcf) US$/C$
----------------------------------------------------------------------------
2010 80.00 70.60 6.05 0.95
2011 83.60 72.00 6.75 0.95
2012 87.40 72.60 7.15 0.95
2013 91.30 73.90 7.45 0.95
2014 95.30 77.20 7.80 0.95
2015 99.40 80.50 8.15 0.95
Thereafter inflation
% change 2% 2% 2% nil
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Actual prices used were adjusted for crude oil and bitumen quality
differentials, natural gas heat content, transportation and
marketing costs specific to the Company's operations.
McDaniel & Associates Consultants Ltd. (McDaniel THAI(TM) Transition Report)
The McDaniel estimates are based on SAGD technology as it is the presently
recognized technology used to define in-situ oil sands reserves and resources.
This does not in any way reflect the technical merits of the THAI(TM) process.
To be able to establish the technical basis to assign reserves and resources
based on THAI(TM), McDaniel conducted a rigorous analysis of our Conklin
THAI(TM) project in conjunction with the reserve evaluation. This analysis
encompassed all of the operational and observational data from the inception of
the Conklin project to clearly establish the effectiveness and sustainability of
THAI(TM) as an economic recovery process. The first step of the analysis was to
define the exploitable resource base on the lands using THAI(TM) and to then set
out the parameters to assign reserves and resources. The Transition Report
concludes that, "It is the opinion of McDaniel & Associates that the pilot
project is successfully proving the THAI(TM) process". In addition, THAI(TM) is
an effective recovery process that is able to produce bitumen from a greater
portion of the reservoir than SAGD, specifically the thinner and less homogenous
regions. The SAGD exploitable bitumen on our lands is estimated by McDaniel to
be 1.3 billion barrels in the low case and 1.7 billion barrels in the high case.
The Transition Report assigns exploitable bitumen-in-place for THAI(TM) of 1.6
billion barrels in the low case and 2.0 billion barrels in the high case, or 21
and 15 percent higher than SAGD respectively. Now that a THAI(TM) exploitable
bitumen-in-place has been defined, McDaniel has confirmed that they will issue a
THAI(TM) based reserves and resource estimate at Conklin once commercial
production rates ( greater than 250 bbls/day per well) has been sustained for a
period of at least three months.
The conclusion from the Transition Report confirms that the THAI(TM) process is
an effective production technology. The analysis is also applicable to
Kerrobert, Dawson, and other similar reservoirs. Now that we have established
the technical baseline for THAI(TM), we will intensify our efforts to sustain
commercial production rates, enabling the assignment of THAI(TM) reserves and
resources to our current and future projects.
Exploitable Bitumen-In-Place, (MMbbls)
--------------------------------------- Difference Difference
Classification THAI(TM) SAGD (MMbbls) (%)
----------------------------------------------------------------------------
High Estimate 1,963 1,710 253 15
Best Estimate 1,785 1,526 259 17
Low Estimate 1,570 1,296 275 21
THAI(TM) BENEFITS
THAI(TM) has many potential benefits over SAGD including expected higher
resource recovery (70%-80% versus 30%-50% for SAGD), lower production and
capital costs, minimal usage of natural gas and fresh water, a partially
upgraded crude oil product, reduced diluent requirements for transportation, and
lower greenhouse gas emissions. The THAI(TM) process also has the potential to
operate in lower pressure, lower quality, thinner and deeper reservoirs than
current steam-based recovery processes. The continued field demonstration of
THAI(TM) will have an enormous impact on resource recovery and estimates of
reserve volumes.
Petrobank has created an educational video to provide interested viewers the
opportunity to see THAI(TM) in action, where we've been, and where we're going.
We encourage you to view this newly produced video at
www.petrobank.com/heavy-oil/thai-video.
HEAVY OIL BUSINESS UNIT OPERATIONAL UPDATE
Kerrobert Project
At Kerrobert, during the months of January and February, we adjusted our pump
configuration and were able to achieve more consistent well operations; however,
these pumps are still not able to fully draw down the wells. Production rates in
early March, based on field measurements, have averaged 123 barrels of oil per
day ("bopd"), with an on-stream factor of 81%. Well bore temperatures are now
consistently in the 250 to 350 degrees Celsius range, and produced gas
composition confirms high temperature combustion. We have now started to see an
improvement in the API and viscosity of the produced oil.
Surface facilities have been operating smoothly with only minor cold weather
related issues. In operations to date we have not had any solids or produced
sand. The next expansion of our air compression capacity will be installed at
the beginning of April. We are finalizing our plans for the development of the
initial earned lands which would encompass nine additional production wells in
this portion of the pool. We are planning to have the additional wells operating
in the third quarter of 2010.
We are now proceeding with the replacement our current hydraulic pump
configuration originally conceived to only operate during startup. As previously
reported, we have concluded that permanent pumps will be more effective than
relying on produced gas-lift alone. After careful analysis for this production
phase in the well life, we have specified and ordered a new pumping solution
that should help us meet our production targets without relying on gas-lift. New
wellheads, instrumentation, and pumps have been ordered, and will be installed
by the end of March.
Conklin Pilot Project
At Conklin, we have now identified an alternative completion and production
configuration for the current wells based on knowledge gained recently from our
operations at Kerrobert. This alternative configuration will involve the
addition of pumps and a revised production gas string in each of the wells. We
have recently shut in the P2B and P3B wells to prepare these wells for the
reconfiguration, which will take place over the next three months and will
involve recompleting each of the current wells. The revised completion design is
expected to improve the production characteristics of the wells enabling them to
flow more uniformly by reducing the effects of swings in gas production inherent
with the current produced gas-lift mechanism. This is a significant optimization
step that is expected to improve and stabilize production over the long term and
that we intend to utilize in all future projects. The P1B well is currently
producing at approximately 135 bopd and will also be reconfigured after the P2B
and P3B recompletions. Once the well workovers are completed, we expect to ramp
up Conklin project production to our 1,500 bopd target during the second half of
2010.
May River Project
We plan to have 12 additional OSE stratigraphic test wells and 3D seismic over
the May River project area completed by the end of March. This work will further
delineate the reservoir over the project area and allow us to finalize well
placement and areas for future expansion. The 3D seismic will also be acquired
over the current Conklin project to provide a new 4D view of the progress of the
combustion zone. Processing and interpretation will be carried out during the
second quarter of 2010.
The regulatory application for May River's first phase was filed with the Energy
Resources and Conservation Board ("ERCB") and Alberta Environment in December
2008. The first round of supplemental information requests ("SIRs") from Alberta
Environment and the ERCB were responded to in mid-December 2009. A second round
of SIRs were received from Alberta Environment early in 2010 and we have
submitted our responses. Typically the ERCB also submits a second round of SIRs
but none have been received to-date.
Front end engineering and design for the project was completed in the fourth
quarter of 2009, and we are now developing the cost estimate and initiating
procurement for some of the long lead time equipment. The design incorporates
power generation utilizing low energy produced gas, sulphur recovery, is CO2
capture ready, and will be a net water producer rather than a water user, making
our May River project a leading environmentally sustainable benchmark for oil
sands and heavy oil development. The project utilizes a modular approach that is
designed to be installed and operated on heavy oil projects world-wide.
Dawson Project
Dawson is a joint venture project located near Peace River, Alberta with a
significant heavy oil resource in the Bluesky formation. The regulatory
application for this project was filed on April 2, 2009 contemplating a project
of similar scope and scale to our Kerrobert project. We received Alberta
Environment's conditional approval on June 26, 2009. The ERCB's SIRs were
received at the end of November and we have submitted our responses.
Archon Technologies
Our wholly-owned subsidiary, Archon Technologies Ltd., has tested several
innovative and step-change technologies on a lab scale. These could
significantly improve THAI(TM) performance by improving overall recovery and
quality of produced heavy oil. Small scale field pilots for these technologies
are planned to be implemented at Conklin. We recently filed another new
enhancement patent involving a novel well design bringing our portfolio of
patents to eight.
We continue to receive world-wide interest in our technology because of its
superior economic and environmental benefits. Our joint venture strategy is to
demonstrate and commercialize THAI(TM) and CAPRI(TM) in a wide range of large
global resource opportunities.
PETROBAKKEN (64% OWNED BY PETROBANK)
PetroBakken announced year end reserves on March 4, 2010, highlighted as follows:
- 2P reserves increased by 141% to 143.6 million boe at December 31, 2009.
- 2009 working interest production was replaced 9.9 times as a result of
increases in reserves from operations and acquisitions.
- NPV (before tax, discounted at 10%) of 2P reserves increased by 145% to $3.7
billion.
- 2P FD&A costs of $32.48 per boe, including the TriStar Oil & Gas Ltd.
("TriStar") acquisition and changes in future development costs. Excluding net
acquisitions, our 2P finding and development ("F&D") costs were $33.02 per boe.
PetroBakken Working Interest Reserves(1)
Forecast Prices(2)
Total Oil NGL Natural Gas Total
(mbbl) (mbbl) (mmcf) (mboe)
----------------------------------------------------------------------------
Proved Developed Producing 48,196 2,256 53,757 59,412
Total Proved 71,629 3,125 88,299 89,470
Proved + Probable (2P) 116,085 5,047 135,035 143,638
(1) Company working interest reserves excluding royalty income reserves
and before deduction of royalties payable.
(2) Based on the Sproule price forecast effective December 31, 2009.
Royalty income volumes are excluded from Company gross reserves noted above but
are included in calculating Company net reserves and net present values.
Production in 2009 included 540 barrels of oil equivalent per day ("boepd") of
royalty income production.
PetroBakken Net Present Value - Before Tax ($ millions)
Forecast Prices
As at December 31, 2009
0% 5% 8% 10% 15%
----------------------------------------------------------------------------
Proved Developed Producing 3,029.6 2,321.7 2,059.0 1,921.1 1,659.3
Total Proved 4,103.5 3,056.4 2,663.0 2,455.9 2,062.2
Proved + Probable (2P) 7,000.7 4,794.0 4,035.0 3,651.2 2,951.9
PetroBakken Net Present Value - After Tax ($ millions)
Forecast Prices
As at December 31, 2008
0% 5% 8% 10% 15%
----------------------------------------------------------------------------
Proved Developed Producing 2,675.2 2,064.4 1,837.8 1,718.8 1,493.0
Total Proved 3,450.4 2,586.4 2,261.2 2,089.8 1,763.7
Proved + Probable (2P) 5,552.3 3,859.3 3,269.4 2,969.4 2,419.7
Reserve Reconciliation - Forecast Prices (mboe)
Developed Total Proved+
Producing Proved Probable
----------------------------------------------------------------------------
PetroBakken reserves at December 31, 2008 26,501 40,465 59,536
2009 production net of royalty interest (9,414) (9,414) (9,414)
Acquisitions 35,319 49,768 78,187
Net additions and revisions 7,006 8,651 15,329
----------------------------------------------------------------------------
PetroBakken reserves at December 31, 2009 59,412 89,470 143,638
PetroBakken year-over-year increase in reserves 124% 121% 141%
PetroBakken production replacement 450% 621% 993%
PetroBakken FD&A Costs(1)
Finding & Development Acquisitions(2) FD&A
----------------------------------------------------------------------------
Capital expenditures ($000s)
Capital expenditures 385,911 8,112 394,023
Corporate acquisition
capital (3) - 1,986,728 1,986,728
----------------------------------------------------------------------------
Total capital 385,911 1,994,840 2,380,751
Change in future development costs
($000s)
Total Proved 5,302 349,998 355,300
Proved + Probable (2P) 120,322 536,678 657,000
Total costs ($000s)
Total Proved 391,213 2,344,838 2,736,051
Proved + Probable (2P) 506,233 2,531,518 3,037,751
Net reserve additions (mboe)
Total Proved 8,651 49,768 58,419
Proved + Probable (2P) 15,329 78,187(4) 93,516
----------------------------------------------------------------------------
FD&A costs ($/boe)
Total Proved 45.22 47.12 46.83
Proved + Probable (2P) 33.02 32.38 32.48
----------------------------------------------------------------------------
(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserve additions for that year.
(2) Includes the acquisition of TriStar Oil & Gas Ltd. and other assets,
and the disposition of approximately 2,000 boepd of assets.
(3) Portion of purchase price allocated to property, plant & equipment and
reflects TriStar net present value as at October 1, 2009 based on
2P NPV10%, before tax.
(4) 2P acquisition reserve volumes net of dispositions at December 31, 2009
include the effect of the Ante Creek disposition of 7.5 mmboe.
PETROMINERALES (66% OWNED BY PETROBANK)
Petrominerales announced year end reserves on February 22, 2010, highlighted as
follows:
- Total proved reserves increased by 43% to 36.0 million barrels of oil and
proved plus probable reserves increased by 44% to 53.1 million barrels of oil.
- Total proved reserve additions replaced production by 232% and proved plus
probable reserve additions replaced 299% of production.
- Total proved plus probable NPV 10% (before tax) is US$2.1 billion.
- Total proved plus probable forecasted production for 2010 is 37,923 bopd.
- Based on capital expenditures of US$281 million, total proved and proved plus
probable F&D costs are US$18.51/bbl and US$13.98/bbl in 2009, respectively,
including changes in future development costs.
D&M completed an evaluation effective as at December 31, 2009 of the Company's
Orito and Neiva properties and portions of the Corcel, Guatiquia, Mapache and
Rio Ariari blocks. D&M's report did not include any evaluation of the Company's
remaining 1.7 million acres of exploration land in Colombia or 2.6 million acres
in Peru. All reserves stated herein are based on forecast prices and costs and
are Company interest reserves before royalties.
Company Gross Reserves Reconciliation (MBBL)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Developed Proved Plus
Producing Total Proved Probable
----------------------------------------------------------------------------
December 31, 2008 Reserves 14,229 25,174 36,849
2009 Production (8,162) (8,162) (8,162)
Net Additions 12,466 18,975 24,420
----------------------------------------------------------------------------
December 31, 2009 Reserves 18,533 35,987 53,107
Year over year increase in reserves 30% 43% 44%
Production replacement 153% 232% 299%
Net Present Value of Future Net Revenue Before Tax (US$ Millions)(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
0% 5% 8% 10% 15%
----------------------------------------------------------------------------
Proved Developed Producing 1,085 949 898 844 760
Total Proved 2,018 1,696 1,588 1,458 1,277
Proved Plus Probable 2,930 2,442 2,353 2,082 1,810
(1) Using forecast prices and costs.
Net Present Value of Future Net Revenue After Tax (US$ Millions)(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
0% 5% 8% 10% 15%
----------------------------------------------------------------------------
Proved Developed Producing 922 806 749 715 642
Total Proved 1,557 1,316 1,201 1,134 994
Proved Plus Probable 2,173 1,819 1,652 1,555 1,353
(1) Using forecast prices and costs.
RESERVES INFORMATION BY PROPERTY
Company Gross Reserves By Block (MBBL)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Corcel Orito Neiva Guatiquia Other Total
----------------------------------------------------------------------------
Proved Developed 7,136 4,250 3,436 3,414 297 18,533
Total Proved 10,612 10,612 8,152 6,314 297 35,987
Probable 6,540 4,676 1,841 4,063 - 17,120
----------------------------------------------------------------------------
Proved Plus Probable 17,152 15,288 9,993 10,377 297 53,107
The proved undeveloped reserves include the following:
- Three wells at Corcel (E-2, Boa-2 and C-2);
- One well at Guatiquia (Candelilla-2);
- 21 wells at Neiva; and
- 20 wells at Orito.
The probable undeveloped reserves include the following:
- Corcel A-3 side-track;
- Candelilla-3;
- 17 wells at Neiva; and
- 6 wells at Orito.
Finding and Development Costs(1)(2)
Petrominerales' all-in 2009 F&D costs of US$13.98/bbl for total proved reserves
and US18.51/bbl for total proved plus probable reserves include US$53 million
(2008 - US$57 million) of exploration costs incurred on exploration acreage not
evaluated by D&M. In addition, Petrominerales spent US$78 million (2008 - US$50
million) on facilities and infrastructure in the year.
Three-Year
2009 2008 Average
----------------------------------------------------------------------------
Capital expenditures (US$ Millions) 281 268 231
Change in future costs to develop (US$ Millions)
Total Proved 70 (54) 33
Proved Plus Probable 60 (149) 26
Total costs (US$ Millions)
Total Proved 351 214 263
Proved Plus Probable 341 119 256
Net reserve additions (MBBL)
Total Proved 18,975 8,591 12,113
Proved Plus Probable 24,420 3,886 14,164
----------------------------------------------------------------------------
F&D costs (US$ per BBL)
Total Proved 18.51 24.95 21.75
Proved Plus Probable 13.98 30.66 18.10
----------------------------------------------------------------------------
(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserve additions for that year.
(2) The total undiscounted future development costs included in the December
31, 2009 D&M report was US$204.3 million (2008 - US$133.9 million) for
total proved reserves and US$294.8 million (2008 - US$234.4 million)
for proved plus probable reserves.
INVESTOR PRESENTATION
Petrobank is pleased to participate in the FirstEnergy Conference in New York
City on Thursday March 11, 2010 at 4:00 p.m. Eastern Time (2:00 p.m. Mountain
Time). Interested parties may listen to the live webcast presentation by
following the link below:
http://remotecontrol.jetstreammedia.com/17009
FINANCIAL STATEMENT RELEASE DATE AND INVESTOR CONFERENCE CALL
Petrobank plans to release fourth quarter 2009 financial results after markets
close on Tuesday, March 16, 2010. Management of Petrobank will be holding a
conference call for investors, financial analysts, media and any interested
persons on Wednesday, March 17, 2010 at 9:00 a.m. Mountain Time (11:00 a.m.
Eastern Time) to discuss Petrobank fourth quarter financial and operating
results. The investor conference call details are as follows:
Live call dial-in numbers: 416-340-2216 / 866-226-1792
Replay dial-in numbers: 416-695-5800 / 800-408-3053
Replay pass code: 7306464
The live audio webcast link is:
http://events.digitalmedia.telus.com/petrobank/031710/index.php and is also
available on our website at: http://www.petrobank.com/investors/.
CORPORATE PRESENTATIONS
The Petrobank, PetroBakken and Petrominerales corporate presentations have been
updated and can be found at www.petrobank.com, www.petrobakken.com, and
www.petrominerales.com.
Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas
exploration and production company with operations in western Canada and Latin
America. The Company operates high-impact projects through three business units
and a technology subsidiary. The Canadian Business Unit, operated by Petrobank's
64% owned TSX-listed subsidiary, PetroBakken Energy Ltd. (TSX:PBN), is a premier
light oil production company combining high growth, long-life Bakken reserves
and production with legacy conventional light oil assets, delivering industry
leading operating netbacks, strong cash flows and production growth. The Latin
American Business Unit, operated by Petrobank's 66% owned TSX listed subsidiary,
Petrominerales Ltd. (TSX:PMG), is a Latin America-based exploration and
production company producing oil in Colombia with 14 exploration blocks covering
a total of 1.8 million acres in the Llanos and Putumayo Basins and 2.6 million
gross acres in the Ucayali Basin of Peru. Whitesands Insitu Partnership, a
partnership between Petrobank and its wholly-owned subsidiary Whitesands Insitu
Inc., owns 75 net sections of oil sands leases in Alberta, 36 sections of oil
sands licenses in Saskatchewan and operates the Whitesands project which is
field-demonstrating Petrobank's patented THAI(TM) heavy oil recovery process.
THAI(TM) is an evolutionary in-situ combustion technology for the recovery of
bitumen and heavy oil that integrates existing proven technologies and provides
the opportunity to create a step change in the development of heavy oil
resources globally. THAI(TM) and CAPRI(TM) are registered trademarks of Archon
Technologies Ltd., a wholly-owned subsidiary of Petrobank.
Forward-Looking Statements: Certain information provided in this press release
constitutes forward-looking statements. The words "anticipate", "expect",
"project", "estimate", "forecast" and similar expressions are intended to
identify such forward-looking statements. Specifically, this press release
contains forward-looking statements relating to financial results, results from
operations and the timing of certain projects. The reader is cautioned that
assumptions used in the preparation of such information, although considered
reasonable at the time of preparation, may prove to be incorrect. Actual results
achieved during the forecast period will vary from the information provided
herein as a result of numerous known and unknown risks and uncertainties and
other factors. You can find a discussion of those risks and uncertainties in our
Canadian securities filings. Such factors include, but are not limited to:
general economic, market and business conditions; fluctuations in oil prices;
the results of exploration and development drilling, recompletions and related
activities; timing and rig availability, outcome of exploration contract
negotiations; fluctuation in foreign currency exchange rates; the uncertainty of
reserve estimates; changes in environmental and other regulations; risks
associated with oil and gas operations; and other factors, many of which are
beyond the control of the Company. There is no representation by Petrobank that
actual results achieved during the forecast period will be the same in whole or
in part as those forecast. Except as may be required by applicable securities
laws, Petrobank assumes no obligation to publicly update or revise any
forward-looking statements made herein or otherwise, whether as a result of new
information, future events or otherwise.
Resources and Contingent Resources: In this press release, Petrobank has
disclosed estimated volumes of "contingent resources" or "resource" estimates.
"Resources" are oil and gas volumes that are estimated to have originally
existed in the earth's crust as naturally occurring accumulations but are not
capable of being classified as "reserves". The following are excerpts from the
definition of "contingent resources" as contained in Section 5 of the COGE
Handbook, which is referenced by the Canadian Securities Administrators in
"National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities".
"Contingent resources" are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from known accumulations using
established technology or technology under development, but which are not
currently considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such as economic, legal,
environmental, political, and regulatory matters, or a lack of markets. It is
also appropriate to classify as "contingent resources" the estimated discovered
recoverable quantities associated with a project in the early evaluation stage.
"Contingent resources" are further classified in accordance with the level of
certainty associated with the estimates and may be sub classified based on
project maturity and/or characterized by their economic status. "Resources" and
"contingent resources" do not constitute, and should not be confused with,
reserves.
Possible Reserves: Possible reserves are those additional reserves that are less
certain to be recovered than probable reserves. There is a 10% probability that
the quantities actually recovered will equal or exceed the sum of proved plus
probable plus possible reserves.
Net Present Values: Estimated values of future net revenue disclosed in this
press release do not necessarily represent fair market values.
Aggregation of Reserves and Resources: Certain tables in this press release
contain volumes that are an arithmetic sum of multiple estimates of reserves and
resources, which statistical principles indicate may be misleading as to volumes
that may actually be recovered. Readers should give attention to the estimates
of individual classes of reserves or resources and appreciate the differing
probabilities of recovery associated with each class of reserves and resources,
as discussed herein, and as discussed in our Annual Information Form which will
be filed on the SEDAR website at www.sedar.com later in March.
Barrels of Oil Equivalent: Disclosure provided in this press release in respect
of barrels of oil equivalent ("boe") units may be misleading, particularly if
used in isolation. A boe conversion relationship of 6 mcf to 1 bbl is based on
an energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the well head.
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