Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is
pleased to announce our year end 2010 reserves evaluation and to provide an
operational update of our Heavy Oil Business Unit ("HBU") activities. Our
independent reserves evaluator, McDaniel & Associates Consultants Ltd.
("McDaniel"), has assigned the first THAI(R) proven reserves at our Kerrobert
project.
All references to $ are Canadian dollars unless otherwise noted. Total Company
share includes Petrobank's 59% share of PetroBakken Energy Ltd. ("PetroBakken")
reserves and net present values ("NPV"). When referencing 2009 for comparative
purposes, Total Company share of reserves and net present value excludes
reserves and NPV related to Petrominerales Ltd. as Petrobank's ownership in
Petrominerales Ltd. was distributed to our shareholders on December 31, 2010.
HIGHLIGHTS
-- THAI(R) proved and proved plus probable ("2P") reserves recognized for
the Kerrobert project are 3.0 million barrels and 4.8 million barrels,
respectively, with before tax NPV at 8% of $6.2 million and $46.0
million, respectively.
-- McDaniel forecast that the THAI(R) sales oil price at Kerrobert will
receive a 10% percent premium over conventional native quality heavy
oil.
-- HBU 2P reserves increased 36% to 95.4 million barrels with NPV, before
tax, discounted at 8% increasing 50% to $724 million at December 31,
2010.
-- HBU best estimate contingent bitumen resources totalled 560 million
barrels with NPV, before tax, discounted at 8% of $3.0 billion (see
"Contingent Resources").
-- PetroBakken Company Interest 2P reserves increased by 18% to 171.4
million barrels of oil equivalent ("MMboe") at December 31, 2010.
-- PetroBakken replaced 274% of production as a result of operations and
acquisitions less dispositions.
-- PetroBakken NPV (before tax, discounted at 10%) of 2P reserves increased
by 13% to $4.1 billion.
-- Petrobank Total Company 2P reserves increased by 21% to 196.5 MMboe.
-- Petrobank Total Company 2P NPV, before tax and discounted by 10% for
PetroBakken and 8% for HBU, increased by 12% to $3.2 billion.
CORPORATE RESERVES / RESOURCES SUMMARY BY BUSINESS UNIT
Company Interest(1), Forecast Prices
HBU - HBU - Total
PetroBakken Heavy Oil Bitumen Company(2)
(Mboe) (Mbbls) (Mbbls) (Mboe)
----------------------------------------------------------------------------
Developed Producing 66,183 575 - 39,623
Total Proved 103,028 3,032 - 63,819
Proved + Probable (2P) 171,377 4,837 90,572 196,521
Best Estimate Contingent
Resources(3) - - 560,131 560,131
(1) "Company Interest" reserves, which represent the Company's working
interest share of reserves including the Company's royalty interests in
reserves and before deduction of the Company's royalty obligations.
(2) Total Company includes only Petrobank's 59% share of PetroBakken
reserves as at December 31, 2010.
(3) See "Contingent Resources".
Net Present Value, Before Tax, Forecast Prices ($ millions) (1)
HBU -
Heavy HBU - Total
PetroBakken Oil Bitumen Company(2)
----------------------------------------------------------------------------
Developed Producing $ 2,135 $ 2 - $ 1,262
Total Proved $ 2,845 $ 6 - $ 1,685
Proved + Probable (2P) $ 4,142 $ 46 $ 678 $ 3,168
Best Estimate Contingent
Resources - - $ 3,000 $ 3,000
(1) Based on McDaniel forecast bitumen and heavy oil netback prices.
Interest expenses and corporate overhead were not included. Net present
values are discounted at 10% for PetroBakken and at 8% for the HBU. The
net present values do not represent the fair market value of the
reserves and/or resources.
(2) Total Company includes only Petrobank's 59% share of PetroBakken net
present value as at December 31, 2010.
Price Forecasts(1)
----------------------------------------------------------------------------
PetroBakken HBU
----------------------------------------------------------------------------
Conklin
Kerrobert SAGD
THAI(R) Bitumen
AECO Oil at at
Natural WTI Crude WTI Crude Fieldgate Fieldgate
Gas(1) Oil(1) Oil(1) (2) (2)
Year ($/Mcf) (US$/bbl) (US$/bbl) (CDN$/bbl) (CDN$/bbl)
----------------------------------------------------------------------------
2011 4.04 88.40 85.00 62.69 56.41
----------------------------------------------------------------------------
2012 4.66 89.14 87.70 64.66 58.32
----------------------------------------------------------------------------
2013 4.99 88.77 90.50 64.09 56.82
----------------------------------------------------------------------------
2014 6.58 88.88 93.40 66.16 58.66
----------------------------------------------------------------------------
2015 6.69 90.22 96.30 68.34 60.65
----------------------------------------------------------------------------
2016 6.80 91.57 99.40 70.61 62.69
----------------------------------------------------------------------------
Thereafter inflation
rate 1.50% 1.50% 2.00% 2.00% 2.00%
----------------------------------------------------------------------------
(1) Sproule Associates Ltd.'s ("Sproule")'s (PetroBakken) US$/CDN$ forecast
rate is 0.932 and McDaniel's (HBU) is 0.975 throughout all years.
(2) 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 and Sproule in respect of
PetroBakken.
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 RESERVES
Petrobank is pleased to announce we have achieved a significant milestone with
the recognition by McDaniel of THAI(R) reserves at our Kerrobert project. This
third party validation of the THAI(R) technology confirms that THAI(R) is able
to economically extract oil in a reservoir that had previously been
conventionally produced. This Waseca Channel reservoir has been drilled and in
production for most of the past 30 years, yet over 90% of the petroleum
initially-in-place ("PIIP") is estimated to be otherwise unrecoverable using
conventional recovery methods. The THAI(R) technology has allowed us to create
sizable incremental value from this previously non-producing resource. McDaniel
has initially assigned 3.0 million barrels of proved reserves and 4.8 million
barrels of 2P reserves as at December 31, 2010, a significant first step in
recognizing the ultimate reserves potential of this field. McDaniel also
assigned proved, probable and possible reserves of 8.5 million barrels,
representing a 46% recovery factor (see "Possible Reserves"). As this is the
first year for THAI(R) reserve recognition, we anticipated a conservative
assessment by McDaniel in assigning 2P reserves representing only 26% of
exploitable oil-in-place ("EOIP") at Kerrobert. Over time, we anticipate that
ultimate recovery factors may achieve planned rates of 65% - 75% of EOIP.
Starting in 2009, McDaniel conducted extensive bottom up analysis of the THAI(R)
technology and subsequently validated THAI(R) by issuing the THAI(R) Transition
Report, as previously disclosed. The McDaniel THAI(R) Transition Report stated
that EOIP evaluated using THAI(R) is 17% higher than EOIP evaluated using steam
assisted gravity drainage ("SAGD") extraction in our Conklin bitumen pool.
Throughout 2010, Petrobank has demonstrated improved on-stream times and
production levels at our Kerrobert two well-pair project. At year-end 2010,
production levels were at economic rates with consistent on-stream times,
leading to McDaniel's initial reserve recognition. McDaniel has also recognized
the incremental value of THAI(R)'s in-situ upgrading with sales oil revenues
projected at approximately 10% higher than those for conventional heavy oil at
Kerrobert.
McDaniel also used Kerrobert as an analogue for their evaluation of our Dawson
property. McDaniel has assigned 32.5 million barrels of EOIP at Dawson (see
"Exploitable Oil-in-Place"). McDaniel is not yet able to assign reserves as it
is too early in this project's development. McDaniel has confirmed that they
will continue to use Kerrobert, and future THAI(R) projects, as analogues for
other heavy oil reservoirs that may ultimately be developed with THAI(R).
McDaniel has continued to evaluate our Conklin and May River bitumen properties
using SAGD extraction techniques as they have classified it as an immobile
bitumen reservoir. McDaniel has elected for this report to continue to estimate
our reserves and contingent resources at Conklin/May River assuming a SAGD
development. 2P reserves at Conklin have increased by 29% to 90.6 million
barrels of bitumen. Best estimate contingent resources at May River have
decreased 7% to 560 million barrels, primarily as a result of our 2010 oil sands
evaluation drilling results which slightly modified pool boundaries.
We believe that initial THAI(R) reserve recognition at Kerrobert is a
fundamental milestone for the THAI(R) technology and with continued operating
success we expect to be able to use THAI(R) as the basis for assigning reserves
to all our heavy oil and bitumen resources.
HBU RESERVES / RESOURCES SUMMARY
The following tables summarize the McDaniel report as at December 31, 2010.
Reserves were assigned to the Conklin, Alberta pilot project and our Kerrobert,
Saskatchewan property (4 sections) and contingent resources were assigned to our
May River leases (62 sections) at Conklin. The McDaniel report does not include
any reserves or recoverable resources associated with our Glover lease (10
sections), our Sutton Creek lease (36 sections), or our Dawson property (31.5
sections).
Reserves and Resources (1) as of December 31, 2010 2009 Change
(MMbbl) (MMbbl) %
----------------------------------------------------------------------------
Proved Reserves (P) 3.0 0.0 n/a
Proved plus Probable Reserves (2P) 95.4 70.0 36
Proved plus Probable plus Possible Reserves
(3P) (2) 110.0 78.8 40
Low Estimate Contingent Resources (3) (4) 474.0 483.2 (2)
Best Estimate Contingent Resources (3) (4) 560.1 599.1 (7)
High Estimate Contingent Resources (3) (4) 697.2 738.9 (6)
(1) Gross reserves and/or resources include the working interest
reserves/resources excluding the Company's royalty interests in reserves
and before deductions of royalties payable to others.
(2) Possible reserves are those additional reserves that are less certain
to be recovered than probable reserves. See "Possible 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. See "Contingent Resources".
(4) A low estimate means higher certainty (P90), a best estimate (P50)
means most likely and a high estimate means lower certainty (P10).
Before Tax Net Present Value - December 31, 2010 - $ Millions (1) (2) (3)
Net Present Value Discounted at: 0% 5% 8% 10%
----------------------------------------------------------------------------
Proved Reserves (1P) 20 11 6 4
Proved plus Probable Reserves (2P) 2,405 1,102 724 555
Proved plus Probable plus Possible
Reserves (3P) 3,163 1,405 929 722
Low Estimate Contingent Resources 10,180 3,923 2,190 1,450
Best Estimate Contingent Resources 14,088 5,258 3,000 2,067
High Estimate Contingent Resources 20,413 6,821 3,794 2,615
(1) Based on McDaniel forecast bitumen and heavy oil netback prices.
(2) Interest expenses and corporate overhead were not included.
(3) The net present values do not represent the fair market value of the
reserves and/or resources.
HEAVY OIL BUSINESS UNIT OPERATIONAL UPDATE
Kerrobert Expansion Project
Drilling and facilities construction activity levels at the Kerrobert 10
well-pair expansion have progressed rapidly since the project got underway
during Q3 2010. We commenced the pipeline infrastructure construction in late
September 2010 and shortly thereafter we began construction of the central
processing facility ("CPF"), which is now 75% complete. The first of two air
injection pads is complete and we are currently tying in the first of four
production satellites. The CPF is expected to be operational by mid-April.
Temporary steam generating facilities for the pre-ignition heating cycle
("PIHC") are in place and are in operation on the first air injection pad.
Drilling and completion of all 10 air injection wells is complete and three of
the new horizontal production wells are drilled and in the process of being
completed. We also abandoned the 13 pre-existing vertical and horizontal cold
production wells on the property. Facilities, drilling and completions
operations are generally on schedule except for the horizontal drilling program
which is currently four weeks delayed, due to early start-up issues with the
drilling rig and extreme cold weather conditions. We are implementing changes to
the drilling operations to return the program close to schedule, including
mobilizing an additional drilling rig, which should see all of the production
wells completed by the end of May. The drilling of the horizontal wells has met
or exceeded our design parameters with respect to trajectory and relationship to
the air injection wells. These wells are larger in diameter, have a higher open
flow area to the reservoir, a tighter mesh in the FacsRite(TM) screen for
improved solids control and an improved wellhead configuration, all of which are
expected to result in improved production capability.
We initiated the PIHC in three injector wells on the first pad on March 6th. The
PIHC will be performed only on the injection wells to condition the reservoir
and establish communication with the production well prior to air injection.
According to our start-up protocol, the PIHC is expected to last 20 to 60 days.
We expect air injection and production on these first expansion wells to
commence in the second quarter of 2011 with sustained target production in each
well being reached approximately one year after first air injection. The PIHC on
the second pad of five injector wells is planned for late in the second quarter
of 2011. We expect to have all of the new wells on air injection and producing
THAI(R) oil by the end of July.
Since the beginning of the year, the on-stream time of the two pilot wells has
improved dramatically to approximately 95 percent. For the past few months we
have been operating the wells in a controlled state to minimize downtime and
pump changes to ensure stability of economic production rates. The majority of
production continues to come from the KP2 well which was drilled relatively flat
as compared to the KP1 well where the toe is located higher in the reservoir,
adversely affecting communication with the combustion front and well control.
The well configuration for the 10 new producer wells will mitigate this issue as
they are planned to be drilled similar to KP2. We are evaluating a remediation
strategy for KP1 to improve communication with the mobile oil zone and improve
production. Peak production rates for the two wells combined have been as high
as 355 barrels of oil per day ("bopd") in the last four months. From December 1,
2010 to February 28, 2011, average calendar day production rate from the KP2
well has been approximately 121 bopd and KP1 has been approximately 35 bopd. The
produced oil has been consistently upgraded in-situ by 4 - 7 degrees API,
requiring less diluent to meet pipeline API quality. Since we have achieved our
objective of formal reserves recognition at Kerrobert, we will focus on
increasing production towards design capacity of 600 bopd per well. Under normal
operations, design capacity is expected to be achieved approximately one-year
after air injection has commenced.
Dawson Project
The Dawson property is situated in a large Bluesky heavy oil/oil sands fairway
in the Peace River region of northwest Alberta. The upper portions of this
formation contain 11 degrees API heavy oil, which is comparable to other
conventional heavy oil reservoirs throughout Western Canada. Existing
conventional cold production typically recovers less than 10 percent of PIIP;
with THAI(R) we expect to achieve significantly higher recovery rates.
Based on a 2010 McDaniel evaluation of the resource, the Dawson property was
estimated to contain best estimate EOIP (10 metre reservoir thickness cut-off)
of 32.5 million barrels (see "Exploitable Oil-in-Place"). As we reported last
fall, Petrobank acquired Shell's 50% working interest in the Dawson project and
a 100% working interest in an additional 27 sections of land prospective for
Bluesky heavy oil resource adjacent to the Dawson project. As a result of this
acquisition, we now have a 100 percent interest in 31.5 sections of land in the
Dawson area.
We received final Energy Resources Conservation Board ("ERCB") and Alberta
Environment ("AENV") approval for our initial Dawson project during the fourth
quarter of 2010. Dawson will initially consist of two THAI(R) well-pairs plus
associated surface facilities. We intend to move the surface facilities from our
first two wells at the Kerrobert project, as they will be incorporated into the
Kerrobert expansion facilities, to our Dawson project during the third quarter
of 2011. We anticipate work on the initial Dawson project to begin during the
second quarter of 2011 with PIHC commencing during the third quarter. Production
is expected to commence in the fourth quarter of 2011 with ramp-up to design
capacity over the following twelve months.
Also at Dawson we will be drilling a minimum of three stratigraphic wells to
expand the geological extent of the reservoir. All wells will be cored through
the Bluesky/Gething for rock property analysis and one well will be drilled
deeper to test the Pekisko which also has heavy oil potential across our
additional 27 sections of land offsetting the project.
In order to capitalize on the full potential at Dawson, the environmental
assessment associated with a regulatory application has been started for the
second phase of the Dawson development. Phase II is being designed as a 10,000
bopd project and the required regulatory applications for both the ERCB and AENV
are scheduled to be submitted during the third quarter of 2011. The regulatory
review cycle could take up to 18 months with a project execution time similar to
our Kerrobert project.
Conklin Pilot Project
We continue to evaluate our Conklin pilot project for the demonstration of
potential enhancements to the THAI(R) process. To date, Conklin has proven the
operation and effectiveness of THAI(R) in a bitumen reservoir. The project has
confirmed that we can ignite and sustain high temperature combustion and through
the use of 4-D seismic we have been able to establish that the combustion front
progresses along the wellbore from toe-to-heel. We have also demonstrated the
ability to manage and control the combustion front and the overall safe
operation of the THAI(R) process. After some initial challenges with sand
production, we deployed FacsRite(TM) liners in two wells, which overcame the
problem and is now being incorporated in to all our future THAI(R) well designs.
The Conklin pilot has also demonstrated that the process is operationally robust
and that the process produces in-situ upgraded oil that can attract a premium
field price compared to native oil. The original well design and surface
facilities at Conklin have provided excellent prototype modelling for current
design enhancements which we are employing in all of our new facilities.
Unfortunately, the original wells are sub optimal for continued operation. In
addition, the localized reservoir at Conklin remains a challenge as it is of
poorer quality with relatively thin basal sand sections (five to eight metres)
in the toe area of the wells, resulting in low initial sustainable production
rates. The reservoir quality improves closer to the heel of the wells to over 15
metres of basal sands. We are reviewing options to utilize Conklin as a field
testing facility for technology enhancements, which may include drilling new
injector and production wells in better parts of the reservoir.
May River Project
The May River project is currently in the final detailed engineering phase, and
orders have been placed for some long lead time equipment, including power
generation turbines and air compression. Upgrades to the existing roads have
been completed, along with other infrastructure work that can be accomplished
prior to receiving final regulatory approval. Draft approval from AENV, which is
conditional on receiving ERCB approval, was received on April 12, 2010. ERCB
project approval remains in process, with a third round of supplemental
information requests having been received and responded to in early 2011.
We plan to drill 12 to 17 stratigraphic wells on our leases this year to further
evaluate additional resource potential, optimize well placements for the 18
well-pairs planned for the 10,000 bopd Phase 1 development and further delineate
the resource for future expansion phases of the May River project.
Archon Technologies Ltd. ("Archon")
Archon, our wholly-owned technology subsidiary, was granted additional patents
in Russia and Mexico during the fourth quarter of 2010 and first quarter of
2011, respectively. Further research is continuing and we expect field scale
testing of new concepts, such as enriched oxygen injection and direct oxidation
of sulphur in produced gas, during 2011.
Business Development
We remain engaged with several parties interested in licensing the THAI(R) and
CAPRI(R) technologies. Although an agreement has not been finalized to date, we
continue to make progress in the negotiation of formal agreements with respect
to potential licensing arrangements.
Land Acquisition
Petrobank acquired 3.5 sections (907.7 hectares) of land in a Saskatchewan Crown
Sale in late 2010. The lands are located in the Plover Area on the same trend as
the Kerrobert project. We plan to purchase or shoot 3-D seismic and drill a
stratigraphic well in 2011 to further define the resource potential.
PETROBAKKEN (59% OWNED BY PETROBANK)
PetroBakken announced year end reserves on February 21, 2011, highlighted as
follows:
-- 2010 average production of 41,688 boepd increased 58% over 2009.
-- Proved plus probable Company Interest(1) reserves increased by 18% to
171.4 MMboe at December 31, 2010, replacing production by 274% (2P
Company Gross(2) reserves increased 18% to 169.2 MMboe).
-- Our new entry into the Cardium play in Alberta during 2010, through
three corporate acquisitions and our initial drilling campaign, has
yielded incremental 2P reserve additions of 43 MMboe. Our first 55
operated wells drilled in 2010 resulted in reserve recognition for 149
of our undeveloped Pembina Cardium locations (out of our current
inventory of over 650). This drilling campaign has accelerated into
2011.
-- From July 2010 to mid-February 2011, PetroBakken drilled 80 (65.9 net)
PetroBakken-executed Cardium wells, of which:
-- 44 (39 net) wells are producing,
-- 16 (11.4 net) wells are completed but not yet producing, and
-- 20 (15.5 net) wells are waiting on completion.
-- Production results from single-leg horizontal multi-stage fracture
stimulated Cardium wells continue to meet expectations with:
-- seven day average rates of 423 barrels of oil per day ("bopd") from
40 wells,
-- thirty day average rates of 246 bopd from 38 wells, and
-- sixty day average rates of 176 bopd from 21 wells.
-- In PetroBakken's 2010 reserve report, producing Bakken bilateral
horizontal wells received, on average, an incremental 35,000 barrels
("bbls") of oil over 2009 reserve assignments for 2P undeveloped
bilateral horizontal locations.
-- Activity in the Bakken play continues to move forward with bilateral
drilling and enhanced oil recovery ("EOR") projects.
Notes:
(1) "Company Interest" reserves represent PetroBakken's working interest
share of reserves including its royalty interests in reserves and
before deduction of the Company's royalty obligations.
(2) "Company Gross" reserves represent PetroBakken's working interest share
of reserves excluding its royalty interests in reserves and before
deduction of royalty obligations.
PetroBakken Reserves
Forecast Prices(1)
As at December 31, 2010
Royalty Company
Interests Interest
Company Gross(2) (3) (4)
--------------------------------------------------------
Total Natural
Oil NGL Gas Sub-total Sub-total Total
(Mbbl) (Mbbl) (MMcf) (Mboe) (Mboe) (Mboe)
----------------------------------------------------------------------------
Proved Developed
Producing 50,888 3,807 63,790 65,326 857 66,183
Total Proved 80,866 5,414 94,337 102,003 1,025 103,028
Proved + Probable
(2P) 136,153 8,871 148,754 169,816 1,561 171,377
----------------------------------------------------------------------------
PetroBakken Net Present Value - Before Tax ($ millions)(5)
Forecast Prices(1)
As at December 31, 2010
0% 5% 8% 10% 15%
----------------------------------------------------------------------------
Proved Developed Producing 3,355.3 2,574.1 2,285.9 2,135.0 1,849.3
Total Proved 4,765.3 3,541.1 3,084.3 2,844.8 2,392.2
Proved + Probable (2P) 8,367.7 5,521.1 4,598.1 4,141.6 3,325.6
----------------------------------------------------------------------------
PetroBakken Working Interest Reserve Reconciliation - Forecast Prices(1)
(Mboe)(2)
Developed Total Proved+
Producing Proved Probable
----------------------------------------------------------------------------
PetroBakken reserves at
December 31, 2009 59,412 89,470 143,638
2010 production net of royalty
interest (15,031) (15,031) (15,031)
Net acquisitions 3,283 5,344 6,817
Net additions and revisions 17,662 22,220 34,393
----------------------------------------------------------------------------
PetroBakken reserves at
December 31, 2010 65,326 102,003 169,816
PetroBakken year-over-year
increase in reserves 10% 14% 18%
PetroBakken production
replacement 139% 183% 274%
----------------------------------------------------------------------------
Notes:
(1) Based on the Sproule price forecast effective December 31, 2010.
(2) Company Gross reserves, which represent PetroBakken's working interest
share of reserves excluding its royalty interests in reserves and
before deduction of royalty obligations.
(3) Royalty interest reserves owned by PetroBakken.
(4) "Company Interest" reserves, which represent PetroBakken's working
interest share of reserves including its royalty interests in reserves
and before deduction of PetroBakken's royalty obligations.
(5) Company working interest reserves value plus royalties received less
royalties and burdens.
PetroBakken FD&A Costs(1)
For the year ended December 31, 2010
Acquisitions
F&D (2) Dispositions FD&A(4)
----------------------------------------------------------------------------
Capital expenditures
(unaudited-$000s)
Capital expenditures 781,523 - - 781,523
Acquisition/(Disposition)
capital(3) - 714,305 (133,632) 580,673
----------------------------------------------------------------------------
Total capital 781,523 714,305 (133,632) 1,362,196
Less: Land value 94,751 352,002 - 446,753
----------------------------------------------------------------------------
Total capital excluding
land value 686,772 362,303 (133,632) 915,443
Change in FDC ($000s)
Total Proved 44,932 133,724 (22,835) 155,821
Proved + Probable (2P) 116,303 173,837 (32,540) 257,600
Total costs ($000s)
Total Proved 826,455 848,029 (156,467) 1,518,017
Proved + Probable (2P) 897,826 888,142 (166,712) 1,619,796
Net reserve additions
(mboe)
Total Proved 22,220 13,608 (8,264) 27,564
Proved + Probable (2P) 34,393 21,235 (14,419) 41,209
----------------------------------------------------------------------------
FD&A costs ($/boe)
(including land)
Total Proved 37.19 62.32 18.93 55.07
Proved + Probable (2P) 26.11 41.82 11.52 39.31
FD&A costs ($/boe)
(excluding land)
Total Proved 32.93 36.45 18.93 38.86
Proved + Probable (2P) 23.35 25.25 11.52 28.47
----------------------------------------------------------------------------
For the year-ended Dec. 31,
2009
FD&A costs ($/boe)
(including land)
Total Proved 45.22 46.81 43.57 46.83
Proved + Probable (2P) 33.02 32.42 32.89 32.48
FD&A costs ($/boe)
(excluding land)
Total Proved 40.52 42.97 43.57 42.56
Proved + Probable (2P) 30.37 29.96 32.89 29.81
For the three years-ended
Dec. 31, 2010
FD&A costs ($/boe)
(including land)
Total Proved 36.17 49.63 27.94 46.31
Proved + Probable (2P) 27.41 34.12 18.38 33.29
FD&A costs ($/boe)
(excluding land)
Total Proved 30.74 41.31 27.94 38.29
Proved + Probable (2P) 23.66 28.77 18.38 27.94
----------------------------------------------------------------------------
(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 corporate acquisitions of Berens Energy Ltd., Rondo
Petroleum Inc. and Result Energy Inc. and certain other asset
acquisitions.
(3) Portion of the purchase prices allocated to property, plant & equipment
and reflects the net present value of each corporate acquisition as at
its acquisition date based on 2P NPV10%, before tax.
(4) PetroBakken uses FD&A as a measure of the efficiency of its overall
capital program including the effect of acquisitions and dispositions.
FINANCIAL STATEMENT RELEASE DATE AND INVESTOR CONFERENCE CALL
Petrobank plans to release fourth quarter 2010 financial results after markets
close on Monday, March 14, 2011. Management of Petrobank will be holding a
conference call for investors, financial analysts, media and any interested
persons on Wednesday, March 16, 2011 at 8:00 a.m. Mountain Time (10:00 a.m.
Eastern Time) to discuss Petrobank's fourth quarter financial and operating
results. The investor conference call details are as follows:
Live call dial-in numbers: 416-340-8527 / 877-440-9795
Replay dial-in numbers: 905-694-9451 / 800-408-3053
Replay pass code: 7468252
The live audio webcast link is:
http://events.digitalmedia.telus.com/petrobank/031511/index.php.
Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas
exploration and production company with operations in western Canada. The
Company operates high-impact projects through two business units and a
technology subsidiary. Petrobank's 59% 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. PetroBakken is applying leading edge technology to a
multi-year inventory of Bakken and Cardium light oil development locations,
along with a significant inventory of opportunities in the Horn River and
Montney gas resource plays in northeast BC. PetroBakken's strategy is to deliver
accretive production and reserves growth, along with an attractive dividend
yield. Whitesands Insitu Partnership, a partnership between Petrobank and its
wholly-owned subsidiary Whitesands Insitu Inc., owns 104 net sections of oil
sands leases in Alberta, 36 sections of oil sands licenses in Saskatchewan and 4
net sections of petroleum and natural gas rights in Kerrobert, Saskatchewan, and
operates the Whitesands project which is field-demonstrating Petrobank's
patented THAI(R) heavy oil recovery process. THAI(R) 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(R) and CAPRI(R)
are registered trademarks of Archon Technologies Ltd., a wholly-owned subsidiary
of Petrobank Energy and Resources Ltd., for specialized methods for recovery of
oil from subterranean formations through in-situ combustion techniques and
methodologies with or without upgrading catalysts. Used under license by
Petrobank Energy and Resources Ltd.
Forward-Looking Statements: Certain information provided in this press release
constitutes forward-looking statements. Specifically, this press release
contains forward-looking statements relating to financial results, results from
operations, the timing of certain projects, anticipated recovery factors, future
oil and gas exploration and development activities, projected levels of in situ
upgrading and resulting oil pricing, potential resource and reserve increases,
future production rates, timing for regulatory approvals and the completion of
potential licensing agreements. Forward-looking statements are necessarily based
upon assumptions and judgments with respect to the future including, but not
limited to, the outlook for commodity markets and capital markets, success of
future evaluation and development activities, the successful application of
technology, prevailing commodity prices, the negotiation of future licensing
arrangements, the performance of producing wells and reservoirs, well
development and operating performance, general economic and business conditions,
weather, and the regulatory and legal environment. 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, risks associated with the
development and application of early stage technology, recompletions and related
activities; timing and rig availability; fluctuation in foreign currency
exchange rates; the uncertainty of reserve and resource 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". "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". "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. In respect of the May River project, contingencies include
current uncertainties around the specific scope and timing of the development of
the project; lack of regulatory approvals; uncertainty regarding marketing plans
for production from the subject area; and need for improved estimation of
project costs. Contingent resources do not constitute, and should not be
confused with, reserves. There is no certainty that it will be commercially
viable to produce any portion of the contingent resources on the May River
property.
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.
Exploitable Oil-In-Place (EOIP): Exploitable Oil in Place is the estimated
discovered volume of oil, from known accumulations, before any production has
been removed, which is contained in a subsurface stratigraphic interval that
meets or exceeds certain reservoir characteristics considered necessary for the
application of known recovery technologies. Examples of such reservoir
characteristics include continuous net pay, porosity, and mass bitumen content.
EOIP is a resources that does not constitute, and should not be confused with,
reserves. There is no certainty that it will be commercially viable to produce
any portion of the resource.
Petroleum Initially-In-Place (PIIP): That quantity of petroleum that is
estimated to exist originally in naturally occurring accumulations. It includes
that quantity of petroleum that is estimated, as of a given date, to be
contained in known accumulations, prior to production, plus those estimated
quantities in accumulations yet to be discovered.
Net Present Values (NPV): Estimated values of future net revenue disclosed in
this press release do not necessarily represent fair market values.
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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