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

Petrobank Energy and Resources Ltd.

November 13, 2006 01:27 ET

Petrobank Announces Third Quarter Results and Continued Success at Whitesands

CALGARY, ALBERTA--(CCNMatthews - Nov. 13, 2006) - Petrobank Energy and Resources Ltd. (TSX:PBG)(OSLO:PBG) ("Petrobank" or the "Company") is pleased to announce third quarter financial and operating results. The Company's third quarter 2006 interim report, including financial statements and management's discussion and analysis, is available on the Company's website at www.petrobank.com, filed on SEDAR at www.sedar.com, and filed on the Oslo Bors website at www.oslobors.no.

HIGHLIGHTS

The third quarter results are highlighted as follows:

- At our WHITESANDS project we began combustion operations and produced first oil from the world's first THAI™ well pair, initiated the Pre-Ignition Heating Cycle ("PIHC") on the second of three well pair and drilled five successful exploration wells on our oil sands leases.

- The Company drilled 46 (40.5 net) conventional oil and gas wells in Canada.

- Conventional production averaged 4,939 boepd in the third quarter of 2006, a 40 percent increase over the comparative 2005 period.

- Funds flow from operations increased 67 percent to $14.8 million.

- Net income increased by 63 percent to $5.2 million.

- In July 2006, the Company closed a new $120 million credit facility and used a portion of the proceeds to repay the remaining $50 million of 9% subordinated notes that were outstanding.



FINANCIAL & OPERATING HIGHLIGHTS

Three months ended Nine months ended
September 30, % September 30, %
2006 2005 change 2006 2005 change
------------------------------------------------------------------------
------------------------------------------------------------------------
Financial
($000s, except where
noted)
Oil and natural gas
revenue 24,639 17,983 37 73,499 42,571 73
Funds flow from
operations (1) 14,788 8,877 67 45,368 16,848 169
Per share
- basic ($) 0.22 0.15 47 0.68 0.29 134
- diluted ($) 0.21 0.15 40 0.66 0.29 128
Net income 5,169 3,170 63 20,486 7,624 169
Per share
- basic ($) 0.08 0.05 60 0.31 0.13 138
- diluted ($) 0.07 0.05 40 0.30 0.13 131
Capital expenditures 57,904 32,094 80 158,356 59,716 165
Total assets 395,654 215,829 83 395,654 215,829 83
Net debt (2) 70,366 54,526 29 70,366 54,526 29
Common shares
outstanding, end of
period (000s)
Basic 67,293 59,148 14 67,293 59,148 14
Diluted 71,346 64,333 11 71,346 64,333 11

Operations (3)
Canadian operating
netback ($/boe except where noted)


Natural gas revenue
($/mcf) (4) 5.39 8.25 (35) 6.23 7.03 (11)
Oil and NGL revenue
($/bbl) 72.13 65.50 10 64.52 60.16 7
Oil and natural gas
revenue (4) 44.28 53.07 (17) 44.61 45.34 (2)
Royalties 6.00 10.41 (42) 6.94 9.24 (25)
Production expenses 8.63 5.81 49 6.47 6.52 (1)
Transportation
expenses 0.42 1.08 (61) 0.43 1.20 (64)
------------------------------------------------------------------------
Operating netback 29.23 35.77 (18) 30.77 28.38 8
Colombian operating
netback ($/bbl)
Oil revenue 64.58 60.24 7 63.20 53.97 17
Royalties 5.16 4.82 7 5.07 4.32 17
Production expenses 7.80 9.41 (17) 7.56 9.31 (19)
------------------------------------------------------------------------
Operating netback 51.62 46.01 12 50.57 40.34 25
Average daily
production
Canada - natural
gas (mcf) 10,578 11,485 (8) 13,267 10,805 23
Canada - oil and
NGL (bbls) 756 551 37 802 381 110
------------------------------------------------------------------------
Total Canada (boe) 2,519 2,465 2 3,013 2,182 38
Colombia - oil
(bbls) 2,420 1,073 126 2,133 1,056 102
------------------------------------------------------------------------
Total Company (boe) 4,939 3,538 40 5,146 3,238 59
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Calculated based on cash flow before changes in non-cash working
capital and asset retirement obligations settled.
(2) Includes working capital (deficiency) and subordinated notes. The
subordinated notes were repaid on July 31, 2006.
(3) 6 mcf of natural gas is equivalent to 1 barrel of oil equivalent
("boe").
(4) Canadian sales prices are shown after forward gas sales contracts.


OPERATIONAL UPDATE

Heavy Oil Business Unit

THAI™combustion operations at WHITESANDS during the third quarter of 2006 continued to confirm the effectiveness of the THAI™technology in our first well pair. Two additional key operational milestones were achieved in the third quarter with the initiation of the Pre-Ignition Heating Cycle ("PIHC") on the second well pair and the shipment of the first produced oil from the project.

Air injection and combustion was initiated on the first of the three project wells on July 20, 2006, and we have been continually injecting air into the vertical well of this center well pair. During the first three weeks of air injection, in-situ combustion ignition was confirmed as we measured various indicators of the combustion reaction, including significantly rising temperatures in the reservoir zone, production of combustion gases and rising horizontal well bore temperatures. This trend continued through the third quarter with recorded reservoir temperatures reaching as high as 800 degrees Centigrade. Combustion gas analysis consistently demonstrated a high ratio of carbon dioxide to carbon monoxide, indicating a very high level of conversion of oxygen, hydrocarbon gases indicative of thermocracking of oil in-situ, and free hydrogen generated from high temperature reactions, all indicators of efficient high temperature combustion. These data also suggest that we are upgrading the oil in-situ. We are very early in the process of building out the combustion front in the first THAI™ well pair and estimate that only approximately 7,000 m3 of the reservoir has been affected by combustion at the toe of the horizontal well, which is less than one percent to total reservoir volume expected to be affected by combustion over the life of each THAI™ well pair.

Since initiating THAI™ production operations, the gross production capability from the first horizontal well has consistently exceeded 1,000 barrels of fluid per day with the potential production capability double our initial forecast rate. High productive capacity has meant that we have had to manage operations to match well flow with current plant capability. The composition of produced fluids continues to be variable, consisting of a combination of condensed steam from the Pre-Ignition Heating Cycle ("PIHC"), reservoir water, bitumen, and sand. Bitumen production rates, while variable, increased over the quarter. During October we saw a significant rise in bitumen production and we produced approximately 4,000 barrels of bitumen. This production was not rateable on a daily basis since the plant facilities were not on stream for the entire period. However, during this period, when producing at high gross fluid rates, we experienced an average 30 percent bitumen cut. While facility bottlenecks and well and plant maintenance operations during the quarter reduced the ability to produce continuously and at the higher rates, air injection operations were not curtailed and have increased over the quarter, indicating an expanding area of combustion.

Surface facilities have been able to handle a wide range of fluid rates and temperatures, however we have experienced facilities downtime and reduced production due to equipment commissioning issues, adjustments to manage higher than design well production capability, and sand production. These facilities issues necessitate ongoing operational adjustments and sand clean-out procedures in the surface facilities and the horizontal well. As reported previously, the produced sand is very fine-grained, indicating that a sand-bridging structure within the reservoir has yet to be fully established. This is most likely a result of our transition from the earlier steam injection operations to combustion operations, and may have been impacted by earlier horizontal well procedures at the beginning of the THAI™ production phase. While we expect the produced sand to be minimized as the combustion front expands and a consistent rateable flow regime is established, we are also enhancing our sand handling capability to minimize plant down time. These facilities modifications are underway and are expected to be in place by the end of November.

Modified PIHC operations began late in the third quarter for the second well pair and we expect to initiate the PIHC for the third well pair in November. The modified PIHC operations are designed to reduce the amount of steam and time required to create reservoir mobility before initiating air injection and combustion.

We are still in the very 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 certain aspects of our surface facilities and operating procedures. We foresee an ongoing process of technical improvement and innovation as we enhance our ability to produce significant volumes of oil using the THAI™ process.

Additional Resource Delineation

During the second quarter of 2006, we reported that the estimated gross bitumen-in-place on a portion of the 62 sections of oil sands leases owned by our 84 percent subsidiary, WHITESANDS Insitu Ltd. had increased to 1.6 billion barrels, based on a May 2006 Fekete Associates Ltd. resource evaluation. In addition, a recoverable reserve and resource assessment by McDaniel Associates Ltd. ("McDaniel") effective May 1, 2006 estimated an initial gross recoverable bitumen volume, based on Steam Assisted Gravity Drainage ("SAGD") technology, of up to 537 million barrels, which includes 25 million barrels of gross probable reserves and 70 million barrels of gross probable plus possible reserves.

During the third quarter of 2006 we drilled five oil sands exploration wells on areas of the leases we believed to contain considerable additional recoverable resources. Weather and ground conditions prevented us from drilling an additional four planned wells, which will now be incorporated into our winter drilling program. The five new wells all intersected significant McMurray channel of a quality equal to or better than previous wells. All of these wells were cored and logged and will be incorporated into an updated McDaniel recoverable resource report. The initial McDaniel report included only 13 sections of our lands, those with at least one drill hole per section, and excluded a number of sections with McMurray channel indicated by our 3-D seismic and/or areas on trend with known McMurray channel. The additional ten well winter drilling program is also expected to delineate significant new recoverable bitumen resources. We have requested an update to the McDaniel report to reflect the impact of the most recent drilling program, and we anticipate a further update will follow our winter drilling program. We also plan to update the reserve evaluation based on the THAI™ recovery process which we believe will have a higher recovery rate, and hence greater recoverable reserves than the SAGD-based estimates.

Project Development

In addition to the ongoing delineation of the recoverable resource potential of our lands we are also evaluating a potential project site for a THAI™ expansion project of approximately 10,000 barrels per day. We have been in the early stages of evaluating a new project area proximal to the current pilot site, to optimize infrastructure, and have selected a preliminary project area. Project scoping and preliminary engineering are expected to commence early in 2007.

A CAPRI test is anticipated by mid 2007, this will either be through a modification of one of the three current horizontal wells, or in a well drilled specifically for CAPRI™.

The THAI™ Process

THAI™ is an evolutionary in-situ gravity assisted 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. During the process, a high temperature combustion front is created underground where part of the oil in the reservoir is burned, generating heat, which reduces the viscosity of the remaining oil allowing it to flow by gravity to the horizontal production well. The combustion front sweeps the oil from the toe to the heel of the horizontal producing well, recovering up to an estimated 80 percent of the original-oil-in-place while partially upgrading the crude oil in-situ. Petrobank controls all intellectual property rights to the THAI™ process and related enhancements, including the patented CAPRI™ technology, which offers the potential for further in-situ upgrading through the use of a well-bore integrated catalyst.

THAI™ has many potential benefits over other in-situ recovery methods, such as SAGD. These potential benefits include higher resource recovery, 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.

THAI™ can also be applied to other heavy oil deposits and it is our strategy to initiate projects in mobile oil reservoirs in Canada and/or internationally. Our ultimate 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 growth for the Company. In support of this activity, Petrobank's 80.7 percent owned subsidiary, Petrominerales Ltd. (TSX: PMG), is evaluating two heavy oil Technical Evaluation Areas in Colombia covering 0.8 million acres for the potential application of THAI™.

Canadian Business Unit

Canadian Business Unit production averaged 2,519 boe per day ("boepd") in the third quarter of 2006, compared to 2,465 boepd in the third quarter of 2005 and 3,017 boepd in the second quarter of 2006. Our 2006 program has, to date, experienced delays due to weather conditions, regulatory approval and equipment availability. At the end of the third quarter we began to bring on initial production additions from our successful 2006 projects that allowed us to exit the quarter producing approximately 3,000 boepd. During the third quarter, activity increased dramatically with the drilling of 46 (40.5 net) wells, compared to only 17 (14.1 net) wells in the second quarter and 12 (8.7 net) in the first quarter of the year. The majority of the impact of this 2006 program will be realized through production additions during the fourth quarter. The first new production in 2006 from our Jumpbush drilling program was tied-in to our facility at the end of the third quarter. We currently have approximately nine million cubic feet of natural gas per day ("mmcfpd") of behind-pipe capacity awaiting tie-in. The recent drop in natural gas prices had encouraged Petrobank to accelerate our low risk light oil drilling program and defer our gas drilling programs. Results to date on the light oil plays in both the Bakken and the Torquay zones of southeast Saskatchewan and southwest Manitoba are very encouraging and will result in significant new oil production being added during the fourth quarter.



Canadian Business Unit Drilling Results

Q1 Q2 Q3 Q4 Year
To Date To Date Success
Property Gross Net Gross Net Gross Net Gross Net Gross Net %
-------------------------------------------------------------------------
Jumpbush
/Milo 4.0 2.8 14.0 11.6 29.0 25.1 1.0 1.0 48.0 40.5 100%
Red Willow 2.0 2.0 1.0 1.0 4.0 4.0 1.0 1.0 8.0 8.0 75%
Innes
- Bakken - - - - 3.0 3.0 2.0 2.0 5.0 5.0 80%
Sinclair
- Torquay - - - - 6.0 6.0 5.0 5.0 11.0 11.0 100%
Other
operated 3.0 3.0 1.0 1.0 2.0 2.0 - - 6.0 6.0 67%
Non
-operated 3.0 0.9 1.0 0.5 2.0 0.4 - - 6.0 1.8 72%
-------------------------------------------------------------------------
Total 12.0 8.7 17.0 14.1 46.0 40.5 9.0 9.0 84.0 72.3 92%
% gas 42% 44% 88% 86% 72% 72% 22% 22% 65% 65%
-------------------------------------------------------------------------


Jumpbush

The majority of our 2006 Jumpbush wells were drilled in the third quarter. To date, we have drilled 44 (37.0 net) wells, 31 (23.9 net) of which have been tied-in and another 13 (13 net) wells are currently awaiting tie-in. Prior to year-end, additional compression will also be added to increase production from all of the wells drilled and tied-in this year. The 13 remaining wells to be tied-in have been tested at 3.6 mmcfpd but we expect the first month's contribution will be approximately 2.0 mmcfpd. We have one additional well planned to be drilled and tied-in this year. We continue to work on planning and regulatory approvals for a 50 to 100 well program next year.

Milo

Milo is just south and east of the Jumpbush property, where we have been extending our Jumpbush exploration model, pursuing Belly River zones with high initial production rates. In 2006, four (3.5 net) wells have been drilled, three (2.5 net) wells during the third quarter. This gas is more complicated to tie-in as we need to utilize third party pipelines and facilities. Currently the four wells have tested at aggregate rates of 2.25 mmcfpd, and we anticipate aggregate initial production from the wells of approximately 1.1 mmcfpd. Through the balance of 2006 we plan to tie-in the four wells and drill a fifth well. We continue to expand our inventory of opportunities on this trend and are confident in the exploration model we are employing to identify lands of interest and add to our inventory of drilling locations.

Red Willow

High deliverability Mannville zones that can be either oil or gas bearing characterize the Red Willow property. To date in 2006, eight wells (8.0 net) have been drilled, with four of those drilled in the third quarter and one more drilled in the fourth quarter. Our drilling resulted in one oil well and five gas wells. The best results have come from the last four gas wells drilled with three of these wells testing at combined rates of 5.3 mmcfpd. We anticipate the first month contribution from all four wells to be approximately 5.5 mmcfpd. Through the balance of 2006 we plan to tie-in these four wells and drill a horizontal well into an existing Glauconite zone oil pool.

Innes area - Bakken Resource Play

The Bakken resource play of southeast Saskatchewan generally requires horizontal wells with specialized fracture stimulations to create economic production of light oil. Petrobank initially participated in this play as a partner in wells operated by other companies testing the initial viability of extracting light oil from this geographically extensive, low permeability reservoir. In 2006 we have participated in four (0.81 net) joint interest wells to date. Furthermore, we expect to participate in an additional three (0.75 net) non-operated wells to be drilled by year-end. We have utilized the experience gained from these early joint ventures to high-grade and expand our 100 percent working interest acreage, further increasing our strong land position in the Bakken play. In the third quarter we began drilling our own 100 percent working interest wells. So far five horizontal wells have been drilled and the rig is currently drilling the horizontal section of our sixth well. The first two of these wells have been fracture stimulated and we expect to have production from our stimulated wells on-stream during the month of November, and we expect to have another five horizontal wells drilled by year-end. We have a large inventory of opportunities in this area and our success to date means we have added many more development locations to this inventory. Petrobank will monitor performance from this relatively new play before providing comments on additions to our production.

Sinclair / Ryerson area - Torquay play

The Torquay play, like the Bakken play, is a relatively new light oil play in southeast Saskatchewan and southwestern Manitoba. Petrobank was able to monitor this play through farm-out agreements on a small part of our fee-simple lands located in Manitoba. Through late 2005 and 2006 Petrobank continued to assess this new opportunity and expand our land position in Saskatchewan and Manitoba on the trend. Starting in the third quarter, we have now drilled 11, 100 percent working interest wells, all of which are cased as potential oil wells. In the Ryerson area, a new pool has been discovered and to date we have drilled seven development wells, four of which are producing with all seven expected to be on-line within two weeks. Our remaining exploration wells are being evaluated and we anticipate drilling a minimum of five more exploration or development wells by year-end. Our inventory of development locations has expanded rapidly as a result of our success in the area to-date. Again, we will be monitoring the performance from this relatively new play before providing comments on additions to our production.

Exploration

Petrobank is further positioning itself in new exploration areas with higher impact plays to compliment our large inventory of low-risk gas and light oil opportunities. This program is growing and we have acquired 5,120 acres of exploration lands on new prospects during 2006. We will continue to add to our land position and mature our exploration ideas in these new areas with seismic and technical work in preparation for drilling in 2007.

Latin American Business Unit - Petrominerales Ltd. ("Petrominerales")

During the third quarter the activities of Petrominerales, Petrobank's 80.7 percent owned subsidiary, 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 which will begin during the first quarter of 2007.

Third quarter 2006 production averaged 2,420 bpd compared to 2,612 bpd in the second quarter of 2006 and 1,073 bpd in the third quarter of 2005. 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 the re-work and recompletion programs outlined below, and due to natural declines.

Orito

We have now completed drilling three wells in the Orito field since June 2006, the Orito-119 well, the redrill of the Orito-116 location and the Orito-124 well.

The Orito-119 well was completed in the upper Caballos sands using a slim hole drilling design. Due to a lack of pressure integrity behind the production liner, a remedial cement job was attempted on the well. With this poor cement job, we were unable to apply our revised fracture stimulation program to the productive intervals in this well and initial oil production from the well has been limited to approximately 60 bpd. If this well exhibits improving productive capability as it cleans up following completion, we plan to install an electrical submersible pump to optimize the productive capability of the well.

Following the Orito-119 well, the rig drilled the sidetrack of the Orito-116 well, also incorporating our slim-hole drilling design, which reached total depth of 6,525 feet on July 4, 2006. As expected, the sidetrack well encountered a similar high quality series of Caballos sands as in the original 116 well which was our original confirmation of the southwest extension to the field, initially testing at rates of more than 1,000 bpd. Unfortunately, the sidetracked well appears to have experienced a casing collapse, similar to the one which occurred in the original 116 well and has now been abandoned. Based on these two well results and similar issues associated with the Orito-113 recompletion discussed below, Petrominerales will be eliminating slim-hole drilling design from our future development plans.

Following the Orito-116 sidetrack, the rig commenced drilling Orito-124, which reached total depth of 8,134 feet on October 3, 2006. We are in the process of completing the Orito-124 well, in the prolific southwest extension area of the field. Log analysis indicates significant hydrocarbon reserves in the Caballos B, C and D sands. Initial tests of the Caballos "B2" and "B3" reservoirs indicate oil productivity, and we are currently in the process of fracture stimulating these sands. Immediately thereafter we plan to fracture stimulate the C and D sands and put the well on test. The Orito-122 well is now drilling at a depth of 6,600 feet and we expect to reach total depth within the next week. The Orito-122 well is expected to prove the updip extension of the oil zone and more fully define the potential of this undrilled area. A successful well in this region of the field has the potential to further increase our inventory of development drilling locations.

In addition to this recent drilling, we also performed re-completions on the Orito-113 and Orito-115 wells. We re-entered the Orito-113 well in an attempt to recover lost production due to near wellbore damage and the well was also deepened to the Upper Caballos A sand. A slim hole liner was set in the previous open-hole productive interval to facilitate further fracture stimulation and zonal isolation. During our pre-stimulation operations, pressure communication behind the liner was observed, and the subsequent fracture stimulation was postponed. We installed a liner top packer to achieve annular isolation and performed a remedial cement job to allow for a successful fracture stimulation of the Caballos zone in that well. The well is currently cleaning up at rates of approximately 250 bpd. The Orito-115 well was also re-completed with a production liner and a fracture stimulation program. The well was placed back on-line recently, and is currently cleaning up with oil production rates of approximately 80 bpd, well in excess of the well's pre-stimulation potential.

Our second drilling rig, contracted for 16 months, has been further delayed and it is not expected to arrive in Orito before mid December. We are assessing the possibility of moving this rig directly to our Llanos exploration program to avoid high mobilization and demobilization costs associated with moving it into Orito where it would most likely only be capable of drilling one additional development well prior to returning to the Llanos Basin to commence our exploration program. Irrespective of our short-term plans, the rig will ultimately be moved to Orito to accelerate our development drilling program.

Neiva

At Neiva, we completed our initial phase of fracture stimulations involving five test wells in the Honda and Doima-Chicoral reservoirs. The DT-56 (Doima-Chicoral) stimulation was highly successful, increasing gross oil production rates from 86 to 170 bpd. The Honda formation fracture stimulations included the installations of progressive cavity pumps ("PCPs") and initially has resulted in significant increases in production. Based on positive initial results, we plan to drill at least three new Doima-Chicoral wells incorporating our fracture stimulation design into the completions. We will continue to monitor the Honda fracture stimulations and expect to be able to expand this program to more than 50 additional Honda locations at Neiva. We have also recently completed the conversion of two wells to water injectors as part of an initial pilot water flood program in the Honda reservoir. We commenced water injection on November 1st and expect response in the surrounding wells during the first half of 2007.

Exploration

Petrominerales has completed the first phase exploration commitments, which included acquiring 3-D seismic and interpretation of existing data on the first five of our exploration blocks, evaluating key, prospective portions of each block. Beginning in February 2007, we will begin a five-well drilling program to test the initial prospects on each of the Casanare Este, Casimena, Corcel and Las Aguilas blocks, as well as our second test on the Joropo block. In addition, Petrominerales has signed two exploration licenses (Mapache and Castor) covering a significant portion of the original Chicago Technical Evaluation Agreement ("TEA"). The recently signed Mapache block covers 107,705 acres and our proposal includes a first phase commitment to acquire 40 square kilometers of 3-D seismic and to drill two exploration wells, which are scheduled for the first quarter of 2008. The Castor block, which was just approved by the National Hydrocarbon Agency, covers 110,265 acres and our proposal includes the acquisition of an initial 30 square kilometer 3-D seismic survey and drilling one well. Petrominerales has also been evaluating the heavy oil potential of our two TEAs in the southern Llanos Basin, where there is evidence of an extensive heavy oil belt. We have begun negotiations to change the entire Rio Ariari TEA to an exploration block covering slightly more than 600,000 acres. Our proposal includes a first phase work commitment of 100 kilometers of 2-D seismic. We hope to complete negotiations on the Rio Ariari exploration license by the end of the month. We have also submitted a proposal to convert approximately 177,500 acres of the original Chiguiro TEA into an exploration license and we are evaluating our first right of refusal on a third party proposal over another portion of the original TEA area covering approximately 125,000 acres. Petrominerales has a license to use Petrobank's THAI™ technology and is evaluating the technology's applicability to these Llanos Basin heavy oil deposits.

Upon acceptance of these most recent exploration proposals, Petrominerales' exploration land base will total 2.0 million acres in nine exploration blocks and two TEAs.

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 combines conventional oil and gas operations with two higher potential coalbed methane opportunities. 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 and Technical Evaluation Agreements covering a total of 2.0 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 1.6 billion barrels of bitumen-in-place and operates the WHITESANDS project to field-demonstrate 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.

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 for technologies which remain unproven, the expected amount and timing of capital projects and the results of operations. 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 CEO
    (403) 750-4400
    or
    Petrobank Energy and Resources Ltd.
    Chris J. Bloomer
    Vice-President Heavy Oil and CFO
    (403) 750-4400
    or
    Petrobank Energy and Resources Ltd.
    Corey C. Ruttan
    Vice-President Finance
    (403) 750-4400
    (403) 266-5794 (FAX)
    Email: ir@petrobank.com
    Website: www.petrobank.com