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

Petrobank Energy and Resources Ltd.

August 10, 2007 19:48 ET

Petrobank Announces Second Quarter Results

CALGARY, ALBERTA--(Marketwire - Aug. 10, 2007) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Corporation") (TSX:PBG) (OSLO:PBG) is pleased to announce second quarter financial and operating results.

HIGHLIGHTS

- Production increased by 23 percent to 6,942 barrels of oil equivalent per day ("boepd") from 5,629 boepd in the second quarter of 2006. Canadian Business Unit production increased by 36 percent to 4,094 boepd while production from the Latin American Business Unit increased by nine percent to 2,848 barrels of oil per day ("bopd").

- Capital expenditures were $165.7 million: $114.6 million in Canada; $42.1 million in Latin America; and $9.0 million in the Heavy Oil Business Unit.

- Net income increased to $16.6 million, 37 percent higher than the second quarter of 2006. On a per diluted share basis, net income increased by 29 percent to $0.22 in the second quarter of 2007 from $0.17 in the first quarter of 2006.

- Funds flow from operations increased to $21.6 million compared to $19.0 million in the same period a year earlier. On a per diluted share basis, funds flow from operations decreased by four percent to $0.26 in the second quarter of 2007 from $0.27 in the second quarter of 2006.

- Issued four million common shares at $21.00 per share for gross proceeds of $84.0 million.

- Issued US$250 million of three percent convertible debentures.

- Initiated THAI™ combustion operations on the third well pair at our WHITESANDS project.

- Acquired the 16 percent interest in WHITESANDS held by a minority shareholder increasing our ownership to 100 percent.

- Increased our oil sands land base by 10 sections bringing our oil sands holdings to a total of 72 sections (46,240 acres).

- Drilled 13 (12.25 net) successful oil wells in the second quarter targeting the Bakken resource play in Canada. Increased our land position on the Bakken light oil resource play by 132 percent to 114,000 net acres. Canadian Business Unit production has now increased to 4,600 boepd and we expect to add production from approximately six new Bakken wells each month.

- Latin American Business Unit production increased to 3,838 bopd in July 2007. Further production additions are expected as a result of the recently completed Corcel-1 exploration well.

The following table provides a summary of Petrobank's financial and operating results for the three and six month periods ended June 30, 2007 and 2006. Consolidated financial statements with Management's Discussion and Analysis ("MD&A") are available on the Corporation's website at www.petrobank.com and will also be available on the SEDAR website at www.sedar.com.



Three months ended Six months ended
June 30, June 30,
% %
Financial 2007 2006 change 2007 2006 change
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($000s, except where noted)
Oil and natural gas revenue 36,859 27,267 35 66,330 48,860 36
Funds flow from
operations (1) 21,580 19,003 14 39,815 30,502 31
Per share - basic ($) 0.28 0.28 - 0.54 0.46 17
Per share - diluted ($) 0.26 0.27 (4) 0.51 0.45 13
Net income 16,564 12,075 37 20,303 15,317 33
Per share - basic ($) 0.22 0.18 22 0.27 0.23 17
Per share - diluted ($) 0.22 0.17 29 0.27 0.22 23
Capital expenditures 165,707 32,935 403 238,319 100,452 137
Total assets 832,132 375,367 122 832,132 375,367 122
Net bank debt (2) 4,425 26,743 (83) 4,425 26,743 (83)
Common shares outstanding,
end of period (000s)
Basic 76,591 67,258 14 76,591 67,258 14
Diluted 89,775 71,498 26 89,775 71,498 26
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Operations
Canadian Business Unit
operating netback ($/boe
except where noted) (3)
Oil and NGL revenue ($/bbl) 67.53 68.42 (1) 65.50 61.08 7
Natural gas revenue
($/mcf) (4) 6.86 5.84 17 6.97 6.54 7
Oil and natural gas
revenue (4) 54.91 43.86 25 52.87 44.75 18
Royalties 4.35 6.13 (29) 5.06 7.31 (31)
Production expenses 8.60 6.46 33 8.34 5.62 48
Transportation expenses 0.26 0.43 (40) 0.30 0.44 (32)
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Operating netback 41.70 30.84 35 39.17 31.38 25

Colombian operating netback
($/bbl)
Oil revenue 63.29 64.05 (1) 61.29 62.33 (2)
Royalties 5.09 5.17 (2) 4.92 5.02 (2)
Production expenses 6.74 6.26 8 7.37 7.41 (1)
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Operating netback 51.46 52.62 (2) 49.00 49.90 (2)

Average daily production (3)
Canada - oil and NGL (bbls) 2,132 797 168 1,913 824 132
Canada - natural gas (mcf) 11,771 13,322 (12) 13,093 14,634 (11)
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Total Canada conventional
(boe) 4,094 3,017 36 4,095 3,263 25
Colombia - oil (bbls) 2,848 2,612 9 2,447 1,988 23
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Total Company conventional
(boe) 6,942 5,629 23 6,542 5,251 25
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(1) Non-GAAP measure calculated based on cash flow from operations before
changes in other non-cash working capital.
(2) Non-GAAP measure includes working capital deficiency (surplus), bank
debt and subordinated notes. The subordinated notes were repaid on July
31, 2006.
(3) Six mcf of natural gas is equivalent to one barrel of oil equivalent
("boe"). Heavy Oil Business Unit 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 forward gas sales contracts.


Heavy Oil Business Unit

Increased WHITESANDS Ownership and Expanded Oil Sands Land Base

On June 11, 2007, Petrobank acquired the WHITESANDS Insitu Ltd. ("WHITESANDS") common shares held by a 16 percent minority shareholder for $120 million, increasing Petrobank's ownership of WHITESANDS from 84 percent to 100 percent. This transaction was completed pursuant to the terms of the Unanimous Shareholders Agreement governing the original investment, and involved an independent third party evaluation of the WHITESANDS common shares.

WHITESANDS acquired, at an August 8, 2007 Crown land sale, an additional 10 sections of oil sands leases south of our existing oil sands leases for a cost of $0.5 million. This brings our total oil sands land holdings to 72 sections, or 46,240 acres.

WHITESANDS Operations

Combustion operations continued on the first two well pairs throughout the first half of the year, and air injection and combustion operations were successfully initiated on the third well pair late in the second quarter. We have now repeatedly demonstrated our ability to successfully initiate combustion using our THAI™ technology. The know-how gained in starting up these first three wells is being incorporated into a simultaneous start-up design for the next three wells, rather than the sequential start-up operation we employed initially.

We have been continuously injecting air in the first well pair for over 12 months, in the second well pair for over seven months, and in the third well pair for over one month. The third horizontal well has demonstrated the same production characteristics as the first two wells, with unrestricted gross fluid production capability of up to 2,000 barrels per day and oil cuts of over 50 percent. The wells have exhibited high sand production volumes and we have had to run them on very low choke settings, significantly restricting flow rates in order to achieve higher on-stream factors through the surface facilities. A small test sand knock-out vessel demonstrated that the sand can easily be removed from the produced fluids, providing the data necessary to design the larger knock-out vessels required to operate each of the wells at their demonstrated capacity. The first, single well, sand knock-out vessel is expected to be fully operational next week, and we expect to have all three vessels in operation by mid-October. Production rates and on-stream factors are expected to increase significantly with the installation of the new sand knock-out facilities that will allow the wells to operate at their demonstrated combined capacity of up to 6,000 barrels per day of gross fluid, with oil cuts of over 50 percent.

Ongoing analysis of the produced oil has shown a continuous upgrading effect. The produced oil is a blend of oil directly affected by combustion and oil that is mobilized and drained by heat conducted into the reservoir beyond the combustion front, which results in a varying quality of produced oil. The produced oil has consistently been of a materially lower viscosity and higher gravity than the native bitumen (500,000 centipoises, 7.6 degree API gravity). The quality of the produced oil has been, at times, up to 16 degrees API and less than 100 centipoises. We anticipate that with the addition of the three sand knock-out vessels and the anticipated higher production rates, we will see production that is more consistently upgraded.

In addition to the continued upgrading of the bitumen in-situ, the produced water has been of very high quality, with clean oil/water segregation and minimal emulsion to process. Analysis of the produced water indicates that it will, with minor further processing, be suitable for other industrial uses.

The current operation, with all three well pairs on continuous air injection and production, indicates that the producing zones associated with the three wells are now in communication. This is a significant observation as this was not expected to occur until later in the project timeline once the combustion zones for each well had advanced further in the reservoir. This earlier-than-expected interaction between the wells will allow us to increase the spacing in our next set of wells from 100 meters to at least 125 meters, thus reducing the number of wells required to produce a given reservoir, and further improving the capital efficiency of the process.

Project Development

In addition to retrofitting the facilities for sand handling and other upgrades, we have initiated a debottlenecking and expansion engineering project to be able to process production from three additional well pairs anticipated to be drilled later this year. These wells will incorporate the CAPRI™ process in which an upgrading catalyst is added around the outside of the well bore to enhance the upgrading of the oil in-situ and a modified liner completion designed to reduce sand production which could reduce the need for additional knock-out facilities. We have also initiated the engineering design for a 10,000 barrel per day project and expect to file this regulatory application by the end of 2007.

Along with our project development plans for our oil sands leases, we continue to evaluate the use of the THAI™ technology in various reservoirs in other regions of the world, including conventional heavy oil reservoirs in Canada. These evaluations are being conducted with third parties that have executed technology evaluation agreements aimed at demonstrating the applicability of the THAI™ technology in other potential projects, and include provisions for future licensing opportunities.

Resource Delineation

In the first quarter of 2007, Petrobank drilled eight delineation wells on the WHITESANDS lands and increased the gross discovered resources of bitumen-in-place on our oil sands leases to 2.6 billion barrels, as estimated in our March 2007 McDaniel and Associates Consultants Ltd. ("McDaniel") reserve report. This represents a 1.0 billion barrel increase from the 1.6 billion barrels first announced in May 2006. McDaniel assigned a recoverable bitumen resource of up to 799 million barrels at March 1, 2007 which compares to 660 million barrels estimated at December 31, 2006. Further delineation drilling to be conducted in late 2007 or early 2008 is expected to add additional recoverable volumes. Since the current recoverable resource evaluations are based only on SAGD recovery technology, the incorporation of the THAI™ technology into our evaluation is expected to materially increase future estimated recoverable bitumen resource. McDaniel has been engaged to conduct an evaluation of our resource utilizing the THAI™ technology recovery method.

Canadian Business Unit

The Canadian Business Unit produced 4,094 boepd in the second quarter of 2007, an increase of 36 percent over 3,017 boepd in the second quarter of 2006. The majority of this increase is from our new Bakken light oil wells being brought on-stream. The Canadian Business Unit drilled 14 (13.25 net) successful oil wells during the quarter with the majority of the activity focused on the Bakken resource play in southeast Saskatchewan. We have recently experienced production losses from our Red Willow property in Alberta, which are being addressed with well workovers and facilities upgrades. We expect further significant production increases as wells are brought on-stream from our active Bakken drilling program.

Bakken Light Oil Resource Play

The Canadian Business Unit continues to build on our success in the large Bakken light oil resource play and, with four drilling rigs working continuously, we have been able to further develop our key areas of proven production and expand the boundaries of the play into new areas. During the second quarter, Petrobank drilled 13 (12.25 net) wells in the Bakken bringing the total for the first half of 2007 to 24 (21.75 net). During the month of July, a further 10 (8.5 net) wells were drilled which should keep us on track to have more than 60 net Bakken horizontal wells drilled by year-end.

Of our 34 successful 100 percent working interest Bakken wells drilled through July 2007, 23 are currently on-stream, with the remainder in various stages of completion. Due to surface access and weather related delays, our fracture stimulations in the horizontal portion of the wells, have lagged our drilling efforts. Completion activities have been particularly hampered by wet ground conditions through the spring and early summer. During the first quarter only four of our 100 percent operated wells were fracture stimulated and during the second quarter only nine further wells were successfully completed. At the end of the second quarter our inventory of 100 percent wells awaiting fracture stimulation stood at nine wells and growing. Improving weather, beginning in mid-July, has allowed the completion crews to steadily diminish our inventory of wells awaiting fracture stimulation, and we expect this inventory to be minimal by the end of August. Total Bakken oil production over the quarter increased from approximately 730 bopd in late-March to approximately 1,700 bopd in late June despite the delays in completions. Current Bakken oil production is now approximately 2,600 bopd bringing the Canadian Business Unit's total production to approximately 4,600 boepd. This excludes 400 boepd of production that is currently shut in at Red Willow as a result of facility maintenance.

To realize the full value of our Bakken oil resource, Petrobank plans to capture the additional value of the liquids-rich associated gas. By the end of the third quarter, we plan to have our new oil battery and gas plant constructed and tied directly into the Enbridge and Transgas pipeline systems in the Innes/Midale area. This facility will allow us to process the associated gas, stripping out the liquids and selling the lean gas. The majority of our 2007 drilling program will be focused in this area. As the number of our wells in nearby areas reaches critical mass, those areas will also be pipeline-connected to this facility. Additional facilities will be required in the future to address our large number of drilling opportunities and the significant areal extent of our land-base in this regional resource play.

The Bakken formation is found in the Williston Basin, underlying much of North Dakota, eastern Montana and extending up into southern Saskatchewan. The expansion of our presence in the Bakken play began with a drilling program that commenced in late 2006. The Mississippian aged Bakken is an extensive regional resource play with the oil contained mostly in siltstones and thin sandstone reservoirs with low porosity and permeability. The Bakken formation is capable of high initial production rates of sweet, light, 41+ degree API gravity oil, and liquids-rich solution gas. This resource is significant with approximately 4.5 million barrels of original oil-in-place per section (square mile or 640 acres) of land within the defined play area.

Management believes that the key to unlocking the potential in the Bakken has been recent advances in horizontal well techniques, particularly the application of new horizontal fracturing and completion technologies. Horizontal wells allow maximum exposure to the reservoir, and new completion techniques allow fracturing of the siltstone along the full extent of the wellbore to maximize production. These technologies have unlocked the production and recovery potential of the Bakken resource. Our horizontal drilling and fracture stimulation technique allows us to avoid fracturing out of the Bakken zone, thereby minimizing associated high water production common in other recent Bakken horizontal wells, and consequently significantly improving Bakken oil productivity. Ultimately we expect this to lead to substantially improved recovery rates. One of our Bakken wells, that commenced production in December of 2006, reached the end of its 37,740 barrel royalty holiday in just 7.5 months. This level of recovery represents more than half of the Sproule proven reserves initially attributed to the well. This was not forecast by Sproule to be achieved until December 2010, highlighting the strong performance we are achieving from our fracture stimulated Bakken wells.

Petrobank's independent reserve evaluator, Sproule Associates Limited ("Sproule"), currently assigns a proved, probable plus possible (3P) reserves estimate of 125,000 barrels per Bakken well. With our high initial production rates from our 100 percent working interest wells, we are producing in excess of the forecast type curves used in this preliminary evaluation. Petrobank's internal estimate is that each Bakken well will recover in excess of 150,000 barrels. We expect our next reserve evaluation to more appropriately reflect our actual Bakken performance to-date.

Following the success of our Bakken drilling program in late 2006, we proceeded, in early 2007, to drill a series of exploration wells to extend the boundaries of the Bakken resource play prior to the major April 2007 Saskatchewan Crown land sale. By the end of 2006, our land base on the Bakken light oil resource play stood at 62,448 (49,105 net) acres. Since the beginning of 2007, through Crown land sales and acquisitions, we have increased our acreage to a total of 138,000 (114,000 net) acres. The majority of this increase was Crown land purchased at the April Crown land sale where we spent $59.5 million to acquire 41,800 (41,800 net) acres. In addition, we closed an acquisition of a 50 percent working interest in certain producing properties in the Viewfield/Stoughton area of southeast Saskatchewan, with extensive undeveloped acreage and an ongoing farm-in with a third party, for $8.5 million. The acquisition included four (2.0 net) Bakken horizontal oil wells that were producing at un-stimulated (pre-fracture) rates of 80 (40 net) barrels of oil per day as well as 9,426 (4,813 net) acres of undeveloped land with the potential to earn a further 13,598 (6,799 net) acres with additional drilling. In a reserve report effective December 31, 2006, McDaniel and Associates Consultants Ltd. assigned total proved reserves of 251,000 barrels, and total proved plus probable reserves of 730,000 barrels, to these acquired lands. Recompletion of these wells using Petrobank's fracture stimulation technique is expected to significantly improve both production and reserves. Our Bakken results have allowed us to confidently pursue this land acquisition strategy, and our aggressive Bakken drilling program for 2007 and beyond.

The majority of our Bakken land base is expected to yield four horizontal wells per section. Currently, we estimate our Bakken drilling inventory at over 550 (500 net) locations. With these recent acquisitions, the Bakken light oil resource play is expected to be the Canadian Business Unit's primary focus area for years to come. Our highly effective Bakken drilling and stimulation program, along with the addition of a significant land base, has strategically positioned Petrobank to be a key Bakken light oil player.

Additional Canadian Business Unit Focus Areas

In addition to our Bakken light oil asset, we continue to develop our long-term legacy shallow gas and CBM asset at Jumpbush with an inventory of over 175 low-risk development drilling locations. We are discussing our development drilling plans with the Siksika First Nation. Petrobank is also aggressively moving forward on new, potentially high-impact exploration prospects in two key areas of north-western Alberta where we planned to test multi-zone oil and gas prospects with at least two exploration wells in 2007. The first of these two wells was recently completed and cased as a light oil well. Although production from this initial well is not expected to be material to Petrobank, the knowledge gained from this early success added greatly to our play understanding, resulting in an expanded northwest Alberta drilling program. We now intend to drill at least two additional wells in this area by the end of 2007. Petrobank continues to leverage its large undeveloped land base into exciting new opportunities.

Latin American Business Unit

Petrobank's Latin American Business Unit, operated through our 80.7 percent owned subsidiary, Petrominerales Ltd. ("Petrominerales"), produced 2,848 bopd in the second quarter 2007 compared to 2,042 bopd in the first quarter of 2007. The increase is mainly due to the ongoing Orito development program. Production averaged 3,838 bopd in July, and significant further production additions are expected as a result of the recently completed Corcel-1 exploration well. Based on test results, the Corcel-1 well is estimated to have combined productive capacity exceeding 10,000 bopd. The well will be initially completed and placed on a six-month test at 4,000 barrels per day, representing only minimal drawdown on the well.

DEVELOPMENT BLOCKS

Orito

Since closing our IPO at the end of the second quarter of 2006, we have now drilled nine new wells at Orito. The effects of this program started to be realized during the second and early third quarters of 2007. The drilling program for the remainder of the year includes four more wells in the Orito field and the Conga-1 exploration well on the Las Aguilas Block. In addition, workovers and pump changes are planned for six wells. Originally we planned to have two drilling rigs working in the Putumayo Basin, but, based on our Corcel-1 results, one of these rigs will remain on the Corcel Block to drill additional delineation and exploration wells.

Neiva

At Neiva, production has increased as a result of well optimizations and the initial success of our pilot waterflood program. Due to the results from the well optimization program and an earlier than expected waterflood response, we will continue the well optimization program and are considering an expanded waterflood.

2007 EXPLORATION PROGRAM

Petrominerales' 2007 exploration program includes the drilling of five wells. Four of these wells have been drilled, all in the Llanos Basin, two of which were completed as new pool discoveries. The remaining well will be drilled in September on the Las Aguilas Block adjacent to Orito, in the Putumayo Basin.

Joropo Block

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 was cased as a potential oil well. The well was cored through certain prospective intervals with indications of high quality oil bearing sands, which were confirmed by subsequent logs indicating a primary target with net oil pay in excess of 25 feet. The well was completed and initial production testing commenced, but was suspended with the onset of the rainy season. Initial test rates reached 450 barrels of fluid per day with a water cut of 20 percent and a gravity of 29 degrees API. The test interpretation indicated very high skin damage which was likely caused by the gravel pack completion. We will be returning to remediate the skin damage and conduct further testing of the well after the end of the rainy season in late 2007 or early 2008. The ultimate size of the prospect will be determined through long-term production testing and follow-up drilling. Successful development of this discovery will most likely include upgraded surface access, which will support 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 totalling an additional 69,122 acres. These two Blocks, Jabali and Jaguar, have been approved by Colombia's National Hydrocarbon Agency's (ANH) and are being finalized for signature.

Casimena Block

Drilling and logging operations were completed at the Mapuro-1 exploration well on the Casimena Block in the Llanos Basin which was drilled to the planned depth of 8,530 feet. Logs indicated that the sands in the Tertiary Carbonera and Mirador formations as well as the Cretaceous Guadalupe, Gacheta and Ubaque formations are predominantly wet or contain non-commercial hydrocarbon accumulations. As a result, the Mapuro-1 well was plugged and abandoned. Despite the results from this first well, this area of the Llanos Basin continues to be highly prospective. We may re-enter the Mapuro-1 well to drill a side track targeting the Ubaque formation as part of our 2008 drilling program.

Casanare Este Block

Our Casanare Este-1 exploration well was drilled to the planned depth of 9,938 feet. The well encountered sands in the Tertiary Carbonera and Mirador formations as well as the Cretaceous Guadalupe, Gacheta and Ubaque formations. However, all sands encountered were predominantly wet or contained non commercial hydrocarbon accumulations and the well was plugged and abandoned. We plan to drill the Casanare Este-2 well in 2008, targeting a structural-stratigraphic play.

Corcel Block

The Corcel-1 exploration well located in the southern Llanos Basin was drilled to a total depth of 12,000 feet. Logs indicated that the target reservoir sands in the Mirador and Guadalupe formations were primarily oil bearing with total potential net pay of approximately 140 feet of high quality sand.

The first zone completed in the Corcel-1 exploration well produced at initial rates of 970 to 1,200 barrels per day of 31 degree API oil, with no water, from the Guadalupe formation, which was the lowermost of our three test intervals. This Guadalupe interval comprises 40 feet of net pay and was evaluated using a jet pump configuration, limiting the ability to produce at full capability. The productivity index calculated from the initial test indicates that with the installation of a properly sized electric submersible pump ("ESP"), the Guadalupe could produce at initial rates of up to 2,500 barrels per day.

The lower Mirador intervals tested at initial rates of 1,500 to 2,300 barrels per day of 28 degree API oil, with no water. These rates were achieved with maximum drawdown of 17 percent from a sand interval with 58 feet of net pay, using the same jet pump configuration that limited the ability to produce the zone at full capability. The upper Mirador interval, containing 42 additional feet of potential oil pay, was commingled with the lower Mirador interval and tested using the same jet pump configuration. The entire Mirador section produced at rates of 2,300 to 2,800 barrels per day of 28 degree API oil, with no water. The productivity index calculated from this test indicates that with the installation of a properly sized ESP, the Mirador could produce at initial rates in excess of 10,000 barrels per day.

The well will now be tested with an ESP from all the Guadalupe and Mirador intervals commingled. Due to surface facility and permit limitations, the test will be conducted at rates increasing from 1,500 to 2,500 bopd over a 6-day period. After installing higher capacity surface facilities and receiving the regulatory permits required for a longer-term test, a six month test will begin at rates of 4,000 bopd. This longer-term evaluation is expected to commence in early September. Although the test will be at very low drawdown, the information obtained during the six months will give us information about the ultimate potential of the well.

We have also started construction of a second drilling pad and expect to spud our second Corcel well in August 2007. The rig will remain at Corcel to drill a continuing program of up to eight additional exploration and delineation wells.

The Corcel Block is situated in a drier region of the Llanos Basin and we have an all-weather road to this location which will accommodate year round production from the well. The ultimate size of the discovery will be defined through our long-term testing and delineation drilling program. Petrominerales has identified additional Corcel prospects from our 47 square kilometre 3D seismic survey, which only covers approximately 15 percent of the 79,815-acre block. In addition, an early 2008 3D seismic program is planned for our 26,341-acre Guatiquia Block, which adjoins the Corcel Block to the south.

Heavy Oil

Petrominerales has three large blocks in the southern Llanos Basin heavy oil belt, Chiguiro Oeste, Chiguiro Este and Rio Ariari. Our heavy oil blocks offset the Cano Sur Block, which is being developed by a recently announced partnership between Shell and Ecopetrol, reflecting the increasing interest in the heavy oil potential of this area.

In addition, Petrominerales intends to participate in the upcoming Heavy Oil Bid Round, expected to be announced later this year. Petrobank's proprietary THAI™ technology, which Petrominerales has licensed, represents a paradigm shift in heavy oil recovery technology. THAI™ is well suited to the Colombian heavy oil environment and should give us a competitive advantage in developing our existing heavy oil blocks.

THAI™ is being field-proven by Petrobank in the Canadian oil sands 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 a 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 heavy crude oil in-situ.

Exploration Summary

Petrominerales holds over 1.5 million acres of land in Colombia, on which we have acquired 357 square kilometres of 3D seismic and reprocessed all available 2D seismic data. This work program has generated 18 additional leads and prospects on these lands. We plan to acquire an additional 140 square kilometres of 3D seismic and 576 kilometres of reconnaissance 2D seismic, which should result in an expanded exploration drilling program for 2008 and beyond. In 2008, we currently plan to drill eight further exploration wells focused primarily in the Llanos Basin.

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 Corporation 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 and an extensive inventory of Bakken light oil locations 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 wholly-owned subsidiary, owns 46,240 acres of oil sands leases with an estimated 2.6 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 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 Energy and Resources Ltd.

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 the 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. 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.

Contact Information

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