Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd.

May 12, 2009 01:37 ET

Petrobank First Quarter Production Hits 43,856 BOEPD

CALGARY, ALBERTA--(Marketwire - May 12, 2009) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is pleased to announce our first quarter 2009 financial and operating results.

(All references to $ are Canadian dollars unless otherwise noted)


(all comparisons are to the first quarter of 2008)

- Petrobank's production almost doubled to 43,856 barrels of oil equivalent per day ("boepd") in the first quarter of 2009.

- Canadian Business Unit ("CBU") production increased 59% to 22,085 boepd.

- Latin American Business Unit ("LABU") production increased 152% to 21,771 barrels of oil per day ("bopd").

- Our Heavy Oil Business Unit ("HBU") produced 248 bopd in March and 256 bopd in April.

- Despite a sharp drop in world oil prices funds flow from operations increased by 1% to $125.2 million ($1.40 per diluted share). We recorded a net loss of $1.5 million ($0.02 per diluted share) in the first quarter compared to net income of $35.5 million ($0.40 per diluted share) in the same 2008 period.

- CBU production expenses improved 27% to $6.81/boe and LABU production expenses improved 32% to $7.40/bbl.

- CBU operating netbacks, excluding hedging gains of $5.31/boe, averaged $34.68/boe and LABU operating netbacks averaged $30.18/bbl in the first quarter.

- On April 27, 2009, Petrobank agreed to sell 9.9 million shares of our Petrominerales holdings for gross proceeds of $101.5 million. The transaction is expected to be completed on May 15, 2009, at which time Petrobank's ownership interest will be reduced to approximately 66.8%.

Three months ended March 31, 2009 2008 % Change
($000s, except where noted)
Oil and natural gas revenue 190,786 179,291 6
Funds flow from operations (1) 125,156 123,488 1
Per share - basic ($) 1.50 1.53 (2)
- diluted ($) 1.40 1.36 3
Net income (loss) (1,542) 35,537 -
Per share - basic ($) (0.02) 0.44 -
- diluted ($) (0.02) 0.40 -
Capital expenditures
Canadian Business Unit ("CBU") 70,024 110,489 (37)
Latin American Business Unit ("LABU") 81,560 68,746 19
Heavy Oil Business Unit ("HBU") 21,410 21,035 2
Total Company 172,994 200,270 (14)
Total assets 2,414,146 1,737,225 39
Net debt (1) 418,079 181,306 131
Common shares outstanding, end of period
Basic 83,598 82,489 1
Fully diluted (2) 99,214 96,889 2


CBU operating netback ($/boe except where noted)

Oil and NGL revenue ($/bbl) (4) 48.57 91.87 (47)

Natural gas revenue ($/mcf) (4) 5.35 7.73 (31)

Oil and natural gas revenue (4) 46.81 83.55 (44)

Royalties 5.32 6.74 (21)

Production expenses 6.81 9.35 (27)
Operating netback (5) 34.68 67.46 (49)

LABU operating netback ($/bbl) (1)
Oil revenue (4) 42.18 86.53 (51)
Royalties 4.60 8.25 (44)
Production expenses 7.40 10.86 (32)
Operating netback (5) 30.18 67.42 (55)

Average daily crude oil production (3)
CBU - oil and NGL (bbls) 19,722 11,351 74
CBU - natural gas (mcf) 14,179 15,229 (7)
Total CBU (boe) 22,085 13,889 59
LABU - oil (bbls) (6) 21,771 8,635 152
Total Company conventional (boe) 43,856 22,524 95

(1) Non-GAAP measure. See "Non-GAAP Measures" section.
(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"). HBU bitumen volumes are excluded from average daily production
as Whitesands operations are considered to be in the pre-operating stage
and accordingly are capitalized.
(4) Net of transportation expenses.
(5) Excludes hedging activities. In the first quarter of 2009 the CBU
realized gains of $5.31/boe (2008 - realized loss of $1.25/boe) and no
gain or loss was recognized by the LABU (2008 - realized loss of
(6) Actual production sold for the three months ended March 31, 2009 was
21,409 bopd (2008 - 8,635 bopd).


Petrobank reported strong funds flow from operations of $125.2 million, or $1.40 per diluted share, in the first quarter of 2009 as year over year sales volumes almost doubled to 43,856 boepd. Funds flow from operations increased 1% from the prior year, despite a 56% decrease in world oil prices. CBU infrastructure investments in 2008 reduced operating expenses to $6.81/boe in the first quarter, preserving strong operating netbacks of $34.68/boe, excluding hedging gains of $5.31/boe. Similarly in Colombia, continued improvements in production operations also decreased operating expenses to $7.40/bbl, leading to operating netbacks of $30.18/bbl.


Following an aggressive drilling program through 2008, our first quarter 2009 production averaged 22,085 boepd, a 59% increase from the 13,889 boepd produced in the first quarter of 2008. In response to the lower oil price environment in early 2009 we reduced our drilling program to 20 (16.14 net) Bakken horizontal wells during the first quarter. Despite lower activity levels, production was down less than 1% from the fourth quarter of 2008. Our efforts in the field to continue optimizing well performance and operating efficiencies minimized the impact of the reduced activity on our production. Outside of the Bakken, our activities are targeted toward building our expertise and drilling inventory in other large resource accumulations, including the Montney and Horn River Basin.

In 2009, our primary focus will be to maintain our low-cost advantage through selective drilling in the Bakken. We are positioned for continued long term reserve and production growth, despite our reduced pace of development at the beginning of 2009. At current commodity prices we expect to drill a further 50 wells this year and if oil prices improve we are prepared to drill as many as 120 wells in 2009. All of our Bakken drilling emphasizes testing and refining different technologies that have the potential to increase ultimate resource recovery.

The Bakken Resource

Petrobank pioneered the horizontal fracture stimulation techniques that opened up the true potential of this substantial resource, and we continue to find new ways to improve well performance and expected ultimate recoveries from the Bakken. Our recent efforts to further improve Bakken production have focused on increasing the intensity of fracture stimulation completions (fracs) by 38% in our long (1400 metre) horizontals, by 200% in our short (700 metre) horizontals, and by 400% in our short bilateral (two 700 metre horizontal legs from a single vertical well bore) horizontal wells. We continue to build on our innovative approach to maximizing value from the Bakken resource and we are monitoring production performance from these wells to optimize future drilling and fracture stimulation design. Our production and reserves are heavily weighted (over 85%) to high value Bakken light oil and associated gas and liquids. This allows Petrobank to achieve industry-leading netbacks and demonstrates our high quality asset base.

Of our year-end inventory of over 550 undrilled Bakken locations, only 162 have been assigned 2P reserves with an additional 19 assigned possible reserves. Our current drilling inventory is based on only four wells per section and could easily double with the advances being realized by increasing well density and frac intensity. We believe the 3P reserve estimates come closer to reflecting the true potential of our assets as our reserves are derived largely from low risk, extensive resource accumulations. CBU 3P reserves increased by 83% year-over-year to 86.2 million boe and reserve additions of 45.5 million boe replaced our 2008 production more than seven times. These 3P reserves have a net present value, discounted at 10%, before tax of $2.0 billion, an 85% increase from 2007 despite steep declines in commodity prices.

Part of our strategy in the Bakken is to operate centralized facilities to capture additional value from the gas and natural gas liquids associated with the light oil, and to ensure field efficiencies that maintain low operating costs. To strengthen our infrastructure, three new facilities at Viewfield, Creelman, and Freestone were connected to our main Midale plant through 100 kilometres of new pipelines. Together our facilities are now conserving more than 7 mmcf/d of natural gas plus associated natural gas liquids, allowing us to maintain low operating costs while improving our overall project economics.

The enhanced operational efficiencies achieved through our extensive infrastructure investments resulted in a reduction of our Bakken production costs to $6.03/boe. This brings the average first quarter production costs for all of our CBU operations down to $6.81/boe, a 27% decrease from the $9.35/boe recorded in the first quarter of 2008. Our future plans include two more pipeline-connected facilities that are scheduled to be built as drilling activity extends to the north. At our current drilling pace, construction is expected to commence in late 2009 or 2010.

Beyond Bakken

Petrobank has also established strong positions in two massive natural gas resource plays; the Montney and the Horn River Basin. The key to unlocking the potential of these plays is through the use of horizontal wells and multi-stage fracture stimulation technologies, similar to those pioneered by Petrobank in the Bakken. We intend to capitalize on our evolving experience with advanced fracturing techniques, with the goal of building a substantial, long-term inventory of drilling locations at a low near-term cost.

In October 2008, through the acquisition of a private company, we acquired a highly prospective position in the Montney tight gas play at Monias in northeastern B.C. We now have a 100% working interest in 17 sections of land, and a 5.0 mmcf/d gas plant.

In December 2008, we drilled our first Montney horizontal well, and in February 2009 we performed a seven-stage fracture stimulation in the upper portion of the 135 metre thick Montney interval. The well flow tested at initial rates in excess of 7.5 mmcf/d plus 180 barrels of natural gas liquids per day. The well was put on production at the end of the first quarter at a restricted rate of 5.5 mmcf/d. This well is currently producing at approximately 2.2 mmcf/day showing a typical production profile where the rate drops quickly and then flattens at a much lower decline rate. The consistent geology across our 17 sections of land establishes a 67-well inventory of prolific Montney drilling locations. Our next steps will be to install additional compression to increase our plant capacity to 10.0 mmcf/d and then drill another well later in 2009 to test new technology ideas and improve our economics for the play. Our independent reserve evaluators have only assigned reserves to the first well in this multi-well development.

A second resource play where we can apply our innovative completion experience is in the Horn River Shale Basin in northeast B.C. As this emerging play developed we began to build an acreage position, which has now expanded to 82 B.C. sections (54,721 acres) of 100% working interest lands and 14 B.C. sections of 15.5% working interest lands. Our first horizontal evaluation well was drilled in the first quarter of 2009 in an area with all-season access close to the Alaska Highway. The majority of the basin is characterized by a short three-month operating season (January to March) due to the presence of thick muskeg. All-season access at this first location allowed us to complete the multi-stage fracture stimulation during the second quarter of 2009. Our immediate focus will be on drilling test wells and developing a multi-year inventory of drilling locations in the Muskwa and Evie shales. No reserves have been assigned to our Horn River asset base as at December 31, 2008.


Late in 2007, we drilled an exploration well in the Cornwall area which tested gas at 6.5 mmcf/day with 200 barrels per day of condensate. We completed a short pipeline tie-in with compression installation during the quarter, and brought the well on production April 1st to take advantage of recently announced royalty incentives in the province of Alberta. Production from the well has been pipeline restricted at rates between 2.0 to 2.5 mmcf/day.


- Achieved stable production rates from our P3B well with air injection at one-third of design rates

- Effectively eliminated sand production with revised P3B liner design

- Produced at restricted rates of 248 bopd in March and 256 bopd in April

- Sustained P3B wellbore temperatures in the catalyst activation range

- Filed the Kerrobert project application with the Saskatchewan regulatory authorities

- Advanced the May River and Dawson project applications through the Alberta regulatory process

Whitesands Project

During March and into the second quarter of 2009, P3B operations were stabilized and rateable production was achieved. In the first quarter, P3B operations were ramped up following the A3 injection well workover and the commissioning of new plant facilities. Production averaged 248 bopd in March and 256 bopd in April, these restricted production rates correspond to a reduced air injection rate required to balance P2 production operations. The highest daily oil rate from the P3B well was 378 bopd in March and 404 bopd in April. During April, production from the P1 well was suspended and maintenance work on the P3B wellhead and primary separator reduced on-stream factors.

Since the initiation of production operations on P3B the well has exhibited negligible sand production, irrefutably proving the effectiveness of the new liner design. Produced gas volumes and rates are also in balance with the air injection rate, confirming the toe to heel process. Wellbore temperatures are now between 300 and 400 degrees Celsius, within the CAPRI™ catalyst activation range. Preliminary analysis of produced oil from P3B indicates upgrading to 12 degrees API, similar to the other wells. However, P3B oil has shown a significant reduction in asphaltene content, an increased volume of condensed light oil production and higher hydrocarbon content in the produced gas. Now that the well is operating in the optimum catalyst temperature range, conclusive, quantitative evidence confirming catalytic upgrading is expected with further testing. Associated water production continues to be high quality and is easily separated from the produced oil. Continuous upgrading and the composition of the produced gas indicate sustained high temperature combustion.

We have a drilling rig on-site and plan to have our P1 replacement well, P1B, drilled in the second quarter incorporating our new liner design. We have decided to cost-effectively convert Whitesands into a modified three well THAI™/CAPRI™ demonstration site, which will enable us to test any other new technology options, such as oxygen enrichment, using the existing facilities.

Kerrobert Project

Pre-development work is currently underway on our two well, THAI™ conventional heavy oil project at Kerrobert. This third party THAI™ license project is located in west central Saskatchewan. We filed the Saskatchewan Ministry of Energy and Resources enhanced oil recovery regulatory application for the project on April 22nd. This filing begins the approximately one month approval process. Pending regulatory approval we expect to begin site preparation and drilling early in June, with the Pre-ignition Heating Cycle beginning in July and first production expected by the fourth quarter.

A public open house was held on April 17th in Kerrobert. A broad cross section of the local communities, land owners, and government representatives attended the open house. We received a positive response and encouragement for the project and its potential.

This joint project will highlight the applicability of the THAI™ technology in the conventional heavy oil resource base in Saskatchewan. We consider that a significant portion of the estimated 20 billion of barrels of unrecovered conventional heavy oil resources in Saskatchewan can be commercialized using THAI™. In addition, Saskatchewan is actively encouraging oil and gas development and the application of advanced technologies.

May River Project

The May River Project is our first large-scale commercial THAI™ project on Petrobank's oil sands leases west of Conklin, Alberta. The May River project design builds on the experience gained from the Whitesands pilot. This project will be built in phases, with initial production capacity of 10,000 barrels of THAI™ oil per day, and an ultimate capacity of up to 100,000 bopd.

The regulatory application for May River's first phase was filed with the Energy Resources Conservation Board and Alberta Environment in December 2008. The application has been deemed complete and is now moving efficiently through the regulatory process. The front end engineering and design for the project began in the fourth quarter of 2008, and we expect to have completed this phase of engineering by the third quarter of 2009. The design incorporates self-sufficient power generation utilizing low-energy produced gas, sulphur recovery, is CO2 capture ready, and will be a net water producer rather than a water user. These designs contribute to making the May River project a leading environmentally sustainable process for oil sands and heavy oil development. The project is also designed to utilize a modular approach with direct applicability to heavy oil projects world-wide.

Dawson Project

The Dawson Project is a joint project involving our first Alberta-based, third party THAI™ license. Our partner is now Shell Canada Limited who acquired Duvernay Oil Corp. in August 2008. The project is located near Peace River, Alberta and will be developed in the Bluesky formation. In August 2008, a stratigraphic well was drilled on the project site, which will be used as a thermal observation well during the project's operating phase. The regulatory application for the project was filed on April 2nd.

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, increase product quality, and reduce the overall environmental impact of bitumen and heavy oil recovery. Technologies being assessed include enriched oxygen injection, power generation using produced lean gas, enhanced produced water quality, and incremental surface upgrading.

We continue to receive increasing world-wide interest in our technologies because of their superior economic and environmental benefits. Our joint project strategy is to demonstrate and commercialize THAI™ in a wide range of large global resource opportunities. Negotiations are ongoing and we expect to successfully conclude additional joint projects in the near term.


A full operational update of our 76.9% owned Latin American Business Unit, Petrominerales Ltd., was published on May 6, 2009 and can be found at and Highlights of this release included:

- Significant production growth in the quarter; crude oil production increased 152% to 21,771 bopd due to drilling successes at Corcel, Mapache and Neiva.

- Strong operating netbacks resulted in cash flow of US$41.8 million (US$0.42 per share) and net income of US$7.4 million (US$0.07 per share) despite a sharp drop in world oil prices.

- Solid financial position with net working capital of US$16.3 million, an undrawn US$80 million credit facility, strong cash flows and operating netbacks combined with significant production growth.

- Continued drilling success has resulted in production averaging 25,252 bopd to date in May.

- Repurchased 802,200 common shares under a normal course issuer bid.


Petrobank's annual general meeting (the "Meeting") will be held today (Tuesday, May 12, 2009) at 2:00 p.m. (Calgary time) in the Main Ballroom of The Metropolitan Centre, 333 Fourth Avenue SW, Calgary, Alberta, Canada. The Meeting will be webcast live and available for replay at To listen to the Meeting live please enter in your web browser After the formal business of the Meeting and corporate presentation, management of the Company will provide a question and answer period. For those participating by webcast, you are invited to submit questions to Petrobank any time during this question and answer session by typing your question into a box displayed on the webcast page and clicking on the button "submit". Petrobank's management will endeavor to answer as many questions as possible during the time frame allotted.

Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas exploration and production company with operations in western Canada and Latin America. 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 76.9% owned (to decrease to 66.8% on May 15, 2009) TSX-listed subsidiary, Petrominerales Ltd. (TSX:PMG), is a Latin American-based exploration and production company producing oil in Colombia with 16 exploration blocks covering a total of 1.9 million acres in the Llanos and Putumayo Basins of Colombia and 2.6 million acres in the Ucayali Basin of Peru. 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 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.

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 financial results, 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.

Non-GAAP Measures

This press release contains financial terms that are not considered measures under Canadian generally accepted accounting principles ("GAAP"), such as funds flow from operations, funds flow per share, net debt and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. Specifically, funds flow from operations and funds flow per share reflect cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds flow per share important as they help evaluate performance and demonstrate the Company's ability to generate sufficient cash to fund future growth opportunities and repay debt. Net debt includes bank debt plus accounts payable and accrued liabilities less current assets (excluding future income tax asset) and is used to evaluate the Company's financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Funds flow from operations, funds flow per share, net debt and operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations, net income or other measures of financial performance calculated in accordance with GAAP. The following table shows the reconciliation of funds flow from operations to cash flow from operating activities for the periods noted:

Three months ended March 31,
2009 2008 Change
Funds flow from operations: Non-GAAP 125,156 123,488 1%
Changes in non-cash working capital (13,892) (53,791) (74%)
Cash flow from operating activities: GAAP 111,264 69,697 60%

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 bbl 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
    (403) 750-4400
    (403) 266-5794 (FAX)