Petrobank Energy and Resources Ltd.
TSX : PBG
OSLO STOCK EXCHANGE : PBG

Petrobank Energy and Resources Ltd.

March 11, 2008 23:43 ET

Petrobank Announces Record Year End Results and Reserves

CALGARY, ALBERTA--(Marketwire - March 11, 2008) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) (OSLO:PBG) is pleased to announce record fourth quarter and year-end financial and operating results, along with increases in our year-end reserve evaluations.

(All references to $ are Canadian dollars unless otherwise noted)

HIGHLIGHTS

In 2007 we positioned ourselves to be a key player in the Bakken formation in southeast Saskatchewan, launched a significant exploration campaign in Colombia, continued to expand our strategy to commercialize the THAI™ process and obtained additional opportunities to apply our technology. Some of the highlights of 2007 include the following:

- Average annual production increased by 94% to 10,243 barrels of oil equivalent per day ("boepd") in 2007 from 5,269 boepd in 2006. Canadian Business Unit ("CBU") production increased by 78% to 5,476 boepd and production from the Latin American Business Unit ("LABU") increased by 117% to 4,767 barrels of oil per day ("bopd") in 2007.

- Fourth quarter average daily production increased by 217% in 2007 to 17,829 boepd from 5,632 boepd in 2006. CBU production increased by 153% to 8,254 boepd and production from the LABU increased by 304% to 9,575 bopd.

- Average daily production increased to 23,677 boepd in February 2008 comprised of 14,750 boepd from the CBU and 8,927 bopd from the LABU.

- For the year ended 2007, funds flow from operations increased by 187% to $174.9 million or $2.10 per diluted share.

- In the fourth quarter of 2007 funds flow from operations increased by 487% to $92.7 million. On a per diluted share basis, funds flow from operations increased by 377% to $1.05.

- For the year ended 2007, net income increased by 252% to $81.4 million or $0.99 per diluted share.

- In the fourth quarter of 2007 net income increased by 1,432% to $40.1 million. On a per diluted share basis, net income increased by 1,025% to $0.45.

- CBU proved plus probable plus possible ("3P") reserves increased by 270% to 47.1 million boe at December 31, 2007 with net present value, before tax, discounted at 10% of $1.1 billion.

- CBU 3P finding and development costs of $16.57/bbl representing a 3.6 times recycle ratio using fourth quarter 2007 CBU operating netbacks.

- Peerless Energy Inc. ("Peerless") was acquired by Petrobank on January 28, 2008 for approximately $337 million, including net debt assumed. Peerless 3P reserves at December 31, 2007 totalled 18.7 million boe with net present value, before tax, discounted at 10% of $445.6 million. Financial results for Peerless will not be recognized until the first quarter of 2008.

- Heavy Oil Business Unit's ("HOBU") 3P reserves plus high estimate contingent recoverable bitumen resources totalled 804.8 million barrels at December 31, 2007 with net present value, before tax, discounted at 8% of $2.2 billion.

- LABU 3P reserves increased by 53% to 51.9 million barrels at December 31, 2007 with net present value, before tax, discounted at 10% of $1.8 billion.

- LABU 3P finding and development costs of US$18.27/bbl representing a 3.4 times recycle ratio using fourth quarter 2007 LABU operating netbacks.

FINANCIAL & OPERATING HIGHLIGHTS

The following table provides a summary of Petrobank's financial and operating results for the three and twelve month periods ended December 31, 2007 and 2006. Consolidated financial statements with Management's Discussion and Analysis ("MD&A") are available on our website at www.petrobank.com under the "Investor Relations - Financial Reports" section.




Financial Three months ended Years ended
($000s, except where December 31, % December 31, %
noted) 2007 2006 change 2007 2006 change
----------------------------------------------------------------------------
Oil and natural gas
revenue 122,469 25,729 376 250,366 99,228 152
Funds flow from
operations (1) 92,733 15,786 487 174,864 60,994 187
Per share - basic ($) 1.20 0.23 422 2.31 0.91 154
Per share - diluted ($) 1.05 0.22 377 2.10 0.88 139
Net income 40,146 2,620 1,432 81,427 23,106 252
Per share - basic ($) 0.52 0.04 1,200 1.08 0.35 209
Per share - diluted ($) 0.45 0.04 1,025 0.99 0.33 200
Capital expenditures 136,528 71,337 91 510,264 229,693 122
Acquisitions - - - 120,250 - -
Net working capital /
(net debt) (1) (2) 16,068 (40,545) - 16,068 (40,545) -
Common shares
outstanding, end
of year (000s)
Basic (2) 77,271 72,125 7 77,271 72,125 7
Diluted (3) 90,038 76,538 18 90,038 76,538 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operations
Canadian Business Unit
("CBU") operating
netback ($/boe
except where noted)
(1) (4)
Oil and NGL revenue
($/bbl) 80.83 54.83 47 75.64 61.18 24
Natural gas revenue
($/mcf) (5) 6.14 6.15 - 6.44 6.21 4
Oil and natural gas
revenue (5) 72.52 43.86 65 62.81 44.40 41
Royalties 5.11 4.47 14 4.86 6.28 (23)
Production expenses 7.99 8.06 (1) 8.19 6.89 19
Transportation expenses 0.10 0.27 (63) 0.19 0.39 (51)
----------------------------------------------------------------------------
Operating netback 59.32 31.06 91 49.57 30.84 61

Latin American Business
Unit ("LABU")
operating netback
($/bbl) (1)
Oil revenue 76.53 57.68 33 71.74 61.68 16
Royalties 7.74 4.61 68 6.68 4.95 35
Production expenses 7.34 8.39 (13) 7.37 7.78 (5)
----------------------------------------------------------------------------
Operating netback 61.45 44.68 38 57.69 48.95 18

Average daily
production (4)
CBU - oil and NGL
(bbls) 6,691 1,265 429 3,579 918 290
CBU - natural gas
(mcf) 9,379 11,968 (22) 11,379 12,940 (12)
----------------------------------------------------------------------------
Total CBU conventional
(boe) 8,254 3,260 153 5,476 3,075 78
LABU - oil (bbls) 9,575 2,372 304 4,767 2,194 117
----------------------------------------------------------------------------
Total Company
conventional (boe) 17,829 5,632 217 10,243 5,269 94
----------------------------------------------------------------------------
Reserves/Resources by
Business Unit
Heavy Oil (mbbls) 804,776 660,387 22
Canadian (mboe) 47,073 12,726 270
Peerless (mboe) (5) 18,726 - -
Latin American -
Colombia (mbbls) 51,930 33,906 53
----------------------------------------------------------------------------
Total Company (mboe) (6) 910,301 594,823 53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Non-GAAP measure. See "Non-GAAP Measures" section within MD&A.
(2) Excludes the effect of acquiring Peerless on January 28, 2008.
Acquisition costs, including Peerless net debt assumed, totalled
approximately $337 million. In connection with the acquisition,
4,931,672 common shares of Petrobank were issued.
(2) Assumes 8.8 million common shares will be issued upon conversion of the
Company's convertible debentures which were issued in 2007.
(3) Six mcf of natural gas is equivalent to one barrel of oil equivalent
("boe"). Heavy Oil Business Unit ("HOBU") bitumen volumes are excluded
from average daily production as Whitesands operations are considered
to be in the pre-operating stage and accordingly are capitalized.
(4) Canadian sales prices are shown after forward gas sales contracts.
(5) Peerless proved plus probable plus possible reserves as at December 31,
2007 are shown. Peerless was acquired by Petrobank on January 28, 2008.
(6) Company working interest proved plus probable plus possible reserves and
contingent recoverable resources (high estimate) excluding royalty
interest reserves and before deduction of royalties payable. Only
represents Petrobank's share (100% at December 31, 2007 and 84% at
December 31, 2006) of the HOBU's reserves and resources and Petrobank's
share (76.5% at December 31, 2007 and 80.73% at December 31, 2006) of
the LABU's (Petrominerales Ltd.) reserves.


CORPORATE RESERVES/RESOURCES SUMMARY BY BUSINESS UNIT

Working Interest Reserves, Forecast Prices
CBU Peerless (1) LABU HOBU Total Company (2)
(mboe) (mboe) (mbbls) (mbbls) (mboe)
-------------------------------------------------------
Developed Producing 8,239 5,967 9,118 - 21,181
Total Proved 19,433 8,873 20,597 - 44,063
Proved + Probable
(2P) 30,469 13,306 36,977 25,476 97,538
Proved + Probable +
Possible (3P) 47,073 18,726 51,930 78,904 184,429
High Estimate
Contingent
Resources - - - 725,872 725,872
3P + High Estimate
Contingent Resources 47,073 18,726 51,930 804,776 910,301

(1) Peerless reserves as at December 31, 2007 are shown. Peerless was
acquired by Petrobank on January 28, 2008.
(2) Total Company includes only Petrobank's 76.5% share of the LABU's
reserves at December 31, 2007.

Net Present Value, Before Tax, Forecast Prices (millions)(1)

CBU Peerless (2) LABU HOBU Total Company (3)
($) ($) (US$) ($) ($)
-------------------------------------------------------
Developed Producing 317.3 169.4 447.9 - 825.3
Total Proved 524.0 252.0 787.4 - 1,371.2
Proved + Probable
(2P) 779.1 344.6 1,314.9 26.0 2,143.6
Proved + Probable +
Possible (3P) 1,082.0 445.6 1,819.4 329.0 3,231.9
High Estimate
Contingent Resources - - - 1,895.0 1,895.0
3P + High Estimate
Contingent
Resources 1,082.0 445.6 1,819.4 2,224.0 5,126.9


Net Present Value, After Tax, Forecast Prices (millions) (1)

CBU Peerless (2) LABU HOBU Total Company (3)
($) ($) (US$) ($) ($)
-------------------------------------------------------
Developed Producing 317.3 150.5 379.4 - 754.6
Total Proved 470.6 205.0 596.4 - 1,126.4
Proved + Probable
(2P) 650.1 269.9 905.1 5.0 1,609.2
Proved + Probable +
Possible (3P) 866.5 341.3 1,204.2 233.0 2,351.1
High Estimate
Contingent Resources - - - 1,297.0 1,297.0
3P + High Estimate
Contingent Resources 866.5 341.3 1,204.2 1,530.0 3,648.1

(1) Net present values are discounted at 10% for CBU, Peerless, and LABU
and at 8% for HOBU.
(2) Peerless reserves as at December 31, 2007 are shown. Peerless was
acquired by Petrobank on January 28, 2008.
(3) Total Company includes only Petrobank's 76.5% share of the LABU's
reserves at December 31, 2007 converted using a US$/$ exchange rate of
0.9881.


The full reserve disclosure tables, as required under National Instrument 51-101, will be contained in Petrobank's 2007 Annual Information Form, which will be filed on SEDAR on or before March 31, 2008.

HEAVY OIL BUSINESS UNIT (HOBU)

The following tables summarize the McDaniel & Associates Consultants Ltd. ("McDaniel") Whitesands reserve reports as at December 31, 2007. 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), or our 50% interest in the Dawson property (4 sections).

To-date, the McDaniel's reports are still based on SAGD technology as it is the presently recognized technology used to define in-situ oil sands reserves. This does not in any way reflect the technical merits of the THAI™ process; it is simply the only way for the Company to presently recognize a portion of our reserve and resource potential on the Whitesands leases using industry accepted norms. Once McDaniel's can independently certify reserves associated with the THAI™ process, this SAGD-based analysis will be phased out.

THAI™ 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™ 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™ is expected to have an enormous impact of on resource recovery and estimates of reserve volumes.



Reserves and Resources (1) as of December 31, 2007:
Based on SAGD (mbbl)
----------------------------------------------------------------------------
Probable Reserves (2P) 25,476
Probable plus Possible Reserves (3P) 78,904
Low Estimate Contingent Resources (2) (3) 482,108
Best Estimate Contingent Resources (2) (3) 635,422
High Estimate Contingent Resources (2) (3) 725,872

2P + Best Estimate Contingent Resources 660,898
3P + High Estimate Contingent Resources 804,776

(1) Gross reserves and/or resources include the working interest
reserves/resources before deductions of royalties payable to others.
(2) 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.
(3) A low estimate means higher certainty (P90), a best estimate (P50)
means most likely and a high estimate means lower certainty (P10).


Whitesands Before Tax Net Present Value - December 31, 2007 -
$ Millions (1) (2) (3)
Based on SAGD
Net Present Value Discounted at: 0% 5% 8% 10%
----------------------------------------------------------------------------

Probable Reserves (2P) 148 62 26 7
Probable plus Possible Reserves (3P) 1,124 515 329 244
Low Estimate Contingent Resources 4,863 1,436 536 167
Best Estimate Contingent Resources 8,379 2,812 1,426 867
High Estimate Contingent Resources 11,901 3,687 1,895 1,210

2P + Best Estimate Contingent Resources 8,527 2,874 1,452 874
3P + High Estimate Contingent Resources 13,025 4,202 2,224 1,454

(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, 2007 -
$ Millions (1) (2) (3)
Based on SAGD
Net Present Value Discounted at: 0% 5% 8% 10%
----------------------------------------------------------------------------

Probable Reserves (2P) 109 36 5 (12)
Probable plus Possible Reserves (3P) 840 375 233 167
Low Estimate Contingent Resources 3,618 931 228 (58)
Best Estimate Contingent Resources 6,246 1,983 926 502
High Estimate Contingent Resources 8,874 2,650 1,297 781

2P + Best Estimate Contingent Resources 6,355 2,019 931 490
3P + High Estimate Contingent Resources 9,714 3,025 1,530 948

(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.


Reserves

In the fourth quarter, independent reserve evaluator McDaniel initiated an assessment of the performance of the THAI™ project to determine, based on the first year of operating data, when a NI 51-101 reserve evaluation could be developed. McDaniel concluded that additional operating data would be required to meet the regulatory requirements for the assignment of reserves and resources for THAI™. Some of the considerations for requiring additional operational data are that the Whitesands project is the first application of THAI™ in the field and there is no other analogous data for comparison or forecasting purposes, two of the three wells were brought on-stream during 2007 and are at earlier stages in their production life than the first well, and plant operations during 2007 were inconsistent due to frequent sand clean outs and facilities upgrades. In the reservoir the process is operating as anticipated with continued high temperature combustion, continued combustion zone development laterally and vertically, upgrading in-situ and oil cuts of around 50%. While gross fluid production rates per well have been variable over the year, they have proven the capacity to produce at rates up to 2,000 barrels of fluid per day, demonstrating both the lifting capacity of the wells and the process. McDaniel is continuing the THAI™ evaluation and, with more stable operations, we expect to be able to have an update by mid year. In the December 31, 2007 SAGD based evaluation, McDaniel has excluded the recoverable bitumen resource for the current Whitesands pilot project site as these barrels are being developed using THAI™.

Our winter drilling resource delineation program commenced late in the fourth quarter of 2007 and is continuing into the first quarter of 2008. A total of 20 wells are being drilled including one well into our new land at Glover, south of our Whitesands land base, acquired in the second quarter of 2007. Sixteen of these new stratigraphic wells have been incorporated into our year end reserve report prepared by McDaniel.

McDaniel has evaluated our main Whitesands land base covering 62 sections of oil sands leases and estimates up to 804.8 million barrels of recoverable bitumen using SAGD technology for the P10 case (3P plus high estimate contingent resource), a 22% increase from December 31, 2006 and a 1% increase from the March 1, 2007 report. McDaniel estimates 660.9 million barrels recoverable in the P50 case (2P plus best estimate contingent resource), a 34% increase from December 31, 2006 and a 10% increase from the March 1, 2007 report. These values exclude the recoverable resource for the Whitesands pilot area which is being produced using THAI™.

We are planning to drill a stratigraphic well on our Dawson leases (50% working interest) in the second quarter of 2008, following which we will have McDaniel complete an evaluation of the property.

Whitesands Update

Operations at the Whitesands site have focused on the installation of the new sand-handling system, which became operational for all three wells late in December 2007. This system has increased on-stream time and improved our ability to manage produced sand to be able to flow the wells to their target potential. We have also added key upgrades to other facilities to enhance the produced gas H2S removal facilities, and improve heat integration to accommodate the planned three-well expansion. The regulatory approval for the produced gas H2S removal facilities was received in February, allowing us to start increasing air injection, which will ultimately allow full development of the combustion front and increased production rates. Because of the extreme cold weather during this time we focused on maintaining plant operations which slowed the rate of increase of air injection until recently. With the improved on-stream factors, we expect to see more stable production rates, as air injection rates are further increased.

Our three well expansion project application, adjacent to the existing Whitesands site, is now moving through the approval process and we are ready to drill these THAI™/CAPRI™ wells immediately following receipt of final regulatory approvals, which are expected in the second quarter. With prompt approval, these wells could be on-stream in the third quarter of 2008.

We also now expect to spud our next well on the current plant footprint in mid-April 2008. This well replaces the P3 well and will be the first field test of our CAPRI™ process, which integrates a catalyst along the horizontal production well, increasing the in-situ upgrading effect. This well advances the testing of our revised slotted liner designed for improved downhole sand control and will be produced through a new, simplified fluids separation design which is expected to greatly improve operational flexibility. By using the existing combustion zone, we expect to avoid the pre-ignition heating cycle and quickly commence production.

May River Project

The May River Project is our commercial expansion plan for the THAI™ technology at the Whitesands site. The central facilities for the project will be located approximately two kilometers from the current Whitesands site. The project is planned to be built in phases, beginning with initial production capacity of 10,000 to 15,000 barrels of oil per day ('bopd") of partially upgraded bitumen, ultimately building capacity to 100,000 bopd. The regulatory applications for the first phase should be filed by mid-2008. With timely receipt of regulatory approvals, construction could begin in early 2009 with project startup in late 2009.

Dawson Project

The Dawson project is a joint venture project involving our first Alberta-based third party THAI™ license. This project is located in Alberta's Peace River Arch area and is our initial THAI™ project in a conventional heavy oil reservoir, another important step in taking the technology to a global market. We are planning to implement a two-well project and with timely regulatory approval we could commence construction at Dawson later in 2008.

Sutton Creek, Saskatchewan

In 2007 we acquired a township of land (36 square miles or 23,040 acres) with oil sands potential at Sutton Creek, Saskatchewan. This new land position is located within a new and promising oil sands fairway. A 2D seismic survey is planned for the area in the first half of 2008.

Technology Development-Archon Technologies Ltd.

We have advanced several technology innovations which will be incorporated into our commercial projects, including the May River Project, to improve operational efficiency and flexibility and to reduce the environmental impact of commercial development. Our centralized operations will reduce the surface footprint and the simplified fluids separation design will provide for more flexible and robust production facilities. Enriched oxygen injection, electrical cogeneration, and solid sulfur recovery will also be incorporated into the commercial design and will have a major impact in further reducing our overall environmental footprint and greenhouse gas emissions. Enriched oxygen injection can reduce the volume of injected air and the resulting produced gases may be used to generate enough power to make the project energy self sufficient, further reducing greenhouse gas emissions. Using a new technology, we also plan to recover sulfur from the produced H2S, eliminating most SO2 emissions.

CANADIAN BUSINESS UNIT (CBU)

Reserves

Our CBU reserve engineers, Sproule Associates Limited ("Sproule"), have completed their evaluation of our conventional Canadian reserves and the reserves associated with the Peerless acquisition, as at December 31, 2007. All reserves are based on forecast prices and costs and are Company gross reserves and include the Peerless reserves, which were effectively acquired on January 28, 2008. Summary results of the Sproule reports are highlighted as follows:

- Total proved reserves of 28.3 million boe.

- Proved plus probable (2P) reserves of 43.8 million boe.

- Proved, probable and possible (3P) reserves of 65.8 million boe.

- NPV 10% (before taxes) of $1,123.7 million (2P), $1,527.6 million (3P).

- Proved plus probable reserve additions replaced 1,258% of 2007 production.



CBU and Peerless Working Interest Reserves(1)
Forecast Prices(2)

Light and
Natural Medium
Gas Oil NGL Total
(mmcf) (mbbl) (mbbl) (mboe)
----------------------------------------------------------------------------
Developed Producing 26,940 8,918 798 14,206
Total Proved 47,878 18,671 1,655 28,306
Proved + Probable (2P) 67,158 30,006 2,576 43,775
Proved + Probable + Possible (3P) 91,106 46,820 3,794 65,799

(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, 2007.


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 2007 included 432 boepd of royalty income production.



CBU and Peerless Net Present Value - Before Tax ($ millions)
Forecast Prices
As at December 31, 2007
0% 5% 10% 15%
---------------------------------------
Developed Producing 709.7 571.9 486.7 428.9
Total Proved 1,238.9 951.8 776.0 657.9
Proved + Probable (2P) 2,084.8 1,455.6 1,123.7 920.0
Proved + Probable + Possible (3P) 3,561.4 2,121.9 1,527.6 1,204.0


CBU and Peerless Net Present Value - After Tax ($ millions)
Forecast Prices
As at December 31, 2007
0% 5% 10% 15%
---------------------------------------
Developed Producing 681.9 549.6 467.8 412.2
Total Proved 1,067.9 825.7 675.6 573.6
Proved + Probable (2P) 1,681.9 1,185.8 920.0 754.6
Proved + Probable + Possible (3P) 2,755.1 1,666.1 1,207.8 954.4


Reserve Reconciliation - Forecast Prices (mboe)

Proved +
Total Proved + Probable+
Proved Probable Possible
----------------------------------------------------------------------------
CBU reserves at December 31, 2006 6,675 9,148 12,726
2007 production net of royalty income (1,841) (1,841) (1,841)
Net additions 14,599 23,162 36,188
----------------------------------------------------------------------------
CBU reserves at December 31, 2007 19,433 30,469 47,073
Peerless reserves at December 31, 2007 8,873 13,306 18,726
----------------------------------------------------------------------------
Proforma CBU reserves at December 31, 2007 28,306 43,775 65,799

CBU year-over-year increase in reserves (1) 191% 233% 270%
CBU production replacement (1) 793% 1,258% 1,966%
CBU finding and development costs ($/bbl) (1) 33.65 24.28 16.57
Recycle ratio based on Q4 2007
operating netback (1) 1.8 2.4 3.6

(1) Excludes Peerless reserves acquired January 28, 2008.


CBU finding and development costs include changes in future development costs and all 2007 CBU capital expenditures which included approximately $100 million of investments for undeveloped land acquisitions and facilities costs that will support our long-term Bakken growth.

Canadian Business Unit Operational Update

Petrobank's CBU increased proved plus probable plus possible (3P) reserves year-over-year by 270% to 47.1 million boe. Proved plus probable plus possible reserve additions totaled 36.2 million boe replacing 2007 production of 5,476 boepd more than 18 times. Including the Peerless reserves acquired in January 2008 CBU proved plus probable plus possible reserves increased further to 65.8 mmboe and have a combined net present value, discounted at 10 percent, before tax of $1.5 billion. Our independent reserve evaluator, Sproule, have included only 171 future drilling locations in these evaluations, which is less than 30% of our internally estimated inventory of over 624 net locations.

With ongoing Bakken development drilling and the acquisition of Peerless, CBU production averaged 14,750 boepd in February 2008 and is currently over 16,000 boepd including 12,000 boepd of high netback, Bakken production. Recent production over the first quarter has been hampered by the anticipated declines from high initial rate wells and the operational and production difficulties caused by extreme cold weather in southeast Saskatchewan. We currently have seven drilling rigs operating on the Bakken trend, resulting in two to 2.5 new wells per week. We currently have six wells awaiting fracture stimulation.

In February 2008, we acquired an additional 7.5 sections of Bakken acreage at the Crown land sale, further increasing our Bakken land base to 214 sections (137,000 net acres). Of this, 186 net sections remain to be developed and we estimate our drilling inventory at over 660 (624 net) locations based on only four wells per section, and we plan to drill 154 of these locations in 2008, which we expect will make Petrobank the most active operator in the play.

The Bakken formation produces light oil in close proximity to Canada's main oil pipelines. Operating netbacks are high, particularly when considering the current environment of high oil prices, the attractive Saskatchewan royalty regime, and relatively low operating costs. The operating netback for our operated Bakken oil production during the fourth quarter of 2007 was $69.71 per barrel.

Bakken oil is rich in natural gas and associated natural gas liquids, and a facility program is underway to capture this additional revenue stream. Our initial gas conservation and oil facility was completed at Innes in late 2007, and we have plans for at least an additional two satellite facilities in 2008. The first satellite facility, located north of the Innes facility in the Creelman area, is expected to be operational in late May. This facility is designed to remove any associated water production and then transfer all remaining oil and natural gas via pipeline to our Innes facility, which has ample capacity to manage these volumes. The second satellite facility, which is expected to be operational by late August, will be an integrated oil battery and gas plant, designed to manage new volumes being produced further to the east. All of these facilities are designed around a proactive approach to conserve liquids-rich natural gas associated with our high-value Bakken light oil production.

LATIN AMERICAN BUSINESS UNIT (LABU) - PETROMINERALES LTD. (TSX: PMG - OWNED 76.5%)

Petrobank is also pleased to report on our 2007 year-end third party reserve report with respect to our LABU. Total proved plus probable reserves in Colombia have increased by 53%, based on the DeGolyer and MacNaughton ("D&M") evaluation as at December 31, 2007. All reserves stated herein are based on forecast prices and costs and are company interest reserves, and before royalties. D&M's work incorporates an update of their comprehensive geological and petrophysical evaluation of the Corcel, Orito, Neiva and Joropo properties. The evaluation does not include any reserves associated with our remaining 13 exploration blocks.

Summary results of the D&M report are highlighted as follows:

- Total proved reserves increased by 52% to 20.6 million barrels.

- Total proved plus probable reserves increased by 51% to 37.0 million barrels.

- Total proved, probable and possible reserves increased by 53% to 51.9 million barrels.

- Total proved plus probable NPV 10% (before taxes) increased 152% to US$1.3 billion (3P - US$1.8 billion).

- Proved plus probable reserve additions replaced 815% of 2007 production.

- Total proved plus probable finding and development costs, including expenditures incurred on exploration blocks, and changes in future development costs were US$21.74/bbl in 2007.



Reserves - Company Interest
Light and Medium Oil (mbbl)
----------------------------------------------------------------------------
Developed Producing 9,118
Total Proved 20,597
Total Proved + Probable (2P) 36,977
Total Proved + Probable + Possible (3P) 51,930


Reserve Reconciliation Proved +
Total Proved + Probable +
Proved Probable Possible
----------------------------------------------------------------------------
LABU reserves at December 31, 2006 13,563 24,531 33,906
2007 production (1,740) (1,740) (1,740)
Net additions 8,774 14,186 19,764
------------- ----- ------ -------
LABU reserves at December 31, 2007 20,597 36,977 51,930
Year over year increase in reserves 52% 51% 53%
Production replacement 504% 815% 1,136%
LABU finding and development costs
(US$/bbl) 25.62 21.74 18.27
Recycle ratio based on Q4 2007 operating
netback 2.4 2.9 3.4


Net Present Value - Before Tax
(US$ millions)
As at December 31, 2007
---------------------------------------
---------------------------------------
0% 5% 10% 15%
---------------------------------------
Proved Developed Producing 558.8 497.3 447.9 415.5
Total Proved 1,091.7 918.8 787.4 698.5
Proved + Probable (2P) 1,885.1 1,558.7 1,314.9 1,156.4
Proved + Probable + Possible (3P) 2,636.4 2,168.0 1,819.4 1,598.7

Net Present Value - After Tax -
Forecast Prices (US$ millions)
As at December 31, 2007
---------------------------------------
---------------------------------------
0% 5% 10% 15%
---------------------------------------
Developed Producing 470.0 420.1 379.4 352.1
Total Proved 814.1 690.9 596.4 531.1
Proved + Probable (2P) 1,291.8 1,070.8 905.1 794.3
Proved + Probable + Possible (3P) 1,745.3 1,435.0 1,204.2 1,053.2
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A full operational update of our 76.5% owned LABU, Petrominerales Ltd., was published on February 28, 2008 and can be found at www.petrominerales.com.

Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas exploration and production company with operations in western Canada and Colombia. The Company operates high-impact projects through three business units and a technology subsidiary. The CBU is developing a solid production platform from low risk gas opportunities in central Alberta and an extensive inventory of Bakken light oil locations in southeast Saskatchewan, complemented by new exploration projects and a large undeveloped land base. The LABU, operated by Petrobank's 76.5% owned TSX-listed subsidiary, Petrominerales Ltd. (trading symbol: PMG), is a Latin American-based exploration and production company producing oil from three blocks in Colombia and has contracts on 15 exploration blocks covering a total of 1.6 million acres in the Llanos and Putumayo Basins. Whitesands Insitu Partnership, a partnership between Petrobank and its wholly-owned subsidiary Whitesands Insitu Inc., owns oil sands leases containing up to 805 million barrels of proved, probable, possible and contingent recoverable resources, based on conventional (SAGD) technology, and operates the Whitesands project which is field-demonstrating Petrobank's patented THAI™ heavy oil recovery process. THAI™ 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™ and CAPRI™ 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 results of 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.

Barrels of Oil Equivalent ("boe")

Disclosure provided herein in respect of 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.

Contact Information

  • Petrobank Energy and Resources Ltd.
    John D. Wright
    President and Chief Executive Officer
    (403) 750-4400
    or
    Petrobank Energy and Resources Ltd.
    Chris J. Bloomer
    Vice-President Heavy Oil
    (403) 750-4400
    or
    Petrobank Energy and Resources Ltd.
    Corey C. Ruttan
    Vice-President Finance and Chief Financial Officer
    (403) 750-4400
    (403) 266-5794 (FAX)
    Email: ir@petrobank.com
    Website: www.petrobank.com