Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd.

November 09, 2007 17:57 ET

Petrobank Announces Record Production and Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 9, 2007) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) (OSLO:PBG) is pleased to announce record third quarter financial and operating results. Each of Petrobank's three business units is operating on an accelerated growth profile. Both the Canadian and Latin American Business Units are setting new production highs fueled by light oil production growth. The Heavy Oil Business Unit has proven the THAI™ technology in the Canadian oil sands and is now advancing our global THAI™ business plan.


- Production doubled in the third quarter of 2007 to 9,935 barrels of oil equivalent per day ("boepd") from 4,939 boepd in the third quarter of 2006. Canadian Business Unit production increased by 115 percent to 5,413 boepd while production from the Latin American Business Unit increased by 87 percent to 4,522 barrels of oil per day ("bopd").

- Production in early November exceeded 16,000 boepd, including 8,130 bopd from the Latin American Business Unit (excluding our Corcel-2 well) and 7,885 boepd from the Canadian Business Unit.

- Capital expenditures were $135.4 million: $79.0 million in Canada; $41.1 million in Latin America; and $15.3 million in the Heavy Oil Business Unit.

- Funds flow from operations increased to $42.3 million compared to $14.7 million in the same period a year earlier. On a per diluted share basis, funds flow from operations increased by 129 percent to $0.48 in the third quarter of 2007 from $0.21 in the third quarter of 2006.

- Net income increased to $21.0 million, a 306 percent increase from the third quarter of 2006. On a per diluted share basis, net income increased by 257 percent to $0.25 in the third quarter of 2007 from $0.07 in the third quarter of 2006.

- In August, the Company acquired a 23,040 acre oil sands licence in Saskatchewan at the Crown Land Sale.

- On November 1, 2007 the Company announced the first THAI™ licensing agreement in Canada and acquired a 50% interest in certain heavy oil lands and related assets in the Peace River region of northwest Alberta.

- The Company expects minimal impact to existing cash flows as a result of the proposed royalty changes in the province of Alberta. The majority of the Company's Canadian oil production is in the province of Saskatchewan and the majority of our natural gas production is on First Nation lands in Alberta, which are not subject to Alberta Crown royalties.

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

Three months ended Nine months ended
September 30, % September 30, %
Financial 2007 2006 change 2007 2006 change
($000s, except where
Oil and natural gas
revenue 61,567 24,639 150 127,897 73,499 74
Funds flow from
operations (1) 42,316 14,706 188 82,131 45,208 82
Per share - basic ($) 0.55 0.22 150 1.09 0.68 60
Per share
- diluted ($) 0.48 0.21 129 1.01 0.66 53
Net income 20,978 5,169 306 41,281 20,486 102
Per share - basic ($) 0.27 0.08 238 0.55 0.31 77
Per share
- diluted ($) 0.25 0.07 257 0.53 0.30 77
Capital expenditures 135,417 57,904 134 373,736 158,356 136
Total assets 930,855 395,654 135 930,855 395,654 135
Net debt (2) 37,762 70,366 (46) 37,762 70,366 (46)
Common shares
outstanding, end of
period (000s)
Basic 76,897 67,293 14 76,897 67,293 14
Diluted 90,083 71,346 26 90,083 71,346 26

Canadian Business Unit
operating netback
($/boe except where
noted) (3)(4)
Oil and NGL revenue
($/bbl) 76.56 72.13 6 71.00 64.52 10
Natural gas revenue
($/mcf) (5) 5.35 5.39 (1) 6.51 6.23 4
Oil and natural gas
revenue (5) 62.86 44.28 42 56.87 44.61 27
Royalties 4.18 6.00 (30) 4.71 6.94 (32)
Production expenses 8.26 8.63 (4) 8.31 6.47 28
expenses 0.18 0.42 (57) 0.24 0.43 (44)
Operating netback 50.24 29.23 72 43.61 30.77 42

Colombian operating
netback ($/bbl) (3)
Oil revenue 72.74 64.58 13 66.84 63.20 6
Royalties 6.32 5.16 22 5.60 5.07 10
Production expenses 7.42 7.80 (5) 7.40 7.56 (2)
Operating netback 59.00 51.62 14 53.84 50.57 6

Average daily
production (4)
Canada - oil and NGL
(bbls) 3,745 756 395 2,531 802 216
Canada - natural gas
(mcf) 10,006 10,578 (5) 12,053 13,267 (9)
Total Canada
conventional (boe) 5,413 2,519 115 4,540 3,013 51
Colombia - oil (bbls) 4,522 2,420 87 3,146 2,133 47
Total Company
conventional (boe) 9,935 4,939 101 7,686 5,146 49
(1) Non-GAAP measure calculated based on cash flow from operations before
changes in non-cash working capital.
(2) Non-GAAP measure includes bank debt plus accounts payable and accrued
liabilities less current assets.
(3) Non-GAAP measure demonstrating Company's revenue less royalties,
production and transportation expenses per unit produced.
(4) 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 pre-operating stage and accordingly are capitalized.
(5) Canadian sales prices are shown after forward gas sales contracts.

Heavy Oil Business Unit


Since July 2006, we have proven our ability to operate the THAI™ process continuously under a variety of operating conditions in one of the world's most challenging reservoir environments. THAI™ is a field-proven technology that will be deployed globally.

THAI™ combustion operations continued on all three wells during the third quarter. As of the end of October, all three of the new sand-handling facilities were installed and being commissioned on each of the wells. These new facilities will enable the wells to produce at their indicated potential of approximately 2,000 barrels of fluid per day per well with a greater than 50% oil cut. We are targeting to have all three wells operating at their full potential by the end of 2007. In addition, these new facilities have been designed to handle the produced fluids from the next three THAI™/CAPRI™ wells that we plan to drill.

With the new facilities, we will be operating with minimal wellhead choking and future production will be managed by the throughput rates of the new vessels. The first of the new facilities was successfully tested early in October 2007 to assess sand handling efficiency and the well's productive capability. The well was only partially drawn down and produced at approximately 800 bopd with a 50% oil cut. After this test, the production rate was reduced to install and commission the remaining two facilities. The wells were intermittently shut in during these operations to accommodate well tie-ins. Along with the installation of the sand vessels, we have also upgraded the overall facility to improve efficiency and to pre-build for the next three wells. This enhanced design will reduce the capital requirements and construction time for the next three THAI™/CAPRI™ wells.

We are also pleased to report that we have been continuously producing upgraded oil. The native bitumen, in-situ, is approximately 500,000 centipoises viscosity and 7.6 degree API gravity. The produced oil is from 10 to 17 degrees API with viscosities ranging from approximately 2,000 to less than 100 centipoises. This upgrading effect has demonstrated a continuously improving trend. Along with the improved oil quality, the produced water is very high quality, non-acidic, with clean oil/water separation and minimal emulsion to process. Analysis of the produced water indicates that it will, with minor further processing, be suitable for other industrial uses.

WHITESANDS Project Development

We have re-engineered the design for the three well expansion to reduce the surface footprint and eliminate facilities at both the injection and production pads. We can utilize our upgraded infrastructure for air injection and production fluids processing for the new THAI™/CAPRI™ wells. These wells will incorporate the CAPRI™ process, in which a catalyst is added around the outside of the well bore to enhance the upgrading of the oil in-situ. We will also use a modified liner completion designed to reduce sand production. We are waiting on regulatory approval for the new wells and expect to begin drilling by the end of 2007 or early 2008.

We are now completing the engineering design phase for a 100,000 bopd project at WHITESANDS, and plan to issue a public disclosure document outlining our plans by the end of 2007. We now expect to file the related regulatory application in the first quarter of 2008. We have recently developed a new centralized process design which will greatly reduce the facilities footprint and which we expect will enable faster regulatory approval and project execution. The first phase of the project is expected to be at least a 10,000 bopd module, expandable from a central location to the ultimate design capacity of 100,000 bopd.

THAI™ Business Development

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 and are aimed at demonstrating the applicability of the THAI™ technology in other potential projects, and include provisions for future licensing opportunities. The activities are now at the stage where we expect to have a pipeline of licensing opportunities and projects for the implementation of THAI™ on a global basis.

The Dawson Property Acquisition

The recent Duvernay Oil Corporation ("Duvernay") license agreement and property acquisition is the first transaction to deploy the technology in a more conventional heavy oil reservoir. In late October, we entered into a THAI™ license agreement with Duvernay and acquired a 50% working interest in certain Duvernay heavy oil lands and related assets in the Peace River region of northwest Alberta ("the Dawson Property"). These assets are comprised of 2,880 acres of land, and include two existing horizontal wells and related facilities. Petrobank's internal evaluation of the Dawson Property yields an estimated original-oil-in-place resource of approximately 100 million barrels, utilizing existing 3D seismic and available well data. We intend to update the reserve and resource estimated for the property in connection with our year end independent reserve evaluation.

The main producing zone in the Dawson area is the Bluesky formation, which contains heavy oil capable of being produced using cold production techniques. There are already numerous cold producing operations in the area, and operators have indicated plans to implement conventional thermal recovery projects. For Petrobank, this property represents an excellent opportunity to implement the THAI™ process in a conventional heavy oil reservoir, which was the initial target reservoir application for THAI™ when it was first developed at the University of Bath in England.

Initial development plans at Dawson will involve a two-well THAI™ project, which can then be expanded to accommodate additional wells on the property. Petrobank is the operator and we intend to commence engineering and regulatory work to undertake this THAI™ project in 2008.

Petrobank and Duvernay have established an area of mutual interest ("AMI") in lands surrounding the Dawson Property where we intend to jointly expand production and reserves through the application of the THAI™ technology on third-party lands and/or jointly acquired properties in the region.

THAI™ License Agreement

Archon has entered into a license and royalty agreement with Duvernay to allow Petrobank's patented THAI™ process to be utilized on the Dawson Property and within the AMI. Archon will earn a ten percent gross overriding royalty on Duvernay's share of production following recovery of a specified amount of production.

The acquisition of the Dawson Property and the licensing agreement with Duvernay is an important first step in Petrobank's development plans for the commercialization of the THAI™ technology on a global basis. The Dawson Property and AMI cover an extensive heavy oil belt with a number of large existing conventional cold heavy oil production operations that typically recover only six to 10 percent of the original-oil-in-place. The application of the THAI™ process in these reservoirs has the potential to increase recoveries up to 70 to 80 percent.

Expanding Oil Sands Land Base

In addition to the Dawson Property acquisition, Petrobank acquired a 23,040 acre oil sands licence in Saskatchewan during the third quarter. The licence has a primary term of five years and forms the basis for a possible future expansion of the application of the THAI™ technology into an exciting new oils sands resource fairway. Initial resource delineation of this licence is expected to commence in late 2008. The Saskatchewan lands are in addition to the acquisition, during the third quarter at an Alberta land sale, of ten sections of oil sand leases south of our existing lands bringing our total portfolio of Alberta oil sands leases to 72 sections. We will evaluate the resource potential of these new Alberta oil sands lands with an early 2008 drilling program.

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 represented 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 from the existing and recently acquired Alberta oil sands lands. We plan to commence our winter drilling program before the end of the year. 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 and reflect the lower capital and operating costs associated with our process. McDaniel has been engaged to conduct an evaluation of our resource utilizing the THAI™ technology recovery method.

Archon Technologies Ltd.

Petrobank's wholly-owned subsidiary, Archon Technologies Ltd. ("Archon"), has also been actively evaluating the acquisition and development of several new technologies and innovations around the base THAI™ and CAPRI™ technologies to capture the full commercial benefits of a THAI™ project. These technologies are in the areas of sulfur recovery, innovative additional surface upgrading processes, produced water processing, oxygen enriched air injection to increase combustion efficiency, CO2 capture, and heat recovery for power generation. Archon has its own research and development facilities in Calgary and a full time staff of researchers who also perform fluids and gas analysis for the current WHITESANDS project. We operate the only three dimensional combustion reactors in the world capable of evaluating the combustion properties of any oil. Archon is building a portfolio of technologies to provide an integrated solution designed to maximize the overall efficiency and economics of a THAI™/CAPRI™ project. Archon is also the vehicle for licensing any of the technology or intellectual property to third parties.

Canadian Business Unit

The Canadian Business Unit produced 5,413 boepd in the third quarter of 2007, a 32 percent increase from the 4,094 boepd produced in the second quarter of 2007 and more than double the 2,519 boepd produced in the third quarter of 2006. Canadian Business Unit production averaged 7,885 boepd in the first week of November. The majority of this increase is new Bakken light oil that continues to be brought on-stream. The Canadian Business Unit drilled 26 (23.5 net) oil wells, two (1.3 net) gas wells and three (3.0 net) dry and abandoned ("D&A") wells during the quarter with the majority of the activity focused on the Bakken resource play in southeast Saskatchewan.

Bakken Light Oil Resource Play

The Canadian Business Unit continues to build on our success in the large Bakken light oil resource play, with five rigs drilling 100% working interest wells and another two rigs drilling 50% working interest non-operated wells. This drilling activity has allowed us to further develop our key areas of proven production and expand the boundaries of the play into new areas. During the third quarter, Petrobank drilled 28 (25.5 net) Bakken wells, bringing the total for the first three quarters of 2007 to 52 (47.3 net) wells. We now anticipate that by year-end we will have drilled approximately 62, 100% working interest, wells and an additional 12 (5.5 net) non-operated wells for a total of 74 (67.5 net) Bakken wells in 2007.

In anticipation of the October 1, 2007 Saskatchewan Crown land sale, Petrobank drilled a number of wells to assess the geological limits of the productive Bakken fairway. During the course of this program, the Company drilled three D&A wells that allowed us to significantly reduce our capital exposure at the sale. While Petrobank has defined the economic play limit at the southern extent of the Bakken fairway, we continue to push the boundaries of the play and acquire new lands within the productive fairway, while minimizing our exposure to marginal lands.

Of our 58 (55.5 net) successful Bakken wells drilled in the first ten months of 2007, 52 (49.5 net) are currently on-stream. Through the third quarter we have ramped up completion activities to keep pace with our drilling activity and at any point in time we typically have approximately six wells in various stages of completion. Total Bakken oil production over the quarter increased from approximately 1,700 bopd in late June to approximately 4,400 bopd in late September. Current Bakken oil production is now approximately 5,650 bopd, bringing the Canadian Business Unit's total production to 7,885 boepd.

To realize the full value of our Bakken oil resource, Petrobank plans to capture the additional upside from the associated liquids-rich gas. During September and October we constructed our first oil battery and gas plant facility at Midale. The oil battery came online in October and will be tied-in to the Enbridge pipeline system by the middle of November. The gas plant is currently tied-in directly to the Transgas pipeline system, and is expected to be operational by the middle of November. This facility will allow us to centrally process a large portion of our current production at a significant cost savings and will also allow us to capture the associated gas and liquids. Most of our remaining 2007 drilling program will be focused in this high productivity, centrally located area. As our well count in nearby lands reaches critical mass, those areas will also be pipeline-connected to this facility. Additional facilities will be required in the future to address our extensive inventory of drilling locations in several concentrated areas across our extensive land position.

The Bakken Formation

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 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 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. Our horizontal drilling and fracture stimulation techniques allow us to avoid fracturing out of the Bakken zone, thereby minimizing associated high water production common in earlier horizontal wells, and consequently significantly improving oil productivity. Ultimately we expect this to lead to substantially improved recovery rates. Several of our wells, that commenced production in December of 2006, reached the end of their 37,740 barrel royalty holiday in less than 11 months and one well has now produced in excess of 50,000 barrels. The royalty holiday recovery level represents more than 50% of the Sproule proven reserves initially attributed to these wells. This was not forecast by Sproule to be achieved until December 2010, highlighting the strong performance we are achieving from our fracture stimulations.

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 well will recover in excess of 150,000 barrels. We expect our next reserve evaluation to more appropriately reflect our actual performance to-date. We also anticipate material reserve additions related to solution gas conservation and liquids recovery through our new gas facility.

The majority of our Bakken land base is expected to yield four horizontal wells per section. Currently, we estimate our drilling inventory at 532 (497 net) locations. This light oil resource play is expected to be the Canadian Business Unit's primary focus area for years to come. Our highly effective drilling and stimulation program, along with the expansion of our significant land base, has strategically positioned Petrobank to be a key Bakken light oil player. In 2008, we plan to drill at least 80 additional Bakken horizontal wells.

Additional Canadian Business Unit Focus Areas

In addition to our Bakken light oil asset, we have a long-term legacy shallow gas asset at Jumpbush with an inventory of over 175 low-risk development drilling locations. We continue to discuss 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 northwestern Alberta where we are targeting multi-zone oil and gas prospects with at least two exploration wells in 2007. The first well was completed and cased as a light oil well in the Beaver Hill Lake sand play. Although production from this initial well is not 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 are currently drilling our second exploration well in this area. Further exploration and development wells will be drilled in northwestern Alberta through the balance of 2007 and into 2008, depending on weather and ground conditions. Petrobank continues to leverage our large undeveloped land base into exciting new opportunities.

Latin American Business Unit (Petrominerales Ltd. - (TSX:PMG)

Petrobank's Latin American Business Unit, operated through our 76.6 percent owned subsidiary, Petrominerales Ltd. ("Petrominerales"), produced 4,522 bopd in the third quarter of 2007 compared to 2,848 bopd in the second quarter of 2007. The increase is mainly due to the Corcel-1 discovery well that was placed on an extended six-month production test, initially at 4,000 bopd increasing to current rates of over 4,500 bopd. Production averaged 8,130 bopd in early November 2007 excluding test results from the Corcel-2 well. Significant further production additions are expected as a result of the recently drilled Corcel-2 well and our ongoing drilling programs at Corcel and Orito.



Petrominerales drilled one well at Orito in the third quarter and completed a further two wells. We also recently cased the Conga-1 exploration well on the Las Aguilas Block adjacent to Orito as a potential oil well. The Orito program for the remainder of the year includes drilling two more wells, completing four wells, and performing workovers and pump changes on three additional wells. We originally planned to have two drilling rigs working in the Putumayo Basin for most of 2007, but, based on our Corcel discovery, one of these rigs has remained on the Corcel Block to drill additional delineation and exploration wells and to assist with our Llanos Basin dry season exploration drilling program in early 2008. This re-configures our Orito development drilling program to a single rig schedule, which can be expanded based on equipment availability. In addition to our ongoing development drilling program, a 3D seismic program is planned for Orito in 2008 which will help delineate the southern extension and eastern flanks of the main Orito field. This is expected to add further to our large inventory of development drilling locations.


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 we plan to expand the waterflood. In addition, we have an inventory of approximately 31 infill locations and 25 fracture stimulation candidates.


Petrominerales has completed drilling all five wells planned for the 2007 exploration program. Four of these wells were drilled in the Llanos Basin, two of which were completed as new pool discoveries (Joropo and Corcel). The final 2007 exploration well, Conga-1, has now been drilled and will be completed as a potential oil well on the Las Aguilas Block adjacent to Orito, in the Putumayo Basin. 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. Currently we have an additional 18 leads and prospects on these lands. In 2008, we plan to drill eight exploration wells focused primarily in the Llanos Basin. We continue to acquire additional 2D and 3D seismic, which should result in an expanded exploration drilling programs beyond 2008.

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 Tertiary Mirador and Cretaceous Guadalupe formations were primarily oil bearing with total potential net pay of approximately 140 feet of high quality sand. The Guadalupe and Mirador intervals were completed and commingled for an initial six-day test that was conducted at rates increasing to 2,500 bopd. A six-month extended production test then commenced on September 7, 2007 at initial rates of 4,000 bopd. We have been slowly ramping up production rates and the well is now producing in excess of 4,500 bopd.

We recently completed drilling our first Corcel delineation well, Corcel-2. The well spudded on August 25, 2007 and reached a total depth of 12,140 feet on October 17, 2007. Logs indicate total potential net pay of approximately 125 feet of high quality reservoir sands in the Mirador and Guadalupe formations. We have initially completed four intervals, with a total of 45 feet of sand, in the Upper and Lower Mirador formations of the Corcel-2 well. These intervals were tested over a 24-hour period at rates increasing to 3,100 bopd on natural flow. The well is now shut in for pressure build up and will then be placed on an extended production test with an electric submersible pump. The pump will be capable of handling up to 6,000 barrels of total fluid production per day.

This initial Mirador completion is being executed with the drilling rig. The rig will then move to drill the third well from the same platform, Corcel-3, to further delineate our first Corcel discovery. After drilling Corcel-3 we expect to use the drilling rig to drill at least one of our Llanos Basin dry-season-only exploration wells, after which we plan to resume our Corcel drilling program starting with the Corcel-C exploration well. The rig is then expected to remain at Corcel for the rest of 2008 to continue drilling 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 the location which will accommodate year round production. Production is currently being processed through temporary facilities and trucked. We are designing permanent production facilities and a pipeline and applying for required governmental approvals.

The ultimate size of the Corcel discovery will be defined through our long-term production testing and delineation drilling program. Petrominerales has identified five additional Corcel prospects, and at least four contingent delineation wells. These locations have been defined from our 47 square kilometre 3D seismic survey, which covers approximately 15 percent of the 79,815-acre Block. A 2008 3D seismic program is planned for our 26,341-acre Guatiquia Block, which adjoins the Corcel Block to the south. At that time we also plan to further expand the 3D seismic coverage over our Corcel Block.

Joropo Block

Our Ojo de Tigre-2 well on the Joropo Block in the Llanos Basin was completed and initial production testing commenced, but was suspended with the onset of the rainy season earlier in 2007. 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. A second Joropo exploration well is planned for the first quarter of 2008. Successful development of the Joropo Block will require upgraded surface access to 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 acquired two adjoining Blocks, Jabali and Jaguar, totalling an additional 69,122 acres.

Las Aguilas Block

Our Conga-1 exploration well was recently drilled, logged and cased as a potential oil well on our Las Aguilas Block, offsetting the Orito field in the Putumayo Basin. Completion and testing operations will commence later in November.

2008 Exploration Program

We plan to drill eight exploration wells during our 2008 exploration program, which will be focused once again on the Llanos Basin, where we plan to test seven new prospects. Six of these wells are scheduled to be drilled during the upcoming dry season (December 2007 through April 2008) with two wells to be drilled at Mapache, one at Joropo, one at Castor, one at Casanare Este, and one at Casimena. Our next Corcel exploration well is expected to be drilled in the second quarter of 2008 and our second Las Aguilas exploration well, in the Putumayo Basin, is expected to be drilled in the second half of 2008. We also plan to shoot additional 3D seismic at Joropo and Corcel, to further delineate prospects on these Blocks. This program will also include seismic on our adjoining blocks to satisfy our first phase work commitments.

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 2008, we plan to shoot 576 kilometres of reconnaissance 2D seismic on our Chiguiro Oeste and Rio Ariari Blocks and a combination of 2D and 3D seismic over our Chiguiro Este Block where we are targeting large heavy oil accumulations.

In addition, Petrominerales intends to participate in the upcoming Heavy Oil Bid Round, expected to be announced early next 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 to efficiently develop Colombian heavy oil opportunities in an environmentally and socially responsible fashion.

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 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, operated by Petrobank's 76.6% owned TSX-listed subsidiary, Petrominerales Ltd. (trading symbol: PMG), is a Latin American-based exploration and production company producing oil from three blocks in Colombia and has contracts on 13 exploration blocks covering a total of 1.5 million acres in the Llanos and Putumayo Basins. WHITESANDS Insitu Ltd., Petrobank's wholly-owned subsidiary, owns 70,720 net 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™ is a registered trademark of Archon Technologies Ltd., a wholly-owned subsidiary of Petrobank Energy and Resources Ltd.

Forward-Looking Statements

Certain information provided in this news release constitutes forward-looking statements. The words "anticipate", "expect", "project", "estimate", "forecast" and similar expressions are intended to identify such forward-looking statements. Although Petrobank believes that these statements are based on information and assumptions which are current, reasonable and complete, these statements are necessarily subject to a variety of risks and uncertainties. You can find a discussion of those risks and uncertainties in our Canadian securities filings. While Petrobank makes these forward-looking statements in good faith, should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. 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
    Petrobank Energy and Resources Ltd.
    Chris J. Bloomer
    Vice-President Heavy Oil
    (403) 750-4400
    Petrobank Energy and Resources Ltd.
    Corey C. Ruttan
    Vice-President Finance and Chief Financial Officer
    (403) 750-4400
    (403) 266-5794 (FAX)