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

Petrobank Energy and Resources Ltd.

August 11, 2006 03:38 ET

Petrobank Announces Second Quarter Results and Key Milestones at Whitesands

CALGARY, ALBERTA--(CCNMatthews - Aug. 11, 2006) - Petrobank Energy and Resources Ltd. (TSX:PBG)(OSLO:PBG) Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") is pleased to announce second quarter financial and operating results. The Company's second 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 second quarter results reflect the impact of significant increases in production generated from the Company's 2005/2006 capital program in Canada and our recent drilling successes in Colombia and are highlighted as follows:

- Colombian oil production averaged 2,612 bpd in the second quarter of 2006, a 155 percent increase over the comparative 2005 period.

- Canadian production averaged 3,017 boepd, a 41 percent increase over the second quarter of 2005.

- Funds flow from operations increased 316 percent to $19.0 million.

- Net income increased by 157 percent to $12.1 million.

- Operating netbacks improved 23 percent and 38 percent in Canada and Colombia, respectively.

- In June 2006, completed the initial public offering and TSX listing of Petrominerales Ltd. ("Petrominerales") (TSX:PMG), Petrobank's Latin American Business Unit, raising gross proceeds of $60 million for Petrominerales and $8.6 million for Petrobank. Petrobank continues to retain an 80.7% interest in Petrominerales.

- 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.

- Achieved key milestones at our WHITESANDS - THAI™ project by completing the Pre-Ignition Heating Cycle ("PIHC"), commencing air injection and initiating in-situ combustion.

FINANCIAL & OPERATING HIGHLIGHTS



Three months ended Six months ended
June 30, % June 30, %
2006 2005 change 2006 2005 change
-----------------------------------------------------------------------
Financial
($000s, except where
noted)
Oil and natural gas
revenue 27,267 13,206 106 48,860 24,588 99
Funds flow from
operations (1) 19,032 4,575 316 30,580 7,971 284
Per share
-- basic ($) 0.28 0.08 250 0.46 0.14 229
-- diluted ($) 0.27 0.08 238 0.45 0.14 221
Net income 12,075 4,702 157 15,317 4,454 244
Per share
-- basic ($) 0.18 0.08 125 0.23 0.08 188
-- diluted ($) 0.17 0.08 113 0.22 0.08 175
Capital expenditures 32,935 16,842 96 100,452 27,622 264
Total assets 375,367 190,366 97 375,367 190,366 97
Net debt (2) 26,743 34,388 (22) 26,743 34,388 (22)
Common shares
outstanding, end of
period (000s)
Basic 67,258 58,392 15 67,258 58,392 15
Diluted 71,498 63,828 12 71,498 63,828 12
Operations (3)
Canadian operating
netback ($/boe
except where noted)
Natural gas revenue
($/mcf) (4) 5.84 6.60 (12) 6.54 6.36 3
Oil and NGL revenue
($/bbl) 68.42 63.60 8 61.08 55.04 11
Oil and natural gas
revenue (4) 43.86 42.63 3 44.75 40.59 10
Royalties 6.13 9.35 (34) 7.31 8.52 (14)
Production expenses 6.46 7.12 (9) 5.62 6.95 (19)
Transportation
expenses 0.43 1.13 (62) 0.44 1.27 (65)
-----------------------------------------------------------------------
Operating netback 30.84 25.03 23 31.38 23.85 32
Colombian operating
netback ($/bbl)
Oil revenue 64.05 52.34 22 62.33 50.70 23
Royalties 5.17 4.19 23 5.02 4.05 24
Production expenses 6.26 10.09 (38) 7.41 9.26 (20)
-----------------------------------------------------------------------
Operating netback 52.62 38.06 38 49.90 37.39 33
Average daily
production
Canada -- natural
gas (mcf) 13,322 11,245 18 14,634 10,459 40
Canada -- oil and
NGL (bbls) 797 273 192 824 295 179
-----------------------------------------------------------------------
Total Canada (boe) 3,017 2,147 41 3,263 2,038 60
Colombia -- oil
(bbls) 2,612 1,024 155 1,988 1,048 90
-----------------------------------------------------------------------
Total Company (boe) 5,629 3,171 78 5,251 3,086 70
-----------------------------------------------------------------------
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(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.

(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

During the second quarter, we completed the PIHC on the first horizontal and vertical well pair (P2) at the WHITESANDS project and commenced air injection on July 20, 2006.

During the PIHC phase, communication between the vertical injection well and the horizontal production well was established by injecting steam in the vertical well located at the toe of the horizontal well. This process developed an expanding hot mobile bitumen zone, and established fluid flow between the injection well and the horizontal production well. During this phase, steam was also circulated in the horizontal production well to aid in the PIHC and to enable high total fluid production rates from the horizontal well. During these operations, the horizontal production well achieved total production rates of up to 1,000 barrels of fluid per day, consisting primarily of condensed steam and formation water and up to a 15% oil cut of 11 degree API bitumen. By establishing communication between the two wells and introducing a large amount of heat energy into the reservoir to create the mobilized bitumen zone around the vertical well, conditions were determined to be appropriate for the initiation of air injection and to cause in-situ combustion.

On July 20, 2006, we started air injection at the center vertical well. This operation commenced the in-situ combustion reaction and initiated the transition to the THAI™ production phase of our operation. Since that time, we have been increasing air injection rates and achieved a significant milestone by generating sustained temperatures of over 600 degrees Celsius (and up to 700 degrees Celsius) within an expanding high temperature combustion zone in the reservoir. Initial production from the horizontal well will be dominated by the recovery of condensed steam from the PIHC process. A period of time is required for the complete transition from the PIHC phase into production via the THAI™ process. Produced fluids and gases are being continuously monitored along with reservoir temperatures and pressures allowing us to manage air injection rates to optimize the combustion zone, production rates, and surface facilities. As we gather and evaluate stabilized production and operational information from the WHITESANDS site, we will provide periodic updates to our shareholders, while protecting the confidential nature of the key operating specifics of our patented THAI™ process.

We are now preparing to begin the PIHC phase on the second of the three well pairs and expect to have all three well pairs on combustion by year end.
During the second quarter we reported that the estimated gross bitumen-in-place on a portion of the 60 sections of oil sands leases owned by our 84% 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. At the most recent Crown land sale we were successful in acquiring two additional sections of oil sands leases bringing our total oil sands acreage to 62 sections (39,680 acres).

We believe there is considerable upside to the recoverable resource estimates as the McDaniel report included only 13 sections of our lands, those with at least one drillhole and excluded a number of sections with McMurray channel indicated by our 3-D seismic and/or areas on trend with known McMurray channel. As a result, WHITESANDS is planning a late-summer drilling program of up to nine wells in easily accessed areas, to be followed up in early 2007 with a similar sized program in winter access areas. This additional drilling is expected to delineate significant new recoverable bitumen resources. Subject to the successful demonstration of the THAI™ recovery process at WHITESANDS, 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.

The THAI™ 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. 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 (Steam Assisted Gravity Drainage). These 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% owned subsidiary, Petrominerales Ltd. (TSX: PMG), is evaluating two large heavy oil Technical Evaluation Areas in Colombia covering 1.1 million acres for the potential application of THAI™.

Canadian Business Unit

Canadian conventional production averaged 3,017 boepd in the second quarter of 2006, compared to 2,147 boepd in the second quarter of 2005 and 3,513 boepd in the first quarter of 2006. Field activity during the first half of the year has been limited, due to weather conditions, regulatory approvals and availability of equipment. Through the first half of 2006, only three new oil wells and one gas well were added to our production base. We are now implementing significant second half development and exploration programs. Over the past two months we have advanced a number of wells to various stages of completion or tie-in, the majority of which will be brought on production by the end of August. We also have a large inventory of locations to be drilled in the last half of 2006 and into 2007 at Red Willow, Jumpbush, Milo, and our new emerging light oil play in southeast Saskatchewan.

At Red Willow, we have drilled seven (7.0 net) wells to date this year, two wells in the first quarter, one well in the second quarter and, most recently, four wells in the third quarter, resulting in four gas wells and one oil well. Currently three of these gas wells are waiting for tie-in and we plan to drill an additional five locations at Red Willow through the end of 2006.

Our Jumpbush shallow gas program has focused entirely on our off-reserve acreage to-date in 2006 due to regulatory delays on the Siksika First Nation. Despite an extended period of wet spring weather we were able to drill 13 (11.6 net) wells on our off-reserve program during the second quarter and we have now completed drilling all 31 (23.9 net) wells in our initial 2006 off-reserve program. Currently both completion and pipeline crews are working to connect these gas wells to our Petrobank-operated Jumpbush gas plant and all 31 gas wells are expected to be on production by the end of August. A second off-reserve program of up to 23 (23 net) additional wells is expected to commence late in the third quarter.

South of Jumpbush, at Milo we have now drilled two wells both of which are cased for shallow gas and are awaiting tie-in. We plan to drill at least four follow-up locations. We have accumulated a total of 14,400 (12,600 net) acres of off-reserve land with an additional 5,760 acres under option pursuant to farmin arrangements. This land base is a continuation of our Jumpbush legacy resource asset.

Our 50 (35 net) well drilling program on the Siksika Nation at Jumpbush is currently delayed in the Nation's regulatory approval process. This program is part of our inventory of approximately 200 development drilling locations which we have identified on our Siksika acreage. The capital designated for this on-reserve program has been re-allocated to our expanding Bakken light oil program in southeast Saskatchewan. Petrobank will proceed with the on-reserve program at Jumpbush after regulatory approvals are complete.

In addition to our ongoing development programs in Alberta, we are accelerating our activity in southeast Saskatchewan targeting the Bakken light oil formation. We currently have one rig drilling in the area and will have a second rig working the area by the end of August. The first phase of drilling incorporates an 18-well program and we have developed an initial inventory of 25 follow-up Bakken locations. Petrobank has an extensive land base in southeastern Saskatchewan including fee-simple lands where we own the mineral rights in perpetuity. This has allowed Petrobank to monitor and participate in the evolution of the Bakken light oil play with little capital exposure to-date. Concurrently, we have been actively acquiring additional lands within the Bakken fairway to compliment our existing position and now have 138,000 gross acres (118,600 net acres) in areas with Bakken potential.

The third quarter has been our busiest quarter to-date in 2006. As of the date of this report, we have already drilled 20 (16.6 net) wells resulting in 19 (15.6 net) gas wells. Currently, we have a total of 37 (29.9 net) gas wells at Jumpbush, Milo, Red Willow and Badger awaiting tie-in with approximately eight mmcfpd of behind pipe gas potential. Most of these wells will connect to Petrobank's facilities with existing capacity to handle these production additions. We are also excited about our extensive southeast Saskatchewan land base, highly prospective for Bakken light oil, where we will soon have two rigs drilling up our initial inventory of 43 locations.

Latin American Business Unit - Petrominerales Ltd.

Petrobank's subsidiary, Petrominerales Ltd., completed its initial public offering on June 29, 2006 and is now listed for trading on the Toronto Stock Exchange under the symbol PMG. The transaction resulted in gross proceeds of $60 million to Petrominerales pursuant to a treasury offering and $8.6 million to Petrobank through a secondary sale of shares. Petrobank has retained an 80.7 percent ownership interest in Petrominerales.

Second quarter production averaged 2,612 bpd compared to 1,356 bpd in the first quarter of 2006 and 1,024 bpd in the second quarter of 2005. These significant increases are mainly due to the success of the Orito 117 and 118 completions at the end of the first quarter of 2006. These wells continue to produce at combined rates of approximately 1,960 bpd (1,548 bpd working interest before 8 percent royalty).

During the quarter, we commenced our development drilling program in the Orito field, spudding our first development well of the year at Orito-119. We also re-entered two other wells, Orito-113 and Orito-115, deepening them for potential productive sands in the Caballos A zone, as well as preparing them for future fracture stimulation in the Caballos B, C, and D sands.

In June of this year we re-entered the Orito-113 well in an attempt to recover lost production due to near wellbore damage and to deepen the well down to the Upper A sand. During our pre-stimulation operations, pressure communication with the annulus was observed, and the subsequent fracture stimulation was postponed. A similar result occurred while cementing the recently drilled Orito-119 well, but a liner top packer was installed and annular isolation was achieved, allowing for the successful fracture stimulation of the Caballos zone in that well. Based on this recent success, the same operation is being planned for Orito-113, which should take place during September with the arrival of a second workover rig. We will also fracture stimulate the Orito-115 well at that time. During these recompletion operations, the wells have either been off-line or producing at less than their potential and we look forward to bringing them back on-stream in the near future.

The first of two drilling rigs under long-term contract commenced operations for Petrominerales in June 2006, drilling the Orito-119 location, which is a re-drill of an old non-producing well within the original field boundaries. Orito-119 reached total depth in early July 2006. The well has been completed and fracture stimulated in the upper Caballos sands. The well is now being brought on-line and we expect to have stable production rates in the near future. Ultimately we plan to install an electrical submersible pump to optimize the productive capability of the well.

Following the Orito-119 well, the rig commenced the sidetrack of the Orito-116 well and should drill through the targeted Caballos formation within the next week. The original Orito-116 well was our first confirmation of the southwest extension to the field beyond the existing field boundaries, initially testing at rates of more than 1,000 bpd. Unfortunately, the well experienced a casing collapse and had to be abandoned. The ongoing delineation of this southwest extension to the field was further confirmed in late 2005 by the drilling of the Orito-117 and 118 wells from the same surface drilling pad. These wells have been the primary contributors to our production growth to-date in 2006. After drilling the Orito-116 sidetrack, the rig will drill two additional locations off this pad, all of which will be targeting this southwest extension of the field.

A second drilling rig, contracted for 16 months, is scheduled to arrive in Orito in late September of 2006, with its first well now scheduled to spud in early October. This rig will also be used to drill our Llanos Basin exploration wells during the first and second quarters of 2007, and will then return to Orito to drill additional development wells. Securing these rigs provides the Company with guaranteed access to the equipment required to implement our exploration program during the January-April dry season in the Llanos Basin and to facilitate an acceleration of the Company's Orito development drilling program into 2008. We expect to drill a total of eight wells in Orito in 2006 and have planned for up to 11 wells in Orito in 2007 in conjunction with five exploration wells in the Llanos and Putumayo basins.

At Neiva, we have commenced our initial phase of fracture stimulations involving five test wells in the Honda and Doima-Chicoral reservoirs. With success, this program may be expanded to more than 50 locations at Neiva.

Petrominerales has been actively evaluating our extensive inventory of exploration acreage focused primarily in Colombia's Llanos Basin. To-date, we have shot 250 square kilometers of 3-D seismic over our Las Aguilas, Corcel, Casanare Este and Casimena exploration blocks. We have identified a total of 16 leads and prospects over our five exploration blocks and we are planning an initial five-well exploration drilling program commencing at the end of 2006. On the Chicago Technical Evaluation Agreement ("TEA"), Petrominerales has submitted two exploration proposals (Mapache and Castor) covering a significant portion of the original TEA. The Mapache Block covers 107,705 acres and our proposal includes a 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 covers 110,265 acres and our proposal includes the acquisition of an initial 30 square kilometer 3-D seismic survey. Upon acceptance of these most recent exploration proposals, Petrominerales' exploration land base will total 2.3 million acres in seven exploration blocks and four TEAs.

Petrominerales has started the necessary work to evaluate the heavy oil potential of two of these TEAs covering 1.1 million acres in the southern Llanos Basin, where there is evidence of an extensive heavy oil belt. Petrominerales has a license to use Petrobank's THAI™ technology and is evaluating the technology's applicability to these Llanos Basin heavy oil deposits.

Outlook

We are now building significant momentum in our drilling, completion and exploration programs both in Canada and in Colombia. With the completion of our Petrominerales initial public offering and our new $120 million Canadian credit facility, we have significantly strengthened our balance sheet. In addition, we have secured the necessary drilling equipment to execute on our long-term capital programs, which together have allowed us to accelerate operations since the end of the second quarter. These capital programs include an increased emphasis on the Bakken light oil resource play in Canada and our extensive inventory of development and exploration opportunities in Colombia. Our Heavy Oil business unit continues to expand the estimated recoverable resource on a portion of our 62 sections of oil sands lands. In addition, we have passed a number of key milestones, most notably the initiation of in-situ combustion at our WHITESANDS project, the first field scale application of our patented THAI™ process. This project marks a potential step change in the global recovery of heavy oil resources. We are excited about the opportunities for growth that each of our business units offer and look forward to updating our shareholders on our continuing progress over the coming months.

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 81% 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 2.3 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