Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd.

March 05, 2009 03:41 ET

Petrobank Announces Year End Reserves & Production

CALGARY, ALBERTA--(Marketwire - March 5, 2009) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is pleased to announce strong reserves growth and production increases.

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


- Production increased by 181% to 28,742 barrels of oil equivalent per day ("boepd") in 2008 from 10,243 boepd in 2007. Canadian Business Unit ("CBU") production increased by 225% to 17,775 boepd (86% oil and NGLs) and production from the Latin American Business Unit ("LABU") increased by 130% to 10,967 barrels of oil per day ("bopd") in 2008.

- Fourth quarter average daily production increased by 111% in 2008 to 37,618 boepd from 17,829 boepd in the fourth quarter of 2007. CBU production increased by 170% to 22,274 boepd (89% oil and NGLs) and production from the LABU increased by 60% to 15,344 bopd.

- Average daily production increased further to 47,897 boepd in February 2009 comprised of 22,000 boepd from the CBU and 25,897 bopd from the LABU.

- CBU proved plus probable ("2P") reserves increased by 95% to 59.5 million boe at December 31, 2008 and we replaced 2008 production more than 5.5 times.

- CBU proved plus probable plus possible ("3P") reserves increased by 83% to 86.2 million boe with net present value, before tax, discounted at 10% of $2.0 billion.

- CBU "all-in" 2P finding, development and acquisition costs of $28.41 per boe representing a 2.4 times recycle ratio using unaudited 2008 CBU operating netbacks.

- Unaudited CBU operating netbacks averaged $67.99 per boe in 2008 and despite a steep decline in commodity prices in the period, fourth quarter operating netbacks remained strong at $39.04 per boe.

- Heavy Oil Business Unit ("HBU") 2P reserves increased by 171% to 69.0 million barrels with net present value, before tax, discounted at 8% of $392.8 million.

- HBU 3P reserves plus high estimate contingent recoverable bitumen resources totalled 814.7 million with net present value, before tax, discounted at 8% of $3.6 billion.

- LABU 2P reserves were flat year over year at 36.8 million barrels with net present value, before tax, discounted at 10% of US$1.2 billion.

- LABU 3P reserves increased by 6% to 55.0 million barrels with net present value, before tax, discounted at 10% of US$1.8 billion.

- Petrobank's total company 2P reserves increased by 61% to 156.7 million boe with net present value of $3.0 billion up from $2.1 billion in 2007.

- Petrobank's total company 3P reserves increased by 12% to 205.9 million boe with net present value of $4.2 billion up from $3.2 billion in 2007.


Working Interest, Forecast Prices

CBU LABU HBU Total Company (1)
(mboe) (mbbls) (mbbls) (mboe)
------ ------- ------- ------
Developed Producing 26,501 14,229 - 37,386
Total Proved 40,465 25,174 - 59,723
Proved + Probable (2P) 59,536 36,849 68,982 156,707
Proved + Probable + Possible
(3P) 86,186 54,965 77,670 205,904
High Estimate Contingent
Resources - - 737,062 737,062
3P + High Estimate Contingent
Resources 86,186 54,965 814,732 942,966

(1) Total Company includes only Petrobank's 76.5% share of the LABU's
reserves at December 31, 2008.

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

CBU LABU HBU Total Company (2)
($) (US$) ($) ($)
--- ----- --- ---
Developed Producing 874.8 487.2 - 1,331.2
Total Proved 1,068.4 831.9 - 1,847.7
Proved + Probable (2P) 1,489.9 1,229.4 392.8 3,034.4
Proved + Probable +
Possible (3P) 2,001.0 1,808.6 522.6 4,217.9
High Estimate Contingent
Resources - - 3,102.6 3,102.6
3P + High Estimate
Contingent Resources 2,001.0 1,808.6 3,625.2 7,320.5

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

CBU LABU HBU Total Company (2)
($) (US$) ($) ($)
--- ----- --- ---
Developed Producing 821.5 421.2 - 1,216.1
Total Proved 938.6 676.5 - 1,572.4
Proved + Probable (2P) 1,238.3 933.3 274.2 2,386.8
Proved + Probable +
Possible (3P) 1,605.7 1,320.6 374.4 3,217.3
High Estimate Contingent
Resources - - 2,175.1 2,175.1
3P + High Estimate
Contingent Resources 1,605.7 1,320.6 2,549.5 5,392.4

(1) Net present values are discounted at 10% for the CBU and LABU, and at
8% for the HBU.
(2) Total Company includes only Petrobank's 76.5% share of the LABU's
reserves at December 31, 2008 converted using a US$/$ exchange rate
of 1.2246.

Price Forecasts

Natural WTI Crude WTI Crude WTI Crude Hardisty
Gas(1) Oil(1) Oil(1) Oil(1) DilBit(1)
Year ($/mcf) (US$/bbl) (US$/bbl) (US$/bbl) ($/bbl)
2009 6.82 53.73 57.00 60.00 53.65
2010 7.56 63.41 69.53 71.40 63.84
2011 7.84 69.53 76.38 83.20 70.26
2012 8.38 79.59 86.99 90.20 72.16
2013 9.20 92.01 94.74 97.40 74.02
inflation %
change 2% 2% 2.5% 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.

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 later in March.



Our CBU reserve engineers, Sproule Associates Limited ("Sproule"), have completed their evaluation of our conventional Canadian reserves as at December 31, 2008. All reserves are based on forecast prices and costs and are Company gross reserves. Summary results of the Sproule reports are highlighted as follows:

- Total proved reserves increased 108% to 40.5 million boe.

- Proved plus probable reserves increased 95% to 59.5 million boe.

- Proved, probable and possible reserves increased 83% to 86.2 million boe.

- NPV 10% (before taxes) of $1.5 billion (2P), $2.0 billion (3P) increases of 91% and 85%, respectively despite a significant drop in commodity prices.

- Proved plus probable reserve additions replaced 2008 production more than 5.5 times.

CBU Working Interest Reserves(1)
Forecast Prices(2)
Light and
Medium Oil NGL Natural Gas Total
(mbbl) (mbbl) (mmcf) (mboe)
Developed Producing 20,191 1,694 27,696 26,501
Total Proved 29,948 2,532 47,910 40,465
Proved + Probable (2P) 44,529 3,667 68,037 59,536
Proved + Probable + Possible (3P) 65,517 5,227 92,654 86,186

(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, 2008.

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 2008 included 401 boepd of royalty income production.

CBU Net Present Value - Before Tax ($ millions)
Forecast Prices
As at December 31, 2008

0% 5% 10% 15%
Developed Producing 1,395.5 1,069.2 874.8 747.4
Total Proved 1,840.3 1,356.4 1,068.4 880.4
Proved + Probable (2P) 3,008.5 2,005.7 1,489.9 1,181.8
Proved + Probable + Possible (3P) 5,058.4 2,890.7 2,001.0 1,526.9

CBU Net Present Value - After Tax ($ millions)
Forecast Prices
As at December 31, 2008

0% 5% 10% 15%
Developed Producing 1,265.3 988.8 821.5 710.1
Total Proved 1,573.5 1,177.1 938.6 781.2
Proved + Probable (2P) 2,420.4 1,643.7 1,238.3 992.8
Proved + Probable + Possible (3P) 3,904.0 2,282.9 1,605.7 1,239.4

Reserve Reconciliation - Forecast Prices (mboe)

Proved +
Developed Total Proved+ Probable+
Producing Proved Probable Possible
CBU reserves at
December 31, 2007 8,239 19,433 30,469 47,073
2008 production net
of royalty income (6,359) (6,359) (6,359) (6,359)
Acquisitions 5,967 9,321 14,248 19,668
Net additions
acquisitions 18,654 18,070 21,178 25,804
------------- ------ ------ ------ ------
CBU reserves at
December 31, 2008 26,501 40,465 59,536 86,186

CBU year-over-year
increase in reserves 222% 108% 95% 83%
CBU production
replacement 387% 431% 557% 715%

CBU Finding, Development and Acquisition ("FD&A") Costs(1)

Finding &
Development Acquisitions(2) FD&A
(unaudited -
expenditures 545,833 - 545,833
capital(4) - 391,502 391,502
------------------- ------- ------- --------
Total capital 545,833 391,502 937,335
Less: land 132,653 83,032 215,685
---------- ------- ------- --------
Adjusted capital
excluding land 413,180 308,470 721,650
Change in future
development costs
Total Proved 6,621 52,598 59,219
Proved + Probable
(2P) (6,623) 75,619 68,996
Proved + Probable +
Possible (3P) (30,513) 90,919 60,406
Total costs ($000s)
Total Proved 552,454 444,100 996,554
Proved + Probable
(2P) 539,210 467,121 1,006,331
Proved + Probable +
Possible (3P) 515,320 482,421 997,741
Total costs
excluding land
Total Proved 419,801 361,068 780,869
Proved + Probable
(2P) 406,557 384,089 790,646
Proved + Probable +
Possible (3P) 382,667 399,389 782,056
Net reserve
revisions (mboe)
Total Proved 18,070 9,321 27,391
Proved + Probable
(2P) 21,178 14,248 35,426
Proved + Probable +
Possible (3P) 25,804 19,668 45,472
FD&A costs ($/boe)
Total Proved 30.57 47.65 36.38
Proved + Probable
(2P) 25.46 32.79 28.41
Proved + Probable +
Possible (3P) 19.97 24.53 21.94
FD&A costs excluding
land ($/boe)
Total Proved 23.23 38.74 28.51
Proved + Probable
(2P) 19.20 26.96 22.32
Proved + Probable +
Possible (3P) 14.83 20.31 17.20

(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
(2) Includes the acquisition of Peerless Energy Inc. ("Peerless") and
Rocor Resources Inc. ("Rocor")
(3) The Company's annual audit of its consolidated financial statements is
not yet complete and accordingly all financial amounts are management's
best estimates which are unaudited and subject to change.
(4) Calculated from the total purchase price plus net debt or working
capital assumed.

Canadian Business Unit Operational Update

Petrobank's CBU achieved record results in 2008 with significant increases in high netback reserves and production. CBU production increased 225% to 17,775 boepd in 2008 from 5,476 boepd in 2007 and proved plus probable reserves increased by 95% year-over-year to 59.5 million boe.

We believe 3P reserve estimates more accurately reflect the true potential of our assets as our reserves are derived largely from low risk, expansive resource accumulations. CBU 3P reserves increased by 83% year-over-year to 86.2 million boe and reserve additions of 45.5 million boe replaced our 2008 working interest production more than 7 times. These 3P reserves have a net present value, discounted at 10 percent, before tax of $2.0 billion, an 85% increase from 2007 despite steep declines in commodity prices. Our production and reserves are heavily weighted (over 85%) to high value Bakken light oil and associated gas and liquids. This allows Petrobank to achieve industry-leading netbacks and demonstrates our high quality asset base. Of our year-end inventory of over 530 undrilled Bakken locations, only 162 have been assigned 2P reserves with an additional 19 assigned possible reserves.

The finding, development and acquisition (FD&A) costs associated with our operations represent investment for our growth in 2008 and an expansion of our inventory of opportunities for the future. "All-in" 2008 CBU 2P and 3P FD&A costs including changes in future development costs, were $28.41 and $21.94/boe, respectively. These costs reflect all investments, including acquisitions, extensive growth in Bakken infrastructure and acquisitions of new large land positions. Petrobank spent $225.3 million on building significant positions in established and emerging resource plays, primarily in the Montney, Horn River and Bakken plays of Saskatchewan and British Columbia. If we remove the capital associated with these acquisitions, our 2P and 3P FD&A costs drop to $22.32 and $17.20/boe, respectively.

Bakken Activity

Petrobank was the most active operator in the Bakken during 2008 and we are now the largest Bakken producer. We drilled 161 net wells in 2008, surpassing our internal target of 154 wells, with a 99.4% success rate. We operated an average of eight rigs through the year, and at times had up to 10 rigs running to execute our development drilling program, which resulted in approximately three new wells being added per week. Our operational expertise was also refined through 2008, compressing the time from spud to on-stream for our wells, inclusive of the multi-stage fracture stimulation, to 35 days. The Peerless acquisition, in January of 2008, also contributed to our strong production base and inventory of drillable locations. We have now developed an innovative way to re-enter old producing Peerless trilateral wells and perform multistage fracs in the two outside horizontal legs, with results exceeding our initial expectations. These types of innovations will continue to drive value growth from the Bakken.

Petrobank pioneered the horizontal fracture stimulation techniques that opened up the true potential of this substantial resource, and we continue to find new ways to improve well performance and expected ultimate recoveries from the Bakken. Our recent efforts to further improve Bakken production have focused on increasing the intensity of fracture stimulation completions (fracs) by:

1. Increasing the number of staged fracs from 8 to 11 in our 1,400 metre long horizontal wells, representing a 38% increase in frac intensity within a section of land,

2. Doubling the number of wells per section with shorter 600 to 700 metre long horizontals and with 8 staged fracs in each horizontal, representing a 200% increase in frac intensity within a section of land, and

3. Doubling the number of locations per section with each well having two 600 to 700 metre horizontal legs from the single vertical well bore and each leg receiving 8 staged fracs, representing a 400% increase in frac intensity within a section of land.

We continue to build on our innovative approach to maximizing value from the Bakken resource and are monitoring production performance from these operations to optimize drilling and fracture stimulation design.

Driven by strong Bakken results, the CBU increased production by 225% to 17,775 boepd in 2008, and average fourth quarter 2008 production increased by 170% to 22,274 boepd. As commodity prices continued to decline in late 2008, Petrobank started to reduce drilling activity and we are now operating two drilling rigs. Based on field estimates, CBU production averaged 22,000 boepd in February 2009.

In 2009, our primary focus will be to maintain our low-cost advantage through selective drilling in the Bakken. We are positioned for strong reserve and production growth, although we have slowed the pace of development. At current commodity prices we expect to drill 40 wells and if oil prices improve we could drill as many as 120 wells in 2009. Our activity levels will be linked to commodity prices as we manage capital expenditures to maintain a strong balance sheet and financial flexibility in a challenging commodity price and capital market environment.

Part of our strategy in the Bakken is to operate centralized facilities to capture additional value from the gas and natural gas liquids associated with the light oil, and to ensure field efficiencies that maintain low operating costs. To strengthen our infrastructure, three new facilities at Viewfield, Creelman, and Freestone were connected to our main Midale plant through 100 kilometres of new pipelines. Together our facilities are now conserving more than 6.5 mmcf/d of natural gas plus associated natural gas liquids and allow us to maintain low operating costs while improving our overall project economics. Our future plans include two more pipeline-connected facilities that are scheduled to be built as drilling activity extends to the north. At our current drilling pace, construction is expected to commence in 2010.

Through 2008, we continued to strengthen our Bakken land base and expand our inventory of drilling locations. Through acquisition, Crown land sales, and direct arrangements with mineral rights owners including the Ocean Man First Nation, we have expanded our Bakken land base to 270 (236 net) sections. These investments provide the foundation for our ability to continue to add value from the Bakken for many years to come.

Beyond Bakken

Petrobank has also established strong positions in two massive natural gas resource plays; the Montney and the Horn River Basin. The key to unlocking the potential of these plays is through the use of horizontal wells and multi-stage fracture stimulation technologies, similar to those pioneered by Petrobank in the Bakken. We intend to capitalize on our evolving experience with advanced fracturing techniques, with the goal of building a substantial, long-term inventory of drilling locations at a low near-term cost.

In October 2008, through the acquisition of a private company, we acquired a highly prospective position in the Montney tight gas play at Monias in northeastern B.C. We have a 100% working interest in 14 contiguous sections of land, and a 5.0 mmcf/d gas plant.

In December 2008, we drilled our first Montney horizontal well, and in February 2009 we performed seven multi-stage fracture stimulations in the upper portion of the 135 meter thick Montney interval. The well flow tested at initial rates in excess of 7.5 mmcf/d plus 180 barrels of natural gas liquids per day. The well will be put on production before the end of the first quarter at a restricted rate of 5.0 mmcf/d, filling the capability of our existing gas plant. The consistent geology across our 14 sections of land establishes a 55-well inventory of prolific Montney drilling locations. Our next steps will be to install additional compression to increase our plant capacity to 10.0 mmcf/d and then drill another well later in 2009. Our independent reserve evaluators have only assigned reserves to our initial well.

A second resource play where we can apply our innovative completion experience is in the Horn River Shale Basin, north of the Montney play in northeast B.C. As this emerging play has developed, we began to build an acreage position, which now encompasses 65 sections (43,428 acres) of 100% working interest lands and 14 sections of 15.5% working interest lands. Our first horizontal evaluation well initiated drilling in late February in an area with all-season access close to the Alaska Highway. The majority of the basin is characterized by a short three-month operating season (January to March) due to the presence of thick muskeg. All-season access at this first location will allow us to complete the multi-stage fracture stimulation during the second quarter of 2009. Our immediate focus will be on drilling test wells and developing a multi-year inventory of drilling locations in the Muskwa and Evie shales. No reserves have been assigned to our Horn River asset base as at December 31, 2008.


Late in 2007, we drilled an exploration well in the Cornwall area which tested gas at 6.5 mmcf/day with 200 barrels per day of condensate. We will be completing a short pipeline tie-in with compression installation and we expect to have this well on production in early April at pipeline-restricted rates of 2.5 mmcf/day.


The following tables summarize the McDaniel & Associates Consultants Ltd. ("McDaniel") Whitesands reserves report as at December 31, 2008. 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 (3 sections).

The McDaniel's 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™ 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 on resource recovery and estimates of reserve volumes.

Reserves and Resources (1) as of December 31, 2008 2007 Change
(mbbl) (mbbl) %
------- ------ -
Probable Reserves (2P) 68,982 25,476 171
Probable plus Possible Reserves (3P) 77,670 78,904 (2)
Low Estimate Contingent Resources (2) (3) 485,162 482,108 1
Best Estimate Contingent Resources (2) (3) 599,215 635,422 (6)
High Estimate Contingent Resources (2) (3) 737,062 725,872 2

2P + Best Estimate Contingent Resources 668,197 660,898 1
3P + High Estimate Contingent Resources 814,732 804,776 1

(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, 2008 - $ Millions
Net Present Value Discounted
at: 0% 5% 8% 10%
----------------------------- -- -- -- ---

Probable Reserves (2P) 1,239.5 601.3 392.8 294.3
Probable plus Possible
Reserves (3P) 1,648.4 788.2 522.6 400.4
Low Estimate Contingent
Resources 8,341.1 2,928.0 1,482.8 879.3
Best Estimate Contingent
Resources 12,590.5 4,402.8 2,387.8 1,573.6
High Estimate Contingent
Resources 18,341.3 5,806.3 3,102.6 2,070.1

2P + Best Estimate Contingent
Resources 13,830.0 5,004.1 2,780.6 1,867.9
3P + High Estimate Contingent
Resources 19,989.7 6,594.5 3,625.2 2,470.5

(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, 2008 - $ Millions
Net Present Value Discounted
at: 0% 5% 8% 10%
----------------------------- -- -- -- ---

Probable Reserves (2P) 924.3 434.3 274.2 198.6
Probable plus Possible
Reserves (3P) 1,231.3 576.4 374.4 281.5
Low Estimate Contingent
Resources 6,211.9 2,031.9 921.9 461.0
Best Estimate Contingent
Resources 9,384.2 3,153.3 1,627.4 1,013.5
High Estimate Contingent
Resources 13,684.6 4,209.5 2,175.1 1,400.9

2P + Best Estimate Contingent
Resources 10,308.5 3,587.6 1,901.6 1,212.1
3P + High Estimate Contingent
Resources 14,915.9 4,785.9 2,549.5 1,682.4

(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.

Heavy Oil Business Unit Operational Update

- Increased 2P reserves by 171% to 69.0 million barrels.

- Entered into our second THAI™/CAPRI™ licence and joint venture agreement for the application of our technology in a conventional heavy oil reservoir in Saskatchewan.

- Received approval for Whitesands expansion in December 2008.

- Completed a 6-well delineation drilling program over the May River Project area confirming a high quality reservoir for the project.

- May River application deemed complete and regulatory review is underway.

Whitesands Project

During the fourth quarter and into early 2009, P3B operations were impacted by maintenance and workover operations. These included the replacement of the thermocouple string in mid-October, the replacement of the A-3 air injection well's packer assembly, and the tie-in of the new wellhead separation system. Severe cold weather at the end of the year and into early 2009 delayed the timely completion of these projects. Due to these events P3B was taken off-line and successfully re-started three separate times.

Since commencing production on P3B, the well has exhibited negligible sand production proving the effectiveness of the new liner design. The well is currently producing 800 barrels of fluid per day on restricted flow at oil cuts between 40 and 50% with minor sediments typically associated with heavy oil production. The well is currently being restricted to balance overall gas and liquids production into the plant. The well bore is now operating at 250 degrees Celsius, and we are targeting a well bore temperature of at least 300 degrees Celsius to assess CAPRI™ catalyst efficiency. Until we are operating above the target temperature we do not expect a significant contribution to upgrading from the catalyst. The current degree of oil upgrading and the produced gas analysis from P3B are consistent with the P1 and P2 wells, indicating high temperature combustion. Produced oil quality is consistently averaging approximately 12 degrees API, compared to the native eight degree API bitumen in-situ. We continue to recover a light oil condensate stream in the secondary separators that is being carried in the vapour phase by the overhead gas system and condensed out in the secondary separators. This lighter oil can be over 30 degrees API and recent analysis indicates that this stream could be up to 10 percent of the total produced hydrocarbons. This lighter oil component further demonstrates significant in-situ thermal cracking and the potential for co-production of other high-value by-products.

In P1 and P2 we have started to see a reduction in produced sand through the de-sand vessels, which has resulted in improved on-stream factors and the wells have had periods of high productivity, up to 400 bopd. Despite these minor operational improvements, these wells still pose major operational challenges and as a result we plan to either re-complete them with narrower slotted liners or drill at least one replacement well. Regulatory approval for our expansion at Whitesands was received late in the fourth quarter and in anticipation of this approval we positioned ourselves to immediately execute the project. However, we have decided that there is little benefit to be gained from significantly expanding the Whitesands site. We have decided to cost-effectively convert Whitesands into a modified 3 to 4 well THAI™ and THAI™/CAPRI™ demonstration site.

Kerrobert Project

Late in the fourth quarter we entered into royalty, technology license and a joint venture agreements with True Energy Trust to apply Petrobank's patented THAI™ heavy oil recovery technology on portions of their Kerrobert heavy oil property in west central Saskatchewan.

Under the agreement, Petrobank will initially earn a 50% working interest in three sections of land in the Kerrobert Mannville heavy oil pool. Subject to regulatory approval, Petrobank and True will develop a two-well project to demonstrate the THAI™ technology in this 20+ metre thick conventional heavy oil reservoir. Petrobank will earn an additional ten percent gross overriding royalty on True's share of all THAI™ production following a threshold reserve recovery.

Petrobank will also earn a 50% working interest in ten additional sections of True lands upon the expansion of the initial THAI™ project or development of another project on these lands. In addition, Petrobank and True have established an area of mutual interest over 30 additional sections of land to jointly develop additional THAI™ projects.

This joint venture brings the THAI™ technology to the conventional heavy oil resource base in Saskatchewan. We estimate that Saskatchewan has approximately 20 billion of barrels of unrecovered conventional heavy oil resource that can be commercialized using our THAI™ technology. We expect to file our Kerrobert application early in the second quarter of 2009 and anticipate approval within one month of filing. Saskatchewan is actively encouraging oil and gas development and the application of advanced technologies.

May River Project

The May River Project is the commercial development of Petrobank's leases (including the Whitesands project) west of Conklin, Alberta utilizing THAI™. The May River design builds on the experience gained from the Whitesands pilot plant and is intended to be built in phases, with initial production capacity of 10,000 barrels of THAI™ oil per day, and an ultimate capacity of 100,000 barrels per day.

The regulatory application for May River's first phase was filed with the Energy Resources Conservation Board and Alberta Environment at the end of 2008. The application has been deemed complete and is now moving through the regulatory process.

The front end engineering and design for the project began in the fourth quarter of 2008, and we expect to have completed this phase of engineering by mid-year. 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 the May River project a leading environmentally sustainable process for oil sands and heavy oil development. The Project is utilizing a modular approach that is designed to be installed and operated on heavy oil projects world-wide.

Dawson Project

The Dawson Project is a joint venture involving our first Alberta-based, third party THAI™ license. Our joint venture partner is now Shell Canada Limited who acquired Duvernay Oil Corp. in August 2008. The project is located near Peace River Alberta and will be developed in the Bluesky formation. The upper portions of this formation contain 11 degree API heavy oil, comparable to other conventional heavy oil reservoirs throughout western Canada. The project scope consists of two well pairs and our simplified facility design. In August 2008, a stratigraphic well was drilled on the project site that will be used as a thermal observation well during the project's operating phase. The regulatory application for the project is complete, and, following review with our new partner, is expected to be filed by the end of March.

Sutton Creek, Saskatchewan

We have acquired 35 kilometres of 2D seismic on our 23,040 acre oil sands lease in northwest Saskatchewan. We are currently processing the data in order to identify potential exploration drilling targets.

Business Development

Our wholly-owned subsidiary, Archon Technologies Ltd., continues to evaluate a number of innovative engineering, environmental, and other value-added technology options to improve operational efficiency and reliability, and to reduce the overall environmental impact of heavy oil recovery. Other technologies being assessed include enriched oxygen injection, power generation using produced lean gas, enhanced produced water quality, and incremental surface upgrading.

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™ in a wide range of large global resource opportunities. The current economic environment has influenced our negotiations and we continue, to make progress and expect to successfully conclude an additional joint venture in the near term.


Petrobank is also pleased to report on our 2008 year-end third party reserve report with respect to our LABU. Total proved reserves in Colombia have increased by 22%, based on the DeGolyer and MacNaughton ("D&M") evaluation as at December 31, 2008. All reserves stated herein are based on forecast prices and costs and are company interest reserves after Ecopetrol's (the State oil company) share, 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 recent exploration successes on the Mapache Block, our Corcel D-3 well, or our remaining 13 exploration blocks. A full operational update of our 76.5% owned LABU, Petrominerales Ltd., was published on March 1, 2009 and can be found at

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

- Total proved reserves increased by 22% to 25.2 million barrels.

- Total proved plus probable reserves remained constant at 36.8 million barrels.

- Total proved, probable and possible reserves increased by 6% to 55.0 million barrels.

- Proved reserve additions replaced 214% of 2008 production.

- Total proved plus probable forecasted production for 2009 is 23,148 bopd.

- Proved, and total proved plus probable F&D costs of US$24.95/bbl and US$30.66/bbl in 2008, respectively, which includes changes in future development costs and expenditures incurred on our 13 exploration blocks that were not evaluated by our reserve evaluators.

LABU Gross Reserves Reconciliation (mbbls)
Proved Proved +
Developed Total Proved + Probable +
Producing Proved Probable Possible
December 31, 2007 reserves 9,118 20,597 36,977 51,930
2008 production (4,014) (4,014) (4,014) (4,014)
Net additions 9,125 8,591 3,859 7,022
------------- ----- ----- ----- -----
December 31, 2008 reserves 14,229 25,174 36,849 54,965
Year over year increase in
reserves 56% 22% 0% 6%
Production replacement 227% 214% 96% 175%

Net Present Value - Before Tax - Forecast Prices (US$ millions)
0% 5% 10% 15%
Proved Developed Producing 606.9 540.9 487.2 454.1
Total Proved 1,201.3 989.1 831.9 726.9
Proved + Probable 1,812.5 1,476.6 1,229.4 1,063.8
Proved + Probable + Possible 2,738.7 2,199.9 1,808.6 1,554.6

Net Present Value - After Tax - Forecast Prices (US$ millions)
0% 5% 10% 15%
Proved Developed Producing 529.1 469.6 421.2 390.8
Total Proved 960.3 798.3 676.5 593.1
Proved + Probable 1,357.4 1,114.2 933.3 809.2
Proved + Probable + Possible 1,979.1 1,598.9 1,320.6 1,136.3

Conference Call

Petrobank management will hold a conference call on Thursday, March 5, 2009 at 9:00am (Mountain Time) to discuss Petrobank's reserves results for the year ending December 31, 2008.

John D. Wright, President and Chief Executive Officer of Petrobank, along with Chris J. Bloomer, Senior Vice President and Chief Operating Officer, Heavy Oil, Corey C. Ruttan, Senior Vice President and Chief Financial Officer, Gregg Smith, Senior Vice President and Chief Operating Officer, Canada and Jack Scott, Executive Vice President and Colombian Country Manager, will chair the investor conference call. The investor conference call details are as follows:

Date: Thursday, March 5, 2009
Time: 9:00am (Mountain Time)
Number: 1-800-769-8320
Re-play: 1-416-695-5800 or 1-800-408-3053
Number: 8832083
until: March 12, 2009

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 Canadian Business Unit is focused on developing a solid production platform from the Bakken light oil play in southeast Saskatchewan, and exploiting a large undeveloped land base through the application of new technology to large oil and gas resource opportunities. The Latin American Business Unit, operated by Petrobank's 76.5% owned TSX-listed subsidiary, Petrominerales Ltd. (TSX:PMG), is a Latin American-based exploration and production company producing oil in Colombia with 16 exploration blocks covering a total of 1.9 million acres in the Llanos and Putumayo Basins of Colombia and 2.6 million 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™ 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.

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" as described below. The following are excerpts from the definitions of resources and reserves, 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 subclassified 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.

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
    Petrobank Energy and Resources Ltd.
    Chris J. Bloomer
    Senior Vice President and Chief Operating Officer, Heavy Oil
    (403) 750-4400
    Petrobank Energy and Resources Ltd.
    Corey C. Ruttan
    Vice President Finance and Chief Financial Officer
    (403) 750-4400
    Petrobank Energy and Resources Ltd.
    R. Gregg Smith
    Senior Vice President and Chief Operating Officer, Canada
    (403) 750-4400
    Petrobank Energy and Resources Ltd.
    Suite 2600, 240 - 4th Avenue S.W.
    Calgary, Alberta T2P 4H4