Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd.

November 12, 2008 21:30 ET

Petrobank Announces Another Record Quarter and Significant Production Increases

CALGARY, ALBERTA--(Marketwire - Nov. 12, 2008) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is pleased to announce record third quarter 2008 financial and operating results driven by strong production increases and superior operating netbacks.


(all comparisons are third quarter 2008 compared to the third quarter of 2007)

- Production more than tripled to 30,850 barrels of oil equivalent per day ("boepd").

- Production has now increased further to over 40,000 boepd.

- Canadian Business Unit ("CBU") production increased by 239% to 18,365 boepd and averaged 21,660 boepd in October.

- Latin American Business Unit ("LABU") production increased by 176% to 12,485 barrels of oil per day ("bopd") and has subsequently increased to 19,590 bopd.

- Funds flow from operations increased by 412% to $216.7 million ($2.36 per diluted share).

- Net income increased by 487% to $123.2 million ($1.35 per diluted share).

- Strong operating netbacks of $84.95 per boe in the CBU and $90.44 per barrel in the LABU.

- Drilled 61.6 net Bakken wells during the quarter, on pace to exceed our 2008 goal to drill 154 net Bakken wells.

- Repurchased 298,400 common shares.


The following table provides a summary of Petrobank's financial and operating results for the three and nine month periods ended September 30, 2008 and 2007. 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, %
2008 2007 change 2008 2007 change
($000s, except where
Oil and natural gas
revenue 306,913 61,567 399 722,308 127,897 465
Funds flow from
operations (1) 216,709 42,316 412 518,120 82,131 531
Per share - basic ($) 2.62 0.55 376 6.32 1.09 480
- diluted ($) 2.36 0.48 392 5.65 1.01 459
Net income 123,226 20,978 487 216,399 41,281 424
Per share - basic ($) 1.49 0.27 452 2.64 0.55 380
- diluted ($) 1.35 0.25 440 2.39 0.53 351
EBITDA (1) 235,377 44,168 433 544,724 85,830 535
Capital expenditures 257,305 135,417 90 629,931 373,736 69
Total assets 2,044,996 930,855 120 2,044,996 930,855 120
Net debt (1) 230,585 37,762 511 230,585 37,762 511
Common shares
outstanding, end
of period (000s)
Basic 82,474 76,897 7 82,474 76,897 7
Diluted (2) 98,173 90,083 9 98,173 90,083 9
CBU operating netback
($/boe except where
noted) (1) (3)
Oil and NGL revenue
($/bbl) 115.11 76.56 50 109.65 71.00 54
Natural gas revenue
($/mcf) 7.94 5.35 48 8.47 6.51 30
Oil and natural gas
revenue 106.51 62.86 69 100.98 56.87 78
Royalties 12.72 4.18 204 10.68 4.71 127
Production expenses 8.84 8.44 5 8.99 8.55 5
Operating netback (4) 84.95 50.24 69 81.31 43.61 86
LABU operating netback
($/bbl) (1)
Oil revenue 110.53 72.74 52 104.63 66.84 57
Royalties 11.71 6.32 85 10.52 5.60 88
Production expenses 8.38 7.42 13 9.76 7.40 32
Operating netback (4) 90.44 59.00 53 84.35 53.84 57
Average daily production
CBU - oil and NGL
(bbls) 16,024 3,745 328 13,868 2,531 448
CBU - natural gas
(mcf) 14,047 10,006 40 14,381 12,053 19
Total CBU (boe) 18,365 5,413 239 16,265 4,540 258
LABU - oil (bbls) 12,485 4,522 176 9,497 3,146 202
Total Company
conventional (boe) 30,850 9,935 211 25,762 7,686 235
(1) Non-GAAP measure. See "Non-GAAP Measures" section within the MD&A.
(2) Assumes 8.8 million common shares will be issued upon conversion of the
Company's convertible debentures.
(3) Six mcf of natural gas is equivalent to one barrel of oil equivalent
("boe"). Heavy Oil Business Unit ("HBU") bitumen volumes are excluded as
Whitesands operations are considered to be in the pre-operating stage
and all expenses, net of revenues, are capitalized.
(4) Excludes hedging activities.



- Record third quarter production of 18,365 boepd, a 239% increase from the third quarter of 2007.

- Production has increased further to average 21,660 boepd in October.

- Drilled 61.6 net Bakken wells in the third quarter.

- Completed construction of the Creelman oil battery and gathering system.

The CBU achieved record production levels during the third quarter. We drilled 73 (61.6 net) Bakken wells during the quarter and put 66 (54.0 net) new wells on production. The production during the quarter averaged 18,365 boepd which represents an 11% increase over the second quarter and a 239% increase over the third quarter of 2007. We continue to add incremental volumes and during October production averaged 21,660 boepd. Approximately 85% of our CBU production is now Bakken light oil which delivers a high operating netback due to premium pricing, relatively low royalties, and low operating costs. The average netback over the quarter for the CBU was $84.95 per boe, despite declining commodity prices.

Our level of activity in southeast Saskatchewan on the Bakken play will meet or exceed our 2008 expectations for both drilling and new facilities. Petrobank utilized 10 drilling rigs at times during the third quarter and successfully drilled 61.6 net wells, resulting in a combined total of 136.4 net wells drilled in the first nine months of 2008. We are on-track to exceed our goal of drilling 154 net wells this year. Currently we have seven rigs working in southeast Saskatchewan and the Company plans to move to six rigs starting in December.

New facilities allow for the conservation of natural gas and natural gas liquids from the Bakken oil production and provide the additional benefit of lowering operating costs with the efficiencies created through this new infrastructure. The Creelman battery and gathering system, completed in September 2008, resulted in the immediate conservation of 800 mcf per day of gas and associated liquids. The new Freestone battery, gas conservation facility and 70 kilometre gas pipeline will commence operations in early December, and we anticipate this will result in the further addition of approximately four mmcf per day of natural gas and associated natural gas liquids.

Due to a combination of low gas prices, the implementation of the new Alberta royalty regime, and a recent unsuccessful drill result, Petrobank is re-evaluating our plans to build a 25 mmcf per day gas plant in the Cornwall area. A variety of less expensive pipeline and facility alternatives are being examined to bring the gas and liquids from our first well to market. We still expect initial production from this area to commence by April 2009.

As part of our efforts to build our inventory of future drilling locations, Petrobank has acquired additional land in areas that are prospective for Bakken light oil and we will be drilling our first wells in both the Montney and Horn River Shale Basin play areas of northeast British Columbia in the next two months. These geological plays cater to Petrobank's technical strengths in horizontal drilling and multi-stage hydraulic fracture stimulations that have been successfully employed in the Bakken play. We have a 100% working interest in 14 sections of prospective Montney acreage and we will spud our first well here in November. An independent resource assessment of this acreage indicates potential best estimate contingent recoverable resource of 148 Bcf. We plan to vertically drill and evaluate the Montney formation prior to continuing with the horizontal portion of the well. Some of Petrobank's 65 sections (43,428 acres) of 100% working interest lands in the Horn River Shale Basin north of Fort Nelson, British Columbia are close to all-season access and we will also spud our first evaluation well on this play during the fourth quarter. Other operators in these areas continue to have strong initial results and we are eager to add new drilling locations to our inventory with successful tests in these promising resource plays.

Solid production growth and strong cash flow from operations allows us to maintain an active program and strengthen our balance sheet while also being cognizant of the recent sharp decline in commodity prices. Our primary focus and key efforts through the balance of 2008 and into 2009 will be to maintain an active program that continues to increase oil reserves and production from the Bakken. We will also be positioning for future growth by strategically investing in opportunities that add quality drilling locations to our significant prospect inventory that is focused on large oil and natural gas resource plays. This high quality inventory positions the CBU to deliver significant future production and reserves growth when commodity prices improve.


- Successfully began production from the world's first THAI™/CAPRI™ well which incorporates our revised downhole completion design, effectively eliminating sand production.

- After a further extended review period we now expect regulatory approval for our Whitesands three well expansion by the end of November.

- Acquired 35 kilometres of 2D seismic at Sutton Creek, Saskatchewan and we expect to have an initial evaluation of the data by year end.

Whitesands Project

During the third quarter we began production of our P-3B THAI™ /CAPRI™ well with encouraging early results. Inter-well communication was rapidly established and combustion temperatures reached 500 degrees Celsius. As previously disclosed, Petrobank drilled P-3B late in the second quarter of 2008 and completion operations commenced on the well in late July. This well has been designed to demonstrate the additional upgrading potential of our patented CAPRI™ process which places an active catalyst bed between two concentric slotted liners. In laboratory tests, CAPRI™ has achieved an upgrading effect of seven degrees API in addition to the upgrading effect resulting from the THAI™ process. The P-3B well also incorporates our narrower slot design, intended to significantly reduce sand production from the McMurray sandstone reservoir typically encountered at Whitesands.

In September, P-1 and P-2 on-stream factors improved. Although it is not our intention to drill any further wells incorporating the completion initially used in P-1 and P-2, with the modification of de-sand vessel internals we have also been able to continuously improve sand management from the P-1 and P-2 wells.

In September and October, a number of planned shutdowns were scheduled. During the same period unplanned shutdowns occurred which led to additional downtime. The planned shutdowns included the replacement of the thermocouple string in P-3B to add additional thermocouple sensors, as well as the shutdown of the A-3 air injection well to replace the well's packer assembly pursuant to regulatory requirements. Shutdowns were also planned to tie-in the new wellhead gas separation and tank separation system on P-3B. Unplanned shutdowns included an Alberta grid electric power failure and the shutdown of the compressors used for air injection due to a failure in the compressor's cooling system. These resulted in wells being shut in and restarted, causing non-rateable production. The P-1 and P-2 wells were brought back on-line early in November and the P-3B well will be brought back on-line following the packer replacement on A-3 which is expected to be completed by the middle of November. We do not plan any major plant shut downs until we tie-in our three well expansion.

Since the commencement of air injection and oil production in August on P-3B, the well has exhibited negligible sand production, in contrast to what was encountered in the initial three wells. First produced fluids consisted of oil and water emulsions from the steam preheat as well as residual drilling mud, which diminished as the well cleaned up. During the initial period we achieved oil production rates up to 300 barrels per day on low air injection rates, with oil cuts of 40 to 50%. P-3B has been operating at a well bore temperature below the optimum range for the catalyst and therefore it is still too early to assess the effectiveness of the catalyst. However, the produced oil has been upgraded to 11.5 degrees API due to the thermal cracking effects of the THAI™ process. The operating plan is to increase well bore temperatures for optimum catalyst efficiency and continue to analyze produced oil quality to assess the catalyst effectiveness. Produced gas analysis from P-3B is consistent with the P-1 and P-2 wells and indicates high temperature combustion with the associated production of free hydrogen. During the early start-up phase of P-3B, the P-1 and P-2 wells were operated at lower air injection rates. These wells have achieved higher on-stream factors with oil production rates of up to 400 barrels per day for each well. Produced oil quality is averaging approximately 12 degrees API, compared to the native eight degree API bitumen in-situ. With P-3B production anticipated to stabilize during the third quarter, we had planned to gradually increase air injection on all three wells; however recent plant shutdowns have delayed these operating plans.

We continue to recover a light oil condensate in the secondary separators that is being carried in the vapour phase by the overhead gas stream. This lighter oil is over 30 degrees API and is not included in the production rates noted above. We continue to analyze the quality and quantity of this light fraction. Estimates indicate that this could be up to 10% of the total produced hydrocarbons. This lighter oil component further demonstrates significant in-situ thermal cracking and the potential for co-production of other high-value by-products.

Our improved surface facilities design utilizing primary gas separation followed by tank separation of oil, water and sand (rather than using a single pressure vessel) is being installed on P-3B and, when combined with the success of our narrower liner slot size, is expected to eliminate most operational challenges caused by sand production in this well and future wells. These improved surface facilities will be operational during the third week of November.

We have now been expecting Alberta government regulatory approval for our three well expansion for several months. We are disappointed with the lack of regulatory progress and have tried to work closely with regulatory agencies to expedite timely approval. Unfortunately, the process for oil sands development in Alberta is being delayed by a number of factors beyond our control. We have positioned ourselves to be able to execute this expansion as soon as possible following approval. The same drilling rig that efficiently drilled P-3B is currently racked on the plant site. All of the equipment necessary to modify the plant to handle the increased production is either on-site, in production, or waiting in yards for shipment. Our current understanding is that Alberta's Energy Resources Conservation Board ("ERCB") will make its decision on the expansion on November 24, 2008. All plans are in place for accelerated site preparation, drilling, and facility modifications once regulatory approval of the three well expansion project is received.

May River Project

The May River Project is our commercial expansion plan for the THAI™ technology on the Whitesands leases. Plant production experience and engineering analysis to date provided the basis for simplifying our May River central processing facility design. The central facilities for the project will be located approximately two kilometres from the current Whitesands site. May River is planned to be built in phases, beginning with initial production capacity of 10,000 bopd of partially upgraded oil, ultimately building capacity to 100,000 bopd.

At May River we will be incorporating on-site electric power generation from our low BTU produced gas. We expect to be able to generate enough power from this gas to be more than energy self-sufficient, which will further reduce the carbon footprint of the project. This will effectively offset coal-fired power generation from the Alberta electrical grid and reduce the greenhouse gas emissions of the project. Elemental sulphur will also be recovered using the CrystaSulf® technology. This technology is designed to recover sulphur from the produced H2S more efficiently and with a much lower energy use than competing technologies. We have recently acquired the worldwide use and license rights to the CrystaSulf® technology for all global heavy oil applications, and will be incorporating this technology into our planned commercial developments, as well as any new joint venture opportunities that we choose to pursue. Produced sulphur is expected to provide additional revenue from the project. Regulatory applications for May River's first phase will now be filed later in November due to delayed receipt of the environmental and engineering reports from third party consultants necessary for the application.

Dawson Project

The Dawson project is a joint venture involving our first Alberta-based, third party THAI™ license. This project is located near Peace River Alberta and will be developed in the Bluesky Formation. The upper portions of this formation contain 11 degree API heavy oil, comparable to other conventional heavy oil reservoirs throughout western Canada. We are planning to implement a two-well project that will also incorporate our simplified facility design. In August 2008, a stratigraphic well was drilled on the project site that will be used as a thermal observation well during the operations phase. The ERCB application for the project is expected to be filed in November and with timely regulatory approval we could commence construction at Dawson in the first quarter of 2009.

Sutton Creek, Saskatchewan

We have acquired 35 kilometres of 2D seismic on our 23,040 acre oil sands lease in Saskatchewan. We had originally planned to shoot a 45 kilometre program but due to poor weather conditions the program was reduced, however we were able to acquire data over the key target areas. Interpretation is expected to be completed by year end at which time we will determine the next steps in an exploration drilling program early in 2009.

Business Development

Our wholly-owned subsidiary, Archon Technologies Ltd., continues to evaluate a number of innovative engineering, environmental, and other value-added technology options to improve operational efficiency and reliability, and to reduce the overall environmental impact of hydrocarbon recovery. Other technologies being assessed include enriched oxygen injection, produced gas-fired cogeneration, enhanced produced water quality, and partial surface upgrading.

We are also in late-stage negotiations on several joint ventures to demonstrate and commercialize THAI™ in a wide range of large global resource opportunities. This portfolio-based approach should also allow us to more rapidly advance the technology and mitigate regulatory delays with the goal of obtaining efficient and timely project approvals.

LATIN AMERICAN BUSINESS UNIT - Petrominerales Ltd. (TSX: PMG - owned 76.4%)

A full operational update of our 76.4% owned Latin American Business Unit, Petrominerales Ltd., was published on November 6, 2008 and can be found at and Highlights of this release included:

- Average crude oil production increased 176% to 12,485 bopd compared to the third quarter of 2007.

- Production is now 19,590 bopd including production from our recently completed Corcel-C3 well.

- Petrominerales will be casing the Corcel-D1 well as a new pool discovery and will immediately move to drill the D2 and D3 wells.

- Operating costs have decreased from US$10.75 per barrel in the second quarter of 2008 to US$8.02 per barrel in the third quarter.

- Superior operating netbacks of US$86.66 per barrel reflecting a 53% increase over the third quarter of 2007.

- Funds flow from operations increased by 288% to US$78.3 million (US$0.75 per diluted share).

- Net income increased by 466% to US$58.0 million (US$0.57 per diluted share).

- Strong financial position with net working capital of US$55.0 million at September 30, 2008, an undrawn credit facility with an US$80 million borrowing base and strong cash flows.

- Repurchased 701,800 common shares.

- Repurchased convertible debentures with a face value of US$15.5 million for US$9.4 million.


Petrobank is pleased to announce the appointment of Mr. Allen Knight, P.Eng., MBA as Vice President, New Ventures. Mr. Knight brings over 30 years experience in the oil and gas industry in various senior roles with a demonstrated ability to execute strategic acquisitions.

Petrobank has promoted Mr. Peter Hawkes, P.Geol. to Vice President, Exploration of the Canadian Business Unit. Mr. Hawkes has 26 years of oil and gas experience and has played a significant role in Petrobank's exploration success since joining the Company in 2005.

To more clearly reflect certain roles and responsibilities within our executive team, we have also promoted Mr. Chris Bloomer to Senior Vice President and Chief Operating Officer, Heavy Oil, Mr. Corey Ruttan to Senior Vice President and Chief Financial Officer and Mr. Gregg Smith to Senior Vice President and Chief Operating Officer, Canada.

One of the key elements of our success has been the strength of our people and we believe that these promotions reflect the strength and depth of our entire team, who are all instrumental in delivering Petrobank's operational goals and guiding our strategic direction.

Conference Call

Petrobank will be holding a conference call on Friday, November 14, 2008 at 9:00am (Mountain Time) to discuss Petrobank's third quarter financial and operating results. The investor conference call details are as follows:

Webcast Link:

Dial-in Number: 416-641-6105 or 1-866-862-3927

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 and a technology subsidiary. The Canadian Business Unit is focused on developing a solid production platform from the Bakken light oil play in southeast Saskatchewan, and exploiting a large undeveloped land base through the application of new technology to large oil and gas resource opportunities. The Latin American Business Unit, operated by Petrobank's 76.4% 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 14 exploration blocks covering a total of 1.6 million acres in the Llanos and Putumayo Basins. Whitesands Insitu Partnership, a partnership between Petrobank and its wholly-owned subsidiary Whitesands Insitu Inc., owns 75 net sections of oil sands leases in Alberta, 36 sections of oil sands licenses in Saskatchewan and operates the Whitesands project which is field-demonstrating Petrobank's patented THAITM heavy oil recovery process. THAITM 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. THAITM and CAPRITM are registered trademarks of Archon Technologies Ltd., a wholly-owned subsidiary of Petrobank.

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 results of operations and the timing of certain projects. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. 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.

Resources and Contingent Resources

In this press release, Petrobank has disclosed estimated volumes of "contingent resources" or "resource" estimates. "Resources" are oil and gas volumes that are estimated to have originally existed in the earth's crust as naturally occurring accumulations but are not capable of being classified as "reserves" as described below. The following are excerpts from the definitions of resources and reserves, contained in Section 5 of the COGE Handbook, which is referenced by the Canadian Securities Administrators in "National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities": Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. Resources and contingent resources do not constitute, and should not be confused with, reserves.

Barrels of Oil Equivalent ("boe")

Disclosure provided herein in respect of boe units may be misleading, particularly if used in isolation. A boe conversion relationship of 6 mcf to 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

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
    Senior Vice President and Chief Operating Officer, Heavy Oil
    (403) 750-4400
    Petrobank Energy and Resources Ltd.
    Corey C. Ruttan
    Senior Vice President and Chief Financial Officer
    (403) 750-4400
    Petrobank Energy and Resources Ltd.
    R. Gregg Smith
    Senior Vice President and Chief Operating Officer Canada
    (403) 750-4400