Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd.

March 13, 2007 01:55 ET

Petrobank Announces Year End Results, Reserves and Board Changes

CALGARY, ALBERTA--(CCNMatthews - March 13, 2007) - Petrobank Energy and Resources Ltd. ("Petrobank") (TSX:PBG)(OSLO:PBG) is pleased to announce year-end financial and operating results, along with the results of our year-end reserve evaluations.


We entered 2006 with an excellent portfolio of opportunities and a solid base of production and reserves. Some of the highlights of 2006 include the following:

- Funds flow from operations more than doubled to $61.4 million from $29.2 million in 2005.

- Net income increased 80% to $23.1 million from $12.8 million in 2005.

- Consolidated conventional production increased 53% from 3,451 boepd in 2005 to 5,269 boepd in 2006.

- Conventional production from the Canadian Business Unit increased 27% to 3,075 boepd from 2,420 boepd in 2005 and increased further to 4,192 boepd in the first two months of 2007.

- Latin American Business Unit production more than doubled to 2,194 bopd.

- The Heavy Oil Business Unit completed construction and initiated combustion and production from the world's first THAI™ project at WHITESANDS.

- Oil sands acreage under lease expanded to 62 sections.

- Heavy Oil Business Unit's 3P reserves plus best estimate contingent recoverable bitumen resources increased by 48% from the first evaluation dated May 1, 2006, to 644.4 million barrels (as at March 1, 2007).

- Conventional Canadian 3P reserves totaled 12.7 million boe at December 31, 2006.

- Latin American Business Unit 3P reserves totaled 33.9 million barrels at December 31, 2006.

- Petrominerales Ltd. (TSX:PMG), our Latin America Business Unit completed its initial public offering in June 2006. Petrobank retains an 80.7% ownership stake.

- Petrominerales amassed a 1.5 million acre exploration land base in Colombia's highly prospective Llanos and Putumayo Basins.

- In early 2006, Petrobank listed on Norway's Oslo stock exchange in connection with a $33 million offering.


The following table provides a summary of Petrobank's financial and operating results for the three and twelve month periods ended December 31, 2006 and 2005. Consolidated financial statements with Management's Discussion and Analysis (MD&A) are available on our website at under the "Investor Relations - Financial Reports" section.

Financial Three months ended Years ended
($000s, except where December 31, % December 31, %
noted) 2006 2005 change 2006 2005 change
Oil and natural gas
revenue 25,729 22,510 14 99,228 65,081 52
Funds flow from
operations(1) 16,057 12,304 31 61,425 29,152 111
Per share - basic ($) 0.24 0.20 20 0.92 0.50 84
Per share - diluted ($) 0.23 0.19 21 0.89 0.49 82
Net income 2,400 5,184 (54) 23,106 12,808 80
Per share - basic ($) 0.04 0.08 (50) 0.35 0.22 59
Per share - diluted ($) 0.03 0.08 (63) 0.33 0.21 57
Capital expenditures 71,337 58,436 22 229,693 118,152 94
Net debt(2) 40,545 60,808 (33) 40,545 60,808 (33)
Common shares outstanding,
end of year (000s)
Basic 72,125 63,220 14 72,125 63,220 14
Diluted 76,538 68,451 12 76,538 68,451 12

Canadian operating netback
($/boe except where noted)
Oil and NGL revenue
($/bbl)(4) 54.83 62.35 (12) 61.18 60.96 -
Natural gas revenue
($/mcf)(4) 6.15 10.36 (41) 6.21 8.09 (23)
Oil and natural gas
revenue(4) 43.86 62.21 (29) 44.40 50.84 (13)
Royalties 4.47 13.00 (66) 6.28 10.46 (40)
Production expenses 8.06 5.07 59 6.89 6.05 14
Transportation expenses 0.27 0.53 (49) 0.39 0.98 (60)
Operating netback 31.06 43.61 (29) 30.84 33.35 (8)

Colombian operating
netback ($/bbl)
Oil revenue 57.68 52.50 10 61.68 53.62 15
Royalties 4.61 4.20 10 4.95 4.29 15
Production expenses 8.39 10.08 (17) 7.78 9.49 (18)
Operating netback 44.68 38.22 17 48.95 39.84 23
Average daily
Canada - oil and NGL (bbls) 1,265 662 91 918 452 103
Canada - natural gas (mcf) 11,968 14,792 (19) 12,940 11,810 10
Total Canada (boe) 3,260 3,127 4 3,075 2,420 27
Colombia - oil (bbls) 2,372 955 148 2,194 1,031 113
Total Company (boe) 5,632 4,082 38 5,269 3,451 53
Reserves/Resources by
Business Unit(5)
Heavy Oil (mbbls) - 84% 541,282 - - 541,282 - -
Canadian (mboe) 12,726 16,188 (21) 12,726 16,188 (21)
Latin American -
Colombia (mbbls) - 80.73% 27,372 22,263 23 27,372 22,263 23
Total Company (mboe) 581,380 38,451 1,412 581,380 38,451 1,412

(1) Calculated based on cash flow from operations before changes in other
non-cash working capital and asset retirement obligations settled.
(2) Includes working capital (deficiency), bank debt and subordinated
(3) Six mcf of natural gas is equivalent to one barrel of oil equivalent
("boe"). Bitumen volumes are excluded from average daily production as
WHITESANDS operations are considered to be in the development stage and
accordingly are capitalized.
(4) Canadian sales prices are shown after transportation and forward gas
sales contracts.
(5) Company working interest proved plus probable plus possible reserves
and contingent recoverable resources (best estimate) excluding royalty
interest reserves and before deduction of royalties payable. The Heavy
Oil Business Unit represents information effective as of March 1, 2007.
Only represents Petrobank's 84% share of the Heavy Oil Business Unit's
(WHITESANDS Insitu Ltd.) reserves and Petrobank's share (80.73% at
December 31, 2006 and 100% at December 31, 2005) of the Latin American
Business Unit's (Petrominerales Ltd.) reserves.


Working Interest Reserves, Forecast Prices
Canada Latin America Heavy Oil Total Company
(mboe) (mbbls) (mbbls) (mboe)(1)
------- -------------- --------- --------------
Developed Producing 3,050 3,947 - 6,236
Total Proved 6,675 13,563 - 10,949
Proved + Probable 9,148 24,531 25,290 50,195
Proved + Probable
+ Possible 12,726 33,906 70,323 99,170
Best Estimate
Resources(3)(4) 12,726 33,906 574,060 522,309
3P + Best Estimate
Contingent Resources 12,726 33,906 644,383 581,380

(1) Total Company includes Canadian Business Unit reserves at December 31,
2006, Petrobank's 80.73% share of the Latin American Business Unit's
reserves as December 31, 2006, and the Company's 84% share of
WHITESANDS Insitu Ltd. reserves as at March 1, 2007 representing the
Heavy Oil Business Unit.

The full reserve disclosure tables, as required under National Instrument 51-101, will be contained in Petrobank's 2006 Annual Information Form, which will be filed on SEDAR on or before March 31, 2007.


The following tables summarize the McDaniel & Associates Consultants Ltd. WHITESANDS reserve reports as at December 31, 2006 and March 1, 2007. The December 31, 2006 report includes five wells drilled in the fourth quarter of 2006 and the March 1, 2007 report includes the impact of our eight well winter delineation drilling program completed in the first quarter of 2007 which, as expected, continued to define significant additional recoverable resource.

Reserves and Resources as of:
December 31, 2006 March 1, 2007
Gross(1) Gross(1)
Based on DilBit Blending Scenario (Mbbl)(4) (Mbbl)(4) Increase
--------------------------------- --------- --------- --------

Probable Reserves (2P) 25,290 25,290 -
Probable plus Possible Reserves (3P) 70,323 70,323 -

Low Estimate Contingent Resources(2)(3) 335,689 405,263 69,574
Best Estimate Contingent Resources(2)(3) 468,009 574,060 106,051
High Estimate Contingent Resources(2)(3) 590,064 728,491 138,427

3P + Low Estimate Contingent Resource 406,012 475,586 69,574
3P + Best Estimate Contingent Resources 538,332 644,383 106,051
3P + High Estimate Contingent Resources 660,387 798,814 138,427

(1) Gross resources include the working interest reserves and 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).
(4) Mbbl means thousands of barrels.


Based on Dilbit Blending Scenario
Net Present Value Discounted at: 0% 5% 8% 10%

Probable Reserves (2P) 97 9 (25) (41)
Probable plus Possible Reserves (3P) 726 295 163 104

Low Estimate Contingent Resources 2,387 584 120 (63)
Best Estimate Contingent Resources 5,078 1,432 605 292
High Estimate Contingent Resources 8,389 2,265 1,047 606

3P + Low Estimate Contingent Resource 3,113 879 283 41
3P + Best Estimate Contingent Resources 5,804 1,727 768 396
3P + High Estimate Contingent Resources 9,115 2,560 1,211 710


Based on Dilbit Blending Scenario
Net Present Value Discounted at: 0% 5% 8% 10%

Probable Reserves (2P) 93 8 (25) (41)
Probable plus Possible Reserves (3P) 742 310 176 115

Low Estimate Contingent Resources 3,120 830 226 (17)
Best Estimate Contingent Resources 6,424 1,882 832 429
High Estimate Contingent Resources 10,578 2,925 1,385 822

3P + Low Estimate Contingent Resource 3,862 1,140 402 98
3P + Best Estimate Contingent Resources 7,166 2,192 1,008 544
3P + High Estimate Contingent Resources 11,320 3,235 1,561 937

(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 resources.
(4) A low estimate means higher certainty (P90), a best estimate (P50)
means most likely and a high estimate means lower certainty (P10).

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.

In connection with the recent updated reserve evaluations, McDaniels also conducted a preliminary estimate of gross bitumen-in-place on 60 of our 62 sections of oil sands leases. Their preliminary estimate of gross bitumen-in-place on our leases is approximately 2.2 billion barrels, which is a 38% increase from the earlier estimate of 1.6 billion barrels of gross bitumen-in-place from Fekete Associates in 2005. We are continuing to assess the ultimate potential bitumen-in-place on our lands, since the THAI™ technology is applicable over a broader range of reservoir characteristics than the SAGD process. This represents a significant opportunity to not only continue to increase the total amount of recoverable bitumen relative to the SAGD based estimates, but also for our THAI™ technology to greatly improve the ultimate recoverable volume and the per-barrel economics of fully developing our oil sands resource base.

WHITESANDS Operational Update

Further to our January 16, 2007 update, combustion operations continue on the first two well pairs and the pre-ignition heating cycle (PIHC) is nearing completion in the third well pair. The start of air injection and combustion in the third well pair is expected to occur around the end of the first quarter 2007. The PIHC phase for the third well is expected to be half the duration of the first well pair, similar to the second well. As a result, we are able to initiate combustion faster and minimize the amount of steam injected. Minimizing steam injection results in lower initial water cuts and a more rapid increase in oil cut. This is a significant improvement in operating performance from that experienced on the first well pair,

The second well's gross fluid production rates, on a restricted choke, have been up to 1,000 barrels per day with oil cuts of between 30 to 40 percent when producing at stable flow rates. We expect to achieve similar results when we start combustion operations on the third well.

Air injection in the first well has continued since July 2006 and production has continued on a restricted choke with a gross fluid rate of up to 1,000 barrels per day and oil cut in the 40 to 50% range. Restricted rates are necessary at this time to manage sand production and fluid rates in to the plant until we complete planned debottlenecking to enable the wells to produce at their higher capability.

While we have not expected to see a material and consistently upgraded produced oil this early in the process, we now believe that we are beginning to see some partially upgraded bitumen. One of the unique aspects of the oil produced by the THAI™ process is the lack of difficult emulsions and a clean oil/water separation. Recent production from the first well pair has demonstrated further improvements in oil/water separation and a reduced viscosity compared to our earlier production, leading us to believe that we are beginning to see an upgrading effect. We have initiated a third party analysis to determine the extent to which the oil is being upgraded.

Plant operations have experienced frequent down time due to recent modifications to the sand handling equipment, turnaround of the vent gas sweetening unit as well as periods of very cold weather in the first quarter. We are still in the early stages of the THAI™ process and in a state of continual adjustment of our operations. This continuous improvement process is consistent with starting up the first field scale demonstration of a new technology, allowing us to modify, on a controlled basis, the surface facilities and operating procedures. We foresee an ongoing process of technical improvement and innovation as we enhance our ability to produce oil using THAI™.

With completion of the recent delineation drilling we have now confirmed the geological parameters of the oil sands reservoir proximal to the current project site. This will allow for expansion of the current facilities by up to three wells, incorporating the CAPRI™ technology, as well as further commercial expansion to 10,000 barrels per day. Project scoping and preliminary engineering for debottlenecking the current facilities and the design of a 10,000 barrel per day project are proceeding.

We believe that THAI™ can also be applied to other heavy oil deposits beyond the Canadian oil sands and it is our strategy to next initiate projects in mobile conventional heavy oil reservoirs in Canada and/or internationally. Our goal is to capture a global portfolio of heavy oil resources where the application of our THAI™ technology can lead to greatly improved recovery rates and significant long-term value for the Company. In support of this activity, we are evaluating, with our Latin American subsidiary Petrominerales Ltd., three exploration blocks in Colombia's Llanos Basin heavy oil belt covering 0.8 million acres with a potential for large heavy oil accumulations.



Our Canadian Business Unit reserve engineers, Sproule Associates Limited ("Sproule"), have completed their evaluation of our conventional Canadian reserves as at December 31, 2006. All reserves are based on forecast prices and costs and are Company gross reserves. Summary results of the Sproule report are highlighted as follows:

- Total proved reserves of 6.7 million boe

- Proved plus probable reserves of 9.1 million boe

- Proved, probable and possible (3P) reserves of 12.7 million boe

- NPV 10% (before taxes) of $150.2 million (P+P), $193.9 million (3P)

Working Interest Reserves(1)
Forecast Prices(2)
Natural Light and Heavy
Gas Medium Oil Oil NGL Total
(mmcf) (mbbl) (mbbl) (mbbl) (mboe)
Developed Producing 12,864 858 14 34 3,050
Total Proved 30,956 1,425 14 77 6,675
Proved + Probable 39,257 2,460 17 129 9,148
Proved + Probable + Possible 53,544 3,433 129 240 12,726

(1) Company working interest reserves excluding royalty income reserves and
before deduction of royalties payable.
(2) Based on the Sproule Associates Limited price forecast effective
December 31, 2006.

Net Present Value - Before Tax (Cdn.$ millions)
Forecast Prices
As at December 31, 2006
0% 5% 10% 15%
Developed Producing 105.9 91.3 81.0 73.3
Total Proved 174.2 135.1 110.4 93.6
Proved + Probable 262.8 191.1 150.2 123.9
Proved + Probable + Possible 384.5 257.5 193.9 156.0

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 the fourth quarter of 2006 included 491 boepd of royalty income production.

Reserve Reconciliation - Forecast Prices (mboe)
Proved +
Total Proved + Probable +
Proved Probable Possible
December 31, 2005 reserves 7,372 11,635 16,188
2006 production net of royalty income (950) (950) (950)
Net change in reserves 253 (1,537) (2,512)
------ ------- -------
December 31, 2006 reserves 6,675 9,148 12,726

The Canadian Business Unit's reserve growth for 2006 was disappointing, due to delays earlier in 2006, most new production was not added until late in the year and we were unable to collect sufficient new production data to support the oil and gas reserves representative of what we actually believe we added during the year. Our current audited reserve estimates are down from the previous year, although we produced 27% more oil and gas last year then we did the year before, and our current production is 36% higher than our average production for 2006. Much of our new production at Red Willow and in the Bakken/Torquay play was added late in the year or early in 2007 resulting in conservative initial reserve estimates, due to lack of production history. Furthermore, our Jumpbush property experienced large negative reserve revisions due to lower gas prices and the deferral of development drilling and production maintenance from 2006 into 2007 and beyond. At Jumpbush, we have initiated an ongoing field and well maintenance program to optimize our production and recover reserves temporarily revised downward that, by analogy with offsetting production, are expected to be recovered. The results of this production maintenance program, the increased production history at key properties, and the continuation of our Bakken and Torquay drilling programs will likely result in an updated reserve evaluation being commissioned later in 2007.

Canadian Business Unit Operational Update

Petrobank's conventional Canadian production averaged 3,075 boepd during 2006 and 3,260 boepd during the fourth quarter of 2006 compared to 2,420 boepd during 2005. In 2006 Petrobank drilled 95 (79.6 net) wells resulting in 59 (50.3 net) gas wells and 29 (22.8 net) oil wells. During the first two months of 2007 production has increased further with the tie-in of a large portion of our 2006 drilling program either late in 2006 or early 2007. For the first two months of 2007 we averaged 4,192 boepd. In addition, we have just begun to add production from our ongoing 2007 drilling program, which will be largely focused on the Bakken and Torquay plays in southeast Saskatchewan and southwest Manitoba.


Petrominerales is also pleased to report on our 2006 year-end third party reserve report. Total proved plus probable reserves in Colombia have increased by 53%, based on the DeGolyer and MacNaughton ("D&M") evaluation as at December 31, 2006. 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 8% royalties. D&M's work incorporates an update of their comprehensive geological and petrophysical evaluation of both the Orito and Neiva properties but, to date, does not include any reserves associated with our 13 exploration blocks.

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

- Total proved reserves increased by 42% to 13.6 million barrels.

- Total proved plus probable reserves increased by 53% to 24.5 million barrels.

- Total proved, probable and possible reserves of 33.9 million barrels.

- Total proved plus probable NPV 10% (before taxes) increased 93% to US$521.8 million (3P - US$677.7 million).

Reserves - Company Interest
Light and Medium Oil (mbbl)
Developed Producing 3,947
Total Proved 13,563
Total Proved + Probable 24,531
Total Proved + Probable + Possible 33,906

Reserve Reconciliation
Proved +
Total Proved + Probable +
Proved Probable Possible
December 31, 2005 reserves 9,582 16,085 22,263
2006 production (2,194) (2,194) (2,194)
Net additions 6,175 10,640 13,837
------- ------- -------
December 31, 2006 reserves 13,563 24,531 33,906

Net Present Value - Before Tax (US$ millions)
0% 5% 10% 15%
Proved Developed 179.2 153.1 133.7 118.8
Total Proved 497.7 391.6 316.4 261.2
Proved + Probable 858.7 660.5 521.8 421.3
Proved + Probable + Possible 1,166.9 876.8 677.7 536.1

Latin American Business Unit Update

Joropo Exploration Success

Our Ojo de Tigre-2 well on the Joropo block in the Llanos Basin was initially drilled to a total depth of 8,309 feet and logged and evaluated. Based on our evaluation, and the geological and hydrocarbon indications in this initial well, a decision was made to side-track to a more favorable bottom-hole location. This second well, Ojo de Tigre-2 Side-Track, was drilled to a total depth of 8,419 feet and has been cased as a potential oil well. The well was cored through certain prospective intervals with indications of high quality oil bearing sands, which was confirmed by subsequent logs indicating a primary target with net oil pay in excess of 25 feet. The well is currently being completed with production results expected over the next several weeks. Unfortunately, this portion of the Llanos Basin is subject to wet surface conditions during the summer months, but we are evaluating alternatives to allow long-term, year-round production of this well. The ultimate size of the prospect will be determined through long-term production testing and potential follow-up drilling. Successful development of this discovery will most likely include upgraded surface access, which would allow for year-round production.

This initial result at Joropo is very encouraging as we have only evaluated a very small part of the 72,257 acre Joropo Block to-date, and we have now submitted applications for two blocks adjoining Joropo totaling an additional 69,122 acres. This was the first of five exploration wells to be drilled in 2007 on our extensive exploration acreage. We have either executed or we are finalizing 13 exploration block contracts totaling 1.5 million acres in the Llanos and Putumayo Basins, making Petrominerales one of the largest exploration landholders in Colombia.

Development Blocks

During the fourth quarter the activities of Petrominerales were focused on continuing development in Orito, implementing our pilot fracture stimulation program in Neiva and preparing for a significant exploration drilling program in the Llanos and Putumayo Basins.

Fourth quarter 2006 production averaged 2,372 bopd compared 955 bopd in the fourth quarter of 2005 and 2,420 bopd in the third quarter of 2006. The significant increase from the prior year period is mainly due to the success of the Orito-117 and 118 completions at the end of the first quarter of 2006 which proved-up a significant southwest extension to the Orito field. The decrease from the prior quarter is mainly a result of certain wells being taken off production during the period for workovers, delays in bringing new production on-line and due to natural declines.

Since closing the Petrominerales IPO at the end of the second quarter of 2006 we have now drilled four new wells at Orito, but have been delayed in bringing production online due to limited access to equipment and services or down-hole mechanical problems. As can be seen from our independent reserve report, we have had a very successful drilling year in 2006. All of our development wells encountered significant oil columns. However, at the present time, a number of these wells are offline or awaiting services, final completion or equipment installation due to the lack of sufficient or suitable services. In an effort to mitigate these challenges we have placed three drilling rigs under long-term contract and we also plan to secure the required completion equipment under long-term contract to ensure existing wells and our new wells planned for 2007 are brought onstream as quickly as possible. This remains a significant challenge for our operations group given the record activity levels in the Colombian oil industry.

Board Changes

Petrobank has accepted the resignation of Robert G. Puchniak from its Board of Directors, effective March 12, 2007. The Company would like to thank Mr. Puchniak for his services as a director and wishes him well in his future endeavors. We are pleased to announce the appointment of Mr. Chris J. Bloomer to the Company's Board of Directors, effective March 12, 2007. Mr. Bloomer currently serves the Company in the role of VP Heavy Oil and CFO, and brings a wealth of public company experience to our Board.

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. The Canadian Business Unit is developing a solid production platform from low risk gas opportunities in central Alberta along with light oil resource plays in southeast Saskatchewan, complemented by new exploration projects and a large undeveloped land base. The Latin American Business Unit is operated by Petrobank's 80.7% owned, TSX-listed subsidiary, Petrominerales Ltd. (trading symbol: PMG), which produces oil through two Incremental Production Contracts in Colombia and has exploration contracts covering 1.5 million acres in the Llanos and Putumayo Basins. WHITESANDS Insitu Ltd., Petrobank's 84% owned subsidiary, owns 39,680 acres of oil sands leases with an estimated 2.2 billion barrels of gross bitumen-in-place 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 combines a vertical air injection well with a horizontal production well. THAI™ integrates existing proven technologies and provides the opportunity to create a step change in the development of heavy oil resources globally.

Natural gas volumes have been converted to barrels of oil equivalent ("boe") so that six thousand cubic feet ("mcf") of natural gas equals one barrel based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. Boes may be misleading, particularly if used in isolation.

Certain statements in this release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995. Specifically, this press release contains forward-looking statements relating to, prospects and technologies which remain unproven and the expected amount and timing of capital 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. Such factors include, but are not limited to: the ability to economically test, develop and utilize the technologies described herein, the feasibility of the technologies, general economic, market and business conditions; fluctuations in oil and gas prices; the results of exploration and development of drilling and related activities; 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.

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
    Vice-President Heavy Oil and Chief Financial Officer
    (403) 750-4400
    Petrobank Energy and Resources Ltd.
    Corey Ruttan
    Vice-President Finance
    (403) 750-4400
    (403) 266-5794 (FAX)