Unconventional Oil

[johnlw]

Connacher estimates $290-million cost for Pod One

2007-04-24 08:16 ET - News Release

Mr. Richard Gusella reports

CONNACHER PROVIDES UPDATE ON RECENT DEVELOPMENTS AND FINANCING

Connacher Oil and Gas Ltd. is providing an overview on recent activities involving the company's Great Divide project, conventional oil and gas activities and the company's 9,500-barrel-per-day refinery in Great Falls, Mont.

Great Divide Pod One

Connacher is in the process of constructing a plant and facilities and drilling steam-assisted gravity drainage (SAGD) well pairs at the company's 10,000-barrel-per-day-of-bitumen SAGD project located in northeastern Alberta (the Pod One project). The budgeted amount in respect of the development of the Pod One project, including contingencies, capitalized interest, capitalized overhead and capitalized operating costs (until the project becomes commercial), was previously disclosed to be $256-million. This included $24-million of sunk costs (lease acquisition, exploratory core hole drilling and preliminary evaluation costs dating back to 2004) incurred prior to submissions of regulatory applications, and commencement of construction.

Most recently, Connacher has completed a detailed review of the overall cost forecast for the Pod One project. The total cost forecast for completion of the Pod One project, prior to any cost-mitigation efforts, is now estimated to be $290-million, including sunk costs, capitalized items, revised budget items and new items. The capitalized costs total approximately $25-million in this estimate and will be incurred over time as the plant is commissioned and bitumen production increases as the reservoir heats up.

A significant portion of the increase in estimated budgeted costs relate primarily to the main SAGD facility. This occurred due to a number of minor scope changes to the facility, efforts to keep shop and field construction on the 300-day schedule during harsh winter conditions, a jump in the price of steel and an increase in the estimated cost of buildings. It is anticipated that some of these cost increases may be mitigated by a reduction in future operating costs as a consequence of the usage of more energy-efficient facilities. Although there have been minor scope changes to the main facility, it is still on schedule for start-up in the summer of 2007. In addition, other estimated cost increases for previously budgeted items related to well pad facilities, camp installation, site preparation, infrastructure items and personnel.

Further costs have arisen for items which were either not previously budgeted for or that have arisen as a consequence of increased activity by Connacher in the region. These items, including road improvements, will be completed within the Pod One project but will provide benefit to Connacher in respect of its other activities in the area over time. In addition to these improvements, modifications to the Highway 63 access are also planned. Costs associated with inventories of parts, personnel camps, electrical infrastructure and civil engineering materials have now been included in the Pod One costs and therefore have resulted in an increase to the overall Pod One project budget; however, these items will also be used for the development of Connacher's nearby resources.

Until very recently, the largest non-planned expenditure item had been site preparation costs due to the proximity of water to the surface and the need to move considerably more material to achieve a suitable site. While this factor and others resulted in usage of the majority of the contingency amount, which had been provided for in the original budget, Connacher anticipated until this recent review that it could complete the Pod One project within the budgeted amounts. The Pod One project remains on schedule for start-up in the summer of 2007, which is within four years of Connacher initially acquiring the oil sands leases. Connacher is satisfied with the execution strategy and process in spite of inflationary pressures and the requirement for some scope changes affecting its budgeted costs. Mitigation efforts will continuously be undertaken to attempt to reduce overall costs associated with the development of the Pod One project.

Other oil sands developments

During this past winter, the company drilled 81 core holes and shot 68 square kilometres of three-dimensional seismic to successfully delineate additional oil sands accumulations. Based on this work, and subject to approval by Connacher's board of directors, the company is preparing an application for submission to the AEUB, Alberta Environment and to other departments of the Alberta government for permission to develop Pod 2 (also known as the Algar project). The Algar project is estimated to be similar in size, scope and cost to the Pod One project. The company has also commenced stakeholder consultations including consultations with first nations groups in the area.

Conventional production summary

As previously disclosed, the company's conventional crude oil and natural gas production for 2006 averaged 2,725 barrels of oil equivalent per day. Connacher's production has recently declined to approximately 2,100 barrels of oil equivalent per day, comprising 8.3 million cubic feet per day of natural gas and 700 barrels per day of crude oil. This has occurred for a variety of reasons, including normal production declines, temporary limitations or malfunctions of some facilities, an inability to tie in new wells as planned due to issues related to plant access, winter conditions and regulatory issues. In the opinion of the company, many of the issues affecting the reduction in production are anticipated to be of short duration. In addition, workovers are continuing and two new wells that have been tied in are expected to soon be on production. In the second quarter of 2007, production is expected to increase. The overall impact on Connacher's budgeted financial results for the first quarter of 2007 and for the full year are not anticipated to be material as a consequence of this short-term decline in production.

Connacher's 2007 winter drilling program resulted in a number of new natural gas wells in its Marten Creek area which have been tested and are standing cased or are awaiting completion and tie-in next winter, due to winter-only access. The company believes, based on initial test results, that it can significantly increase its production of natural gas from this area once this work is completed. These new reserves were discovered subsequent to the preparation of the year-end reserves evaluation and will be included in the company's next reserves update. Further drilling is planned in this area.

Profitability increases at Montana refinery

Connacher also advises that based on information presently available, its refining subsidiary, Montana Refining Company Inc. (MRCI), anticipates reporting strong operating and financial results for the first quarter of 2007, substantially in excess of budgeted expectations and consequentially more than offsetting the shortfall relative to budget anticipated to arise from the lower production levels derived from Connacher's conventional oil and natural gas properties. A number of factors contributed to this performance, including higher product prices, better-than-expected product yields, higher-than-expected throughput, a lower crude cost and some positive developments associated with the asphalt market. This strong financial performance will assist Connacher's overall financial results in the first quarter of 2007 and also is a mitigant to financial requirements for the increased costs anticipated at Great Divide Pod One.

Compliance inspection

On April 17, 2007, MRCI received notification from the United States Environmental Protection Agency that its National Enforcement Investigations Centre will be conducting a Clean Water Act compliance inspection in respect of the refinery commencing on April 24, 2007. The purpose of this inspection is to determine compliance with applicable environmental legislation, approvals and permits. MRCI is co-operating in connection with this compliance inspection.

Financing

On April 17, 2007, Connacher announced the offering, on a bought-deal basis, of 4,819,300 common shares and 5,714,300 common shares issued on a flow-through basis, for total net proceeds of $50,000,170 underwritten by a syndicate led by GMP Securities LP and including Orion Securities Inc., HSBC Securities (Canada) Inc., Raymond James Ltd., D & D Securities Company, Desjardins Securities Inc. and Jennings Capital Inc. (collectively, the underwriters). Following consultation between Connacher and the underwriters, Connacher and GMP Securities LP, on behalf of the underwriters, agreed to terminate the offering effective April 23, 2007. The underwriters have advised that they continue to remain committed in their support for the financing initiatives of Connacher and intend to work toward negotiating with Connacher an equity financing on terms and conditions to be mutually agreed upon.

We seek Safe Harbor.

[johnlw]

Researcher cracks secrets of 'ugly' bitumen
Gordon Jaremko, The Edmonton Journal
Published: Monday, April 23, 2007

EDMONTON - Steve Kuznicki knew he took on a tall order when an Alberta business, government and academic coalition imported him from New Jersey to clean up oilsands production.

"Bitumen is some of the ugliest stuff you ever saw," the 53-year-old industrial chemist said in an interview.

As a champion inventor whose resume is studded with professional awards and 53 patents in cleanup fields such as water purification and gas separation for health care, he knows dirty when he sees it.


"Ugly is contaminated, non-homogenous and ill-defined," he said.

"Bitumen is five-per-cent sulphur, half a per cent nitrogen and 1,000 parts per million heavy metals. Its viscosity (stickiness) is like tar on a cold day. That's ugly."

The former chief scientist of global chemicals giant Engelhard Corp. also recognized a leadership role in big-league industrial research when it was offered to him in Edmonton by the University of Alberta, the province's $1-billion Alberta Ingenuity Fund and Imperial Oil.

The coalition, backed by other federal and industry agencies, is paying him to make a fresh start as a pioneer of clean technology for the world's largest energy source outside Saudi Arabia.

"The oilsands are so big," Kuznicki said. "If I were running the show, I'd get a hundred crazy inventors together, and if one came up with something significant we'd be ahead of the game."

A similar but more formal version of his idea founded the assembly of about 50 professors, technical staff and graduate students he leads on the U of A campus, the Imperial Oil -- Alberta Ingenuity Centre for Oil Sands Innovation or COSI for short.

Ingenuity fund literature describes Kuznicki as an "award-winning, blue-sky R&D researcher with a long list of science commercialization successes."

He specializes in a field with proven potential to transform wide arrays of consumer products and industrial processes.

Enter molecular sieves. "You run into several of these every day. The uses of these things run into the thousands but nobody's heard of them."

A box of laundry detergent is more than one-quarter a molecular sieve known as zeolite A, which replaced environmentally harmful phosphates formerly used heavily in cleansers. About five per cent of all patents for industrial chemical materials and processes involve molecular sieves.

Kuznicki's contributions include the science behind filters that remove lead from drinking water and separate oxygen from the atmosphere in portable respirators that enable lung disease sufferers to stay mobile.

Molecular sieves are naturally occurring, often volcanic minerals with mesh structures that resemble screen doors. Specialists in the field devise ways to employ the materials on a large scale, lately in forms engineered to suit industrial and manufacturing purposes.

COSI's declared ambition is to come up with more environmentally acceptable, energy-efficient ways to tap the oilsands than the current production mainstay, the hot-water process that Edmonton scientist Karl Clark invented on the U of A campus in the 1920s.

Clark's method served the industry well in its infancy but could stunt its growth by consuming oceans of water, creating seas of toxic tailings ponds, burning up Alberta's natural gas and emitting clouds of carbon-dioxide, COSI founders told a February launch ceremony for the new research campaign.

Two months later, Kuznicki reported the team is coming up with encouraging results on a budding research front known as "non-aqueous extraction" or taking out the black gold without using water.

The experiments combine mineral sieves, acid, grinding and heat. The sieves remove more than 50 per cent of bitumen's impurities and make a start on thinning it out into the lighter or "cracked" oil form required for pipeline shipping and refining.

The latest trials, still too fresh to be written up in scientific journals or even memos to COSI supporters, go a big step further.

In the "blue-sky" vein of trying new things without being held back by fear of failing, Kuznicki's team put a light hydrocarbon byproduct of oil and gas processing into tubes full of the cracked bitumen as an organic solvent.

The washed material collapsed and partially upgraded oil flowed out. An additional process that recycles the solvent for repeated use is conceivable, he said.

"I don't know if we have something practical yet. But it sure has me going," Kuznicki said.

"This is awfully preliminary. But this has me awfully excited."

A new oilsands extraction process that works could produce more than oil. There is potential to add new dimensions to Alberta industry by creating demand for large volumes of industrial materials.

Molecular sieves have been commercial items for millennia. Quarries date back to Roman times when the minerals were used as "dimension stone," a construction material prized as hard but light because of its natural mesh structure.

"I'd be stunned if there weren't significant deposits in Alberta, probably along the sides of the Rocky Mountains," Kuznicki said.

[Tackler]

Good coverage and how convienient right after more financing. I love the math involved! ...

"I honestly believe if I come out with a technology that's different from the one you're using, and after the initial shock I can show it takes half the capital investment, has half the operating costs, will recover twice as much oil and start up in half the time, how long are you going to wait?" Mr. Wright said.

$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$$

[kidl]

'It's a nice problem to have'
Petrobank's bitumen recovery project is working so well that production is being held back for lack of storage space
Jon Harding, Financial Post
Published: Saturday, April 21, 2007

http://www.canada.com/nationalpost/financialpost/printedition/story.html?id=66f1fbc8-b61c-4e74-bd1e-....

CALGARY - A $35-million oilsands experiment Petrobank Energy and Resources Ltd. is conducting on a muddy rectangle of land cut from the northeastern Alberta forest is going far better than president and CEO John Wright could have hoped.

The thermal recovery project, which Mr. Wright thinks can revolutionize the oilsands busines, is showing it is capable of producing more oil than expected and it reached its peak potential sooner than expected.

Petrobank is the 84% owner of Whitesands Insitu Ltd., a pilot project in which the company's oilsands reserves are being baked underground in a volatile mix of oxygen and hydrocarbons.
John Wright, president and CEO of Petrobank Energy and Resources Ltd., says there's a market out there for the company's patented toe-to-heel air injection (THAI) bitumen recovery system.View Larger Image View Larger Image
John Wright, president and CEO of Petrobank Energy and Resources Ltd., says there's a market out there for the company's patented toe-to-heel air injection (THAI) bitumen recovery system.

A combustion front, slow-moving and at 600-degree Celsius, is pushing oil to the surface.

The so-called fire flood recovery method was tested and scrapped by a handful of industry stalwarts in the 1970s. Petrobank took the technology and adapted a horizonal well configuration that lets gravity -- the oilsands melt towards the production well--do some of the work.

With the eyes of the industry watching closely, heavy crude has been successfully sucked above-ground for the better part of the past eight months at Whitesands via two of the project's three planned horizontal production wells.

A third well pair -- made up of one vertical air injector and a horizontal producer sitting 500-metres away -- will be brought on stream in the coming weeks, all of which is leading to a new challenge for Mr. Wright.

Whitesands' potential output was an uncertain measure pending the success of Petrobank's patented toe-to-heel air injection (THAI) recovery process.

With THAI working so successfully, production from the three sets of wells could easily double early predictions of 1,800 barrels of oil a day, and for now, it's being choked back well below that because the project's storage tanks are too small.

It's a nice problem to have, Mr. Wright said.

"It's telling us everything about the process that worked theoretically in the lab works in the field, and also that we took a very fail-safe, call it conservative, stance in our planning.

"We didn't build big enough tanks, but the last time I drove down the road that was a pretty easy solution to solve. There are lots of big tanks out there."

Mr. Wright and his Petrobank colleagues believes the THAI process could unseat the more common oilsands recovery method called steam-assisted gravity drainage, or SAGD, which itself has only been used by the industry for a little more than 10 years.

Only about 10% of Alberta's oilsands are buried close enough to the surface to mine.

The THAI process seeks to recover as much as 80% of the bitumen in place, more than double that of SAGD, and for half the capital and operating costs.

There's no need to build water processing and large steam production facilities, and large quantities of natural gas aren't required because there's no need for steam.

Mr. Wright figures costs to build an oilsands project using the THAI recovery method would come in at between $10,000 and $15,000 a flowing barrel, a measure of capital intensity. That's about half the cost for a SAGD project and a giant step back from large-scale mining and upgrading projects that produce upgraded synthetic crude, for which costs have risen to between $100,000 and $128,000 per flowing barrel.

"Above ground, it's way less pots and pans, and below ground it's half as many horizontal wells, which are the expensive wells," said Mr. Wright.

Petrobank will later this year build three more well pairs to test another of its patented processes called CAPRI, in which catalysts mixed with the hot oil at the well bore could work to upgrade it underground. The company is also planning to build a separate commercial project producing 10,000 barrels a day on its oilsands leases.

Ultimately, the hope is for Whitesands Insitu Ltd. to farm out its technology to other oilsands players.

"I honestly believe if I come out with a technology that's different from the one you're using, and after the initial shock I can show it takes half the capital investment, has half the operating costs, will recover twice as much oil and start up in half the time, how long are you going to wait?" Mr. Wright said.

"There will be some skepticism, but sooner or later it'll just be accepted as a common concept, like SAGD was."

[johnlw]

I guess Total has their own people, own culture.
The Deer Creek boys might not enjoy working for a monolith?

[Tackler]

I dont get it when they sell to Total all the expertise moves on?

"Its engineers and geologists have worked on 11 oilsands projects"

So Total has to start hiring, or bring in a bunch of french engineers?

[johnlw]

Old hands have grand ambitions
Oilsands know-how

Claudia Cattaneo
Financial Post

Saturday, April 21, 2007

After selling Deer Creek Energy Ltd. to French oil giant Total SA in 2005 for $1.67-billion, the startup's management team re-assembled months later to launch a new company, Laricina Energy Ltd.

Its ambitions are just as grand this time around.

Laricina wants to produce 150,000 to 200,000 b/d by 2022 to 2025 using in-situ technology from three main plays: oilsands in the McMurray Formation, the less-known Grand Rapids sands, and from carbonates, an emerging area that has caught the attention of Royal Dutch Shell PLC and Husky Energy Inc.

Glen Schmidt, former chief executive of Deer Creek who holds the same titles at the new private company, said his team is moving quickly to achieve its first oil production in 2010 or 2011 because of its experience. Its engineers and geologists have worked on 11 oilsands projects already in operation and three under construction.

"We are not confused about where we are going and we have a board of directors that has been active in the oilsands for six years. We are very much focused on what we know how to do."

The company assembled a vast land base in the past 18 months and just completed its first winter drilling program. It estimates its leases hold five billion barrels of oil in place, of which 1.2 billion barrels is recoverable.

Laricina also holds a 1% interest in the $10-billion Joclyn mining oilsands project. It had earlier sold its 84% stake to Total as part of the Deer Creek transaction.

The small interest was effectively re-purchased from Enerplus Resources Fund, which had been its 16% partner in Joclyn, before the Total transaction.

Mr. Schmidt said Laricina wanted to re-establish the Enerplus partnership in the new venture.

The interest accounts for a small portion of its assets but gives Laricina the option to participate in an upgrader, if one is built by Total, Mr. Schmidt said.

The company has not yet decided whether it wants to upgrade its bitumen.

With the discount applied to heavy oil now shrinking because of new pipelines to the United States and more demand for Canadian heavy oil among U.S. refiners, upgrading in Alberta may no longer make sense, he said.

"We view upgrading as a different business and an evolving business," Mr. Schmidt said.

The private company has raised $200-million and plans to go public in late 2008 or early 2009.

Laricina is named after a Boreal Tamarack able to thrive in adverse climates.

[e-mail]
© National Post 2007

[Rocketred]

exel

Excelsior Energy to buy 52.5% of heavy oil project

2007-02-08 11:07 ET - News Release
Shares issued 27,556,028
EXEL Close 2007-02-05 C$ 0.30


Mr. David Winter reports

EXCELSIOR SIGNS BINDING LETTER OF INTENT TO ACQUIRE A 52.5% OF HEAVY OIL PROJECT IN ATHABASCA HEAVY OIL DISTRICT NEAR FORT MCMURRAY

Excelsior Energy Ltd. has signed a binding letter of intent with Bounty Development Ltd., an Alberta-based private company, to acquire a 52.5-per-cent interest in Bounty's wholly owned Hangingstone oil sands assets. These assets consist of 39 contiguous sections (24,960 acres) in Township 86 and Township 85 in Alberta, approximately 28 kilometres south of Fort McMurray. An independent, Alberta-based private company has also signed a letter of intent to acquire a 22.5-per-cent interest from Bounty in the assets on the same terms as Excelsior.

The assets are located in close proximity to a number of active SAGD projects that are in various stages of development. Jacos's Hangingstone producing SAGD project and Connacher's Great Divide project to the southwest, North American Oil Sands' Hangingstone project to the south, and Nexen/Opti's Long Lake area to the east. All of these large projects are located within 30 kilometres of the assets.

The assets comprise leases and permits. The leases are valid for 15 years, the permits are valid for five years and can be converted to leases on expiry of the permit, and remain valid for an additional 15 years (20 years in total). The productive reservoir is the McMurray formation, which comprises high-quality fluvial and estuarine channel sands. Wells drilled on the assets and in immediately adjacent sections confirm the presence of the reservoir sands with oil pay thickness ranging between 12 metres and 40 metres. Bounty's reservoir mapping indicates the presence of four potential SAGD pods.

The first stage of the project will be to acquire 134 kilometres of 2-D seismic to tie the existing wells, and to delineate the size and number of potential SAGD oil sand pods. Acquisition of the 2-D seismic program will commence within the next few weeks with completion (including processing) targeted toward the end of April. An evaluation well program of up to 24 wells is planned for winter, 2007/2008, to further delineate the SAGD pods.

DeGolyer and MacNaughton has been engaged to prepare a National Instrument 51-101-compliant resource report, additional information will be released on completion of the report.

The total consideration to be provided by Excelsior comprises:


a $4.2-million bonus, a portion of which can be paid in Excelsior shares;
$8,154,300 in cash as payment of past land acquisition and related costs, a portion of which can be paid in Excelsior shares;
a payment of $1.4-million toward a 2-D seismic program; and
an estimated $5,103,000 to drill up to 24 evaluation wells.

Bounty will retain a 25-per-cent working interest in the assets.

Private placement

Excelsior is also planning to complete a non-brokered private placement. The private placement is expected to consist of 3,333,330 common shares to be offered at 30 cents per share, and 2.5 million flow-through shares to be offered at 40 cents per share to raise a total of $2-million. The proceeds will be used in conjunction with Excelsior's existing working capital to finance the initial acquisition and seismic program costs. The private placement is expected to close on or before the end of February, 2007.

We seek Safe Harbor.

[Tackler]

They got approached, someone important wants a piece of the action.

[johnlw]

I wonder why they are taking it out of Canada?

[Tackler]

The good - A portion of the proceeds of the offering may also be used to increase the company's ownership interest in its Whitesands Insitu Ltd. 84-per-cent-owned subsidiary.

The bad - The notes will be offered solely to investors outside of Canada on a private placement basis.

And the ugly - a conversion premium of 40 per cent

[johnlw]

Petrobank arranges $250-million (U.S.) debt offering

2007-04-20 06:37 ET - News Release

Mr. John Wright reports

PETROBANK ANNOUNCES LAUNCH OF CONVERTIBLE DEBT OFFERING

Petrobank Energy & Resources Ltd. intends to make an offering of up to $250-million (U.S.) in principal amount of convertible notes due 2012. The amount of the offering includes an option in respect of up to $50-million (U.S.) in principal amount of notes that Petrobank has granted to ABG Sundal Collier Norge ASA (ABG). The offering is being conducted outside of Canada through a syndicate led by ABG, and including Haywood Securities Inc. and TD Securities Inc.

The proceeds of the offering will be used for general corporate purposes, including but not limited to, expenditures on the company's Whitesands heavy oil project and an acceleration of the company's recently expanded Bakken light oil resource play in southeast Saskatchewan. A portion of the proceeds of the offering may also be used to increase the company's ownership interest in its Whitesands Insitu Ltd. 84-per-cent-owned subsidiary.

The notes are convertible into common shares of Petrobank and are expected to have an annual coupon in the range of 2.25 per cent to 3.0 per cent and a conversion premium of 40 per cent based on the volume weighted average common share price of the company on the Toronto Stock Exchange, determined on April 20, 2007. The company will have an option to call the notes after three years, should the price of the company's common shares exceed 120 per cent of the prevailing conversion price of the notes.

The notes will be issued at 100 per cent of their principal amount and, unless previously redeemed, converted or cancelled, will mature in 2012. The notes are expected to be issued on or about May 4, 2007.

The notes will be offered solely to investors outside of Canada on a private placement basis. ABG is acting as sole bookrunner for the offering. The offering is subject to certain approvals, including the approval of the Toronto Stock Exchange.

In connection with the offering, the company has amended its shareholders rights plan such that the benefits of the plan are available to holders of convertible securities, including holders of the notes. The amended shareholders rights plan will be made available on SEDAR (see Stockwatch SEDAR files).

We seek Safe Harbor.

[johnlw]

UTS Energy to JV on lease 14 with Teck


UTS Energy Corp (C:UTS)
Shares Issued 427,447,073
Last Close 4/18/2007 $4.51
Thursday April 19 2007 - News Release

Dr. William Roach reports

UTS ANNOUNCES TECK COMINCO BUYS A 50% WORKING INTEREST IN LEASE 14

UTS Energy Corp. has entered into a letter of intent with Teck Cominco Ltd. under which Teck Cominco will acquire a 50-per-cent interest in lease 14 for $200-million. Teck Cominco has had an option to acquire 50 per cent of lease 14 since 2005. The price is based on a value of $1.00 per barrel and an assumed bitumen resource for 100 per cent of lease 14 of approximately 400 million barrels. Closing of the transaction is conditional on customary conditions, including settlement of definitive documentation.

"We are very pleased to partner once again with Teck Cominco. This investment aligns UTS's and Teck Cominco's holdings into a 50:50 venture on the west side of the Athabasca River, and, we firmly believe, provides tangible benefits to both companies," said William Roach, president and chief executive officer. "This transaction has a profound impact on UTS in three fundamental ways. Firstly, it fully repays UTS's $80-million obligation to Teck Cominco for our share of the 50:50 land acquisition programs. Secondly, it effectively funds UTS's share of the joint exploration and delineation program for the next two to three years. Thirdly, and perhaps most importantly, this transaction provides a new benchmark for the value of bitumen barrels in the ground on the west side of the Athabasca River, where UTS and Teck Cominco have found substantial oil sands about six miles north of lease 14 in the lease 311 area."

The transaction is expected to close in the third quarter of 2007 with the final adjustment to take place once the full analysis of the lease 14 drilling results is complete. The purchase price may be adjusted based on the resource estimate to reflect a maximum of 500 million barrels or a minimum of 300 million barrels at $1 per barrel. This is consistent with our previously disclosed estimate contained in our annual information form. Results of the detailed core analyses and the independent engineering estimate of bitumen resources are expected by the fourth quarter of 2007.

"We believe that lease 14 contains sufficient exploitable crude bitumen resource to support a stand-alone or a satellite mining project of 50,000 barrels per day of bitumen," Dr. Roach continued, "Further, based on initial review of well logs from lease 311 and the surrounding area, we believe that we now have a significant resource base outside of the Fort Hills project."

Lease 14 is located in the Athabasca oil sands area and comprises approximately 7,147 acres (2,858 hectares) in township 98, ranges 10 and 11 W4, on the west side of the Athabasca River, and across from the northern boundary of the Fort Hills oil sands project. It is approximately 20 kilometres north of Syncrude's Aurora North operations, and a similar distance north of CNRL's Horizon project. Lease 14 is situated between Shell Canada Ltd.'s oil sands leases 9 and 17, which are at the southern end of the proposed Pierre River mine.

Lease 311 comprises approximately 11,520 acres (4,608 hectares) and is located 10 kilometres north of lease 14 in township 100, range 11 W4 in the Athabasca oil sands area. Lease 311 is owned jointly with Teck Cominco on a 50:50 basis. UTS and Teck Cominco also jointly own leases 477, 610 and 840, contiguous and directly to the north of lease 311 (comprising about 43,520 acres, or 17,408 hectares), and leases 468 and 470, contiguous and directly west of lease 311 (comprising about 10,240 acres, or 4,096 hectares).

As a result of the successes from this winter's exploration program, UTS and Teck Cominco have commenced developing preliminary plans for a program of up to 400 core holes next winter. The focus of next year's program will be to delineate lease 311 and the surrounding area comprising of leases 468, 470 and 477 extensively with approximately 300 additional core holes. A further 70 to 100 core holes will target continued evaluation of the other exploration leases which may include some drilling on jointly held insitu leases.

For additional information on leases 14 and 311, please refer to the company's annual information form filed on SEDAR.

[johnlw]

Connacher Oil and Gas Ltd (C-CLL) - News Release

Connacher Oil arranges $50-million financing

2007-04-17 16:13 ET - News Release
Shares issued 198,218,448
CLL Close 2007-04-16 C$ 4.22

Mr. Richard Gusella reports

CONNACHER ANNOUNCES BOUGHT DEAL EQUITY FINANCING

Connacher Oil and Gas Ltd. has entered into an agreement to sell, on a bought-deal basis, 5,714,300 flow-through common shares at $5.25 per share and 4,819,300 common shares at $4.15 per common share to a syndicate of underwriters led by GMP Securities LP and including Orion Securities Inc., Raymond James Ltd., HSBC Securities (Canada) Inc., Dominick & Dominick Securities Inc., Jennings Capital Inc. and Desjardins Securities Ltd. The offering will raise total gross proceeds of $50,000,170. Connacher has also granted the underwriters an overallotment option, exercisable in whole or in part for a period of 30 days following closing, to purchase up to an additional 857,200 flow-through shares and 722,900 common shares at the same offering prices indicated above. If the overallotment options are fully exercised, the total gross proceeds to Connacher will be $57,500,505. Closing is expected to occur on or about May 9, 2006.

The net proceeds of the offering of flow-through shares will be used to incur eligible Canadian exploration expenses, which will be renounced in favour of the purchasers for the 2007 taxation year. The net proceeds of the common share offering will be used for working capital purposes.

We seek Safe Harbor.

[Tackler]

More work for Ed's renters

[johnlw]

Flint wins $500M oilsands contract
Estimated contract

Ashok Dutta
Calgary Herald

Wednesday, April 18, 2007

Calgary-based Flint Energy Services has been awarded an estimated $500-million construction contract to fabricate and install a froth treatment unit to serve the phase 1 expansion of the Albian Sands project in Fort McMurray.

Albian Sands is part of the Athabasca Oil Sands Project (AOSP) expansion -- a 100,000-barrel-per-day increase in bitumen mining and upgrading facilities. AOSP is a joint venture between Shell Canada Inc. (60 per cent shareholder), Chevron Canada Ltd. (with 20 per cent stake) and Western Oil Sands Ltd. Partnership (the remaining 20 per cent interest).

The order was placed with Albian Sands Energy Inc., which operates the facility on behalf of AOSP.

"Scheduling work has been largely completed with the client and lead operator, Shell," Flint Energy's director of investor relations, Guy Cocquyt, said on Tuesday. "Onsite mobilization will start in June 1 and fabrication of the process equipment modules will commence on July 1."

The contract calls for the fabrication of 150 modules over a 10-month period. It also entails the manufacture of pipe racks and carrying out foundations, site preparations and electrical, mechanical and instrumentation works.

"We have a 70-acre facility at Sherwood Park, Edmonton and within that area there is a 150,000-square-feet under-roof module fabrication facility. The remaining area is available for onsite assembly and loading the process equipment for transportation to Fort McMurray," he said.

The facilities are due to be installed by early 2010.

Mark Friesen of Calgary-based FirstEnergy Capital said that the Albian Sands project is a significant project, with Shell Canada being fully committed to the expansion.

To keep pace with a growing order book, Flint Energy last year doubled the capacity of its fabrication yard at Sherwood Park. "Depending on contracts, we employ 300-to-500 people in our facility," Cocquyt said.

In late March, Flint Energy announced that its subsidiary - Flint Transfield Services Ltd. -- was awarded an estimated $1-billion asset management services contract by Suncor Energy for its oilsands projects in Alberta and the refinery in Sarnia.

The contract, which was awarded on a cost reimbursable basis with performance incentives, is the first of its kind to be awarded in the province's oilsands patch.

"The liability for Flint Transfield is marginal," commented Kevin Lo, energy services analyst with FirstEnergy. "They have the capability, but will need to hire more workers. That should not be a problem since the tightness (we saw earlier) in the availability of workers in Alberta has eased in the past few months."

Peter Bell, vice-president of strategy and development with Flint Transfield, said on Tuesday that by the end of 2008 his company will be looking at a work force of 1,500 through a a ramp-up from existing capacity.

"Typically, we take up orders worth $50 million-$100 million. The Suncor contract is our biggest in Canada and we will not be bidding for any more jobs until we deliver," Bell pointed out.

Flint Energy's shares were traded at $26.16 on Tuesday, 16 cents higher than the previous day.

[e-mail]
© The Calgary Herald 2007

[Rocketred]

Platform to propose name change to Alberta Oil Sands

2007-03-26 11:02 ET - News Release
Shares issued 28,817,144
PFM Close 2007-03-23 C$ 0.37


Mr. Shabir Premji reports

PLATFORM PROPOSES NAME CHANGE TO ALBERTA OIL SANDS INC. AND ANNOUNCES SIGNIFICANT ACQUISITION OF OIL SANDS LANDS

Platform Resources Inc. will propose a name change to Alberta Oil Sands Inc. at its annual general meeting to be held in May, 2007. The company will focus on the exploitation and production of an in situ Athabasca oil sands project.

The company has accumulated, over a period of time, a 100-per-cent working interest in 23 sections (14,720 acres) of contiguous oil sands rights southwest of Ft. McMurray. Total consideration paid for the lands was approximately $3-million.

The prospective oil sand zone on these lands is the McMurray formation, a sandstone layer deposited in an estuarine channel environment. The region has multiple large SAGD (steam-assisted gravity drainage) projects in various stages of development, including production and is in close proximity to existing services and infrastructure.

Further details will be disclosed in future news releases.

We seek Safe Harbor.

[johnlw]

Oilsands pipeline to U.S. a job killer: labour group
Study says 18,000 jobs in the balance

Shaun Polczer
Calgary Herald

Tuesday, April 17, 2007

The head of the Alberta Federation of Labour says TransCanada Corp.'s proposed Keystone pipeline to the United States is a job killer that needs to be stopped.

In a submission to the National Energy Board, labour federation president Gil McGowan said the proposed 3,000-kilometre pipeline to the U.S. Midwest is not in the public interest because it would export refining and upgrading jobs from Canada, where the oil is produced.

"Canadians should be getting the greatest value for their resources," he said.

"The Keystone project falls well short of providing maximum value in the areas of jobs, economic opportunity and long-term economic and energy security."

According to a study by the economic consulting firm Infometrica, the labour federation insists 18,000 jobs would be created in Canada if bitumen was refined in Alberta instead of being shipped to the U.S. on the proposed pipeline.

"If Keystone goes ahead, we will miss a once-in-a-lifetime opportunity to create a broad, healthy, value-added, and research industry centred around a rejuvenated refining industry, McGowan warned.

Instead, "billions of dollars will be spent to retool and renovate current refineries in places such as Illinois and the American Gulf Coast."

If approved, Keystone would transport some 435,000 barrels a day from Hardisty, near Edmonton, to refineries in Illinois.

In February, TransCanada received National Energy Board approval to transfer assets from its main natural gas line to a subsidiary that would operate Keystone.

In December it filed a formal application to build the line and National Energy Board hearings seeking approval to construct and operate the Canadian facilities are scheduled to begin on June 4.

TransCanada spokeswoman Shela Shapiro said the company doesn't comment on intervenor submissions or the regulatory system.

"We're aware they have filed and it's part of the process," she said.

But David MacInnis, head of the Canadian Energy Pipeline Association, said at least 450,000 barrels a day of new pipeline capacity is needed by 2009 to avert slowdowns and job losses in the burgeoning oilsands sector.

TransCanada, along with Enbridge Inc. and Kinder Morgan have put forth proposals to increase oilsands export capacity to the United States.

Although MacInnis wouldn't comment on the merits of any specific proposal, he said CEPA supports "market-backed solutions" to add new pipeline infrastructure and alleviate what he said is a looming capacity shortage.

He further suggested that upgraders planned for the Edmonton area over the next several years are threatened by a lack of skilled labour.

"With all that construction, I don't get the sense anybody is worried about losing jobs. In fact the opposite is true."

He said the labour federation's call for a moratorium on future pipeline construction would threaten oilsands growth and actually cost jobs in the long run.

"The AFL need to look in the mirror," he said.

"The short story is that these oilsands pipes create jobs. If they get their way, they will absolutely devastate the economy.

"There will definitely be shut-ins in production at oilsands plants . . . that's what's going to kill jobs."

[e-mail]

[johnlw]

Japan Canada Oil Sands presses ahead
Company aiming for 35,000 barrels a day of output
Ashok Dutta, Calgary Herald
Published: Thursday, April 12, 2007

Japan Canada Oil Sands Ltd. (Jacos) is pressing ahead with a three-year seismic and delineation program to drill more than 100 delineation wells and shoot over 65 square kilometres of new 3D seismic data at its lease in Athabasca's oilsands.

The efforts will be the first step toward setting up a commercial venture with capacity of up to 35,000 barrels per day -- and which ultimately could help the oil starved industrial giant meet its demand for energy.

With a GDP growth of 2.8 per cent, Japan imported an average 5.84 million bpd of crude oil in 2006, a number that will only increase going forward.

"We came to Canada as part of Tokyo's plans to diversify energy sources, which has been 90 per cent dependent on the Middle East for its oil imports," Brian Harschnitz, Jacos' vice-president of operations, said on Wednesday.

"Athabasca will represent one of the successes in the overall strategy."

"Forty-two delineation wells have already been drilled since the winter of 2006 and we plan to drill a similar number next year," Harschnitz indicated. "Nearly 32 square kilometres of 3D seismic data has also been acquired."

Jacos plans a staggered total investment of $50 million in the initial program, along with its partner Nexen Inc.

At the same, it is pursuing plans to debottleneck its existing oilsands demonstration plant at Hangingstone to increase steam capacity by 10 per cent.

Debottlenecking is when a project is expanded without any major modifications.

For Jacos, the project will include the installation of a 50-million-BTU boiler and modifications to the water system entailing an investment of about $10 million.

"We have just filed for regulatory approval to install the boiler. The target will be to install the facility by the third quarter," he said.

Calgary-based Jacos -- which in 1978 signed a farm-in agreement with Petro-Canada, Canadian Occidental (Nexen) and Esso (Imperial Oil) -- was the first foreign oil company to gain a foothold in the oilsands of Athabasca. Its current focus, OSL 70, is located 50 kilometres southwest of Fort McMurray and is currently home to a demonstration plant that was started in 1999.

Jacos' leases, with estimated resources of two billion barrels, are spread over 44,600 hectares and include Hangingstone, Chard, Corner and Thornbury.

Jacos -- which is 88 per cent owned by Japan Petroleum Exploration Co., five per cent by Inpex, four per cent by Mitsui & Co. and the remaining three per cent by Japanese institutions -- is the operator of the Hangingstone plant.

"Its current output is about 8,000 bpd of bitumen," he said, adding production from the facility peaked briefly at just over 9,000 bpd in 2005. "The debottlenecking process will increase the steam capacity, but we do not have any plans to cross the current approved level of 11,000 bpd of bitumen," Harschnitz said.

Initially, Jacos' focus was on delineation of the leases using core drilling holes, acquiring 2D seismic data and piloting activities. During the late 1980s to 1994, Jacos set up a demonstration plant based on the cyclical steam simulated (CSS) process.

"That was suspended in 1994, as low recoveries and steam-oil-ratio (SOR) did not demonstrate economic viability," he pointed out.

SOR is defined as the number of units of steam required to produce a single unit of oil.

Development and application of cutting-edge technology has been central to Jacos, which has in the past nearly three decades been fine-tuning various bitumen extraction methods.

"In 1999, we started a three-phase SAGD (steam-assisted gravity drainage) operation. Phase 1 utilized some of the original CSS facilities and included plant modifications and well additions," Harschnitz said.

Subsequent phases have resulted in the drilling of a total 15 horizontal well pairs and the installation of four boilers of total capacity 480 million BTUs. The results have been tangible, with current SOR rate being 3.3:1, compared with well over 10:1 earlier using CSS.

Looking ahead, Harschnitz informed that Jacos is weighing options for the development of a solvent plant that will use propane instead of steam to recover the bitumen.

"A significant cost of per-barrel production of bitumen is natural gas and new technology will certainly reduce some of the major cost components," commented Peter Howard, senior director at the Canadian Energy Research Institute. "Solvent injection, toe-to-heel and nuclear power are all options. If they come to completion, it should significantly lower per-barrel costs," he added, without giving any figures.

Drilling is also underway for seven horizontal pairs at Hangingstone at an estimated cost of $20 million. Calgary-based Akita Drilling Ltd. is the drilling partner.

"Drilling of the wells will be complete by May and we plan startup in the third quarter," Harschnitz said.

The new wells will serve to sustain bitumen production at Hangingstone.

"Technology development and delineation took us more than two decades, but we will now see the results of our patience over the coming few years," he said.

[e-mail]

[johnlw]

Mineral rights sale policies hurt communities, report says
Pembina Institute calls for halt to oilsands lease auctions

Gordon Jaremko
The Edmonton Journal

Thursday, April 12, 2007

EDMONTON - An obsolete provincial mineral rights sales system fuels the oilsands rush at the expense of Alberta communities, land, air, water and wildlife, an environmental group warned today.

The Pembina Institute for Appropriate Development, in a 42-page paper titled Haste Makes Waste, called for a halt to multibillion-dollar lease auctions until new conservation blueprints are drafted for the northern bitumen belt.

"When the government grants oilsands rights, it kick-starts exploration and development activities," the institute says.

"The decision to grant tenure and initiate this chain of events is made in the absence of public scrutiny or consideration of the economic, social and environmental impacts of doing so," the institute says.

Industry sees no need for an overhaul, saying its environmental critics overestimate the importance of mineral rights sales procedures and underestimate the strength of current regulation.

Energy markets drive the development pace including lease auctions and current internal government procedures include adequate safeguards, said Greg Stringham, vice-president of the Canadian Association of Petroleum Producers.

The Pembina Institute suggests global industry interest in the oilsands is too intense to manage with traditional mineral lease auctions.

Last year, the province sold a record 15,425 square kilometres of oilsands rights for $1.96 billion, a four-fold increase to the previous high of 3,553 square kilometres for $433 million set in 2005.

The new call for limits on mineral rights sales follows warnings that the system spells trouble by the Alberta Environmental Law Centre and the Canadian Institute for Resource Law. The centre made a case for reform at Edmonton hearings last week by a 19-member provincial oilsands policy committee.

The demand for change also follows an outbreak of conflict over bitumen deposits beneath Marie Lake, a beauty spot 300 kilometres northeast of Edmonton. Cottage owners, boaters and fishermen are fighting a marine seismic survey of mineral rights sold under the lake without consulting them first.

Industry newcomer Osum Corp. is seeking technical approval to probe 25 square kilometres of oilsands rights, 400 metres beneath the lake floor in a lease bought last fall, with echo-sounding work vessels shooting air cannons akin to equipment used in offshore exploration.

Alberta has sold a total 49,973 square kilometres of oilsands leases but it is still not too late to impose environmental order because about 100,000 square kilometres of the bitumen belt has not yet been bought up by industry, the Pembina Institute says.

"We must rethink the rate of oilsands growth in the context of the stress it places on the region's air, land and water, and the province's infrastructure, economy and social systems," says the new report.

In current mineral lease auctions, industry "nominates" or chooses properties to be put up for sale. Postings are circulated to potential buyers but not the general public.

The only inquiry into requests for sale of new development targets is done behind closed doors by a civil service group called the Crown mineral disposition review committee. It checks for established environmental restrictions and puts notices about them on the auction packages.

"The tenure regime 'puts the cart before the horse,' " the Pembina Institute says.

"The fact that project proponents already paid for and acquired mineral rights creates legal and political pressures to allow them to exercise their rights" when they make development applications to the Alberta Energy and Utilities Board.

Public reviews should be held on potential development targets before they are sold to industry, including environmental assessments and time to decide whether to create new protected areas, the institute says.

But Stringham said "there is a good balance in place right now" between industry and the public. Indefinite suspensions or delays of oilsands leasing would drive up costs and hinder projects, the CAPP vice-president said.

"A moratorium is not the way to go. The way to go is to make sure the laws are correct up front," he said. "It's really critical for environmental laws and conditions to be clear up front."

[e-mail]
© The Edmonton Journal 2007

[johnlw]

Marie Lake cottage owners say 'never' to oilsands seismic survey
Osum believes northern recreational area contains two billion barrels of oil

Gordon Jaremko
The Edmonton Journal

Monday, April 09, 2007

EDMONTON - Call it the battle of Marie Lake.

Plans to sail an industrial mini-armada onto a beauty spot 300 kilometres northeast of Edmonton, for a spring marine seismic survey of an oilsands deposit beneath the lake, has ignited furious resistance.

"Our company hears you," Osum Corp. vice-president Andrew Squires admitted after a three-hour confrontation with an angry, standing-room-only crowd in a south Edmonton hotel conference room last week.

Irate cottage owners, boaters and fishermen turned an information meeting held by the Calgary firm into a protest rally. It was the third "open house" meant to cool tempers by dispensing reassuring facts over free servings of coffee and cookies. But the community turned up the heat.

The group cheered as vocal members seized the microphone and, in the guise of asking questions, broadcast a vision of "our fish being blasted out of the water and crewmen's boots stomping on rare orchids."

The room rang with shouts of "NEVER" in reply to a company representative who asked when the survey could be rescheduled to cause the least offense against the water recreation season.

"Marie Lake is a hidden jewel," cottage owner Cliff Adams explained in an interview.

"It's hard to get to, but once you're there you never want to leave," said the retired Edmonton high school biology teacher, who has owned a Marie Lake lot since 1971.

The place is rare for Alberta. It's no stagnant prairie mosquito hatchery ringed by mud flats and tall weeds. "Marie Lake is a beautiful lake with excellent beaches and clear water," says the University of Alberta's Atlas of Alberta Lakes.

The 35 square kilometres of water,

averaging 14 metres deep, harbours 11 fish species that sustained a mink farm and occasional commercial catches

until 1981. The fish still lure recreational anglers.

But Osum is not out to win a popularity contest. "There are a lot of knowledgeable people that say there is no impact," Squires told the Marie Lake group as he refused to retreat from the planned seismic survey.

The firm is after big game, predicting its 25-square-kilometre lease on a bitumen deposit about 400 metres beneath the lake floor will turn out to contain two billion barrels of oil.

Osum stuck to its plan for 10 survey vessels to generate a three-dimensional electronic portrait of the development target with a month of marine seismic echo-sounding, including about 19,000 shots by 207-decibel air cannons.

A chainsaw makes a 117-decibel racket. A jet aircraft scores 130 on the scientific noise scale.

Jim O'Neil, a veteran biologist with the Golder Associates environmental consulting firm, sought to reassure the Marie Lake crowd. Marine seismic surveys have been done on nearly a score of Alberta lakes with no recorded ill effects, he reported.

"I've never seen a fish killed by this operation," O'Neil said. Warning shots are fired with the volume tuned just loud enough to scare fish away before the air guns make their big bangs.

Osum claims a long, impeccable pedigree for its plans.

"What we're talking about is not new technology or a science project," Squires said. "It's been proven by your own government."

His five-year-old private firm's name is short for oilsands underground mining. The company has raised funds from an array of investment institutions to dig into a thick bitumen formation beneath Marie Lake.

The project is the first attempted industrial use of a production method invented by a former Crown corporation, the Alberta Oil Sands Technology and Research Authority.

Trial runs were done in the 1980s and '90s at a site north of Fort McMurray known as UTF, for underground test facility.

The contested Marie Lake seismic survey kicks off a five- to seven-year project. It will eventually include a 500-metre vertical mine shaft, horizontal tunneling, upward sloping heat injection and bitumen flow wells into the oilsands deposit, and a pipeline and steam plant on the land surface near the lake.

The Marie Lake group continues to resist in private meetings with provincial officials. Alberta Sustainable Resource Development, which has the final say on the seismic program, did not return telephone calls.

But the fight highlighted an issue raised at Edmonton public hearings of the province's 19-member oilsands policy committee.

There is a "critical gap" in Alberta's system of selecting industrial sites, said Environmental Law Centre staff counsel Jodie Hierlmeier.

Unlike regions under federal control, such as the Northwest Territories, Alberta has no procedure for seeking public acceptance of development locations before selling mineral leases that include drilling and production rights.

In Alberta, industry "nominates" or selects oil and gas targets with requests to post them for sale at frequent auctions. A civil service group, the Crown mineral disposition review committee, checks for established environmental restrictions on the land surface involved. The work is done in private and public comment is not invited.

"Mineral tenure is the critical decision point in directing the timing, location and intensity of oilsands development," said a paper submitted to the policy committee by Hierlmeier's 25-year-old, non-profit research society.

"These decisions are made with little or no integration across (economic) sectors, and without thorough environmental reviews or direct public involvement. This process needs to be reformed," the environmental lawyers suggested.

[e-mail]
© The Edmonton Journal 2007

[oasdihf]

Petrobank Strengthens Asset Base in Bakken Light Oil Resource Play
Mon Apr 9, 4:22 AM

CALGARY, ALBERTA--(CCNMatthews - April 9, 2007) - Petrobank Energy and Resources Ltd. ("Petrobank") (TSX: PBG.TO)(OSLO: PBG) ("Petrobank") is pleased to announce a significant expansion to our southeast Saskatchewan land base highly prospective for Bakken light oil, recent Bakken drilling results, and an expansion of our Bakken light oil drilling plans for 2007 and beyond, summarized as follows:

- Excellent initial production results from recent Bakken horizontal wells

- Bakken land position increased by 137%

- Plan to expand from two dedicated horizontal drilling rigs to four in the third quarter of 2007

Emerging Bakken Resource Play

The Bakken formation is found in the Williston Basin, underlying much of North Dakota, eastern Montana and extending up into southern Saskatchewan. The Mississippian aged Bakken is an extensive regional resource play with the oil contained mostly in siltstones and thin sandstone reservoirs with low porosity and permeability. The Bakken formation is capable of high 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 of land within the defined play area.

The key to unlocking the potential in the Bakken has been advances in horizontal well techniques, particularly the application of new horizontal fracturing and completion technologies. Horizontal wells allow maximum exposure to the reservoir, and new completion techniques allow fracturing of the siltstone along the full extent of the wellbore to maximize production. These technologies have greatly improved the production and recovery potential of the Bakken and Petrobank has successfully employed an enhanced completion technique.

In 2005, we farmed-out a small portion of our lands in southeast Saskatchewan in the Bakken play in exchange for a combination of royalty interests and carried working interests. This strategy enabled Petrobank to monitor the early technical development of the play with no capital risk. Based on that vantage point, we developed an innovative drilling, completion and fracture stimulation program, which was successfully tested in the first horizontal wells drilled by Petrobank into the Bakken.

Recent Acquisitions

Late in 2005 and throughout 2006, we added to our existing 100 percent land position, and, by the end of 2006, our land base on the Bakken play stood at 62,448 (49,105 net) acres. Since the beginning of 2007, through Crown land sales and acquisitions, we have increased our acreage by a further 52,950 (52,845 net) acres to a total of 115,398 (101,950 net) acres. The majority of this increase was Crown land purchased at Saskatchewan's April 2007 land sale where we spent $59.5 million to acquire 47,285 (47,285 net) acres. We are also in the process of closing an additional acquisition and a farm-in transaction that, combined, will provide an additional 9,426 (4,813 net) earned interest acres and the potential to earn a further 13,345 (9,400 net) acres on the Bakken play through drilling. These acquisitions will increase our total potential Bakken land position to 138,169 (116,163 net) acres.

2006 / 2007 Drilling Program

Our 100 percent working interest drilling program commenced in September 2006, and seven wells were drilled by the end of 2006. The completion program for these initial wells did not begin until late November 2006 and the first four wells to be drilled, fracture stimulated and placed on production commenced at rates ranging from 200 to more than 250 barrels per day each and on average, have produced more than 12,000 barrels per well in their first three months of production. Similar results have now been observed in seven of our eight initial 100 percent wells. These results are superior to those realized by the other operators in the wells we initially farmed-out in 2005, and in numerous offsetting third party locations.

We believe that these repeated positive results are due to our horizontal drilling and fracture stimulation methodology, which allows us to avoid fracturing out of the Bakken zone, thereby minimizing associated high water production common in other recent Bakken horizontal wells. Petrobank's independent reserve evaluator, Sproule Associates Limited, currently assigns a proved, probable plus possible (3P) reserves estimate of 125,000 barrels per Bakken well. With our high initial production rates from these first 100 percent wells, we are producing in excess of the forecast type curves used in this preliminary evaluation. With continued positive performance indicators from our wells, we would contemplate updating our reserve evaluation later in 2007.

These superior Bakken production rates have allowed our Canadian Business Unit to focus the 2007 budget on our Bakken lands and we now have two rigs dedicated to the play. Following the success of our initial drilling program, we proceeded, in early 2007, to drill a series of exploration wells to determine the boundaries of the Bakken play prior to the recent Saskatchewan Crown land sale. The majority of these wells were fracture stimulated, but were not producing prior to the land sale. The post-fracture stimulation results from key wells drilled in this program were strong and consistent with our other Bakken oil producers, but the wells were not put on production in advance of the land sale for competitive reasons.

These results have allowed us to confidently pursue this land acquisition strategy, and an aggressive Bakken drilling program for 2007. Prior to spring break-up, our two rigs had drilled nine wells in 2007 and an additional two dedicated rigs are expected to be added in the third quarter of this year with a goal to drill 60 wells by the end of 2007.

All recently acquired lands are highly prospective for Bakken light oil and are expected to yield up to four horizontal wells per section. Currently, we estimate our Bakken drilling inventory at 550 (500 net) wells. With these recent acquisitions, the Bakken light oil resource play is expected to be our Canadian Business Unit's primary focus area in 2007 and for years to come. Our highly effective Bakken drilling and stimulation program, along with the addition of a significant land base at the last Crown land sale, has strategically positioned Petrobank to be a key Bakken light oil player.

Additional Canadian Business Unit Focus Areas

In addition to our Bakken light oil asset, we continue develop our long-term legacy shallow gas and CBM asset at Jumpbush with an inventory of over 175 low-risk development drilling locations. Petrobank is also aggressively moving forward on new, potentially high-impact exploration prospects in two key areas of northwestern Alberta where we will begin to test the multi-zone oil and gas potential of these areas with at least two exploration wells in 2007.

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 is operated by Petrobank's 80.7% owned, TSX-listed subsidiary, Petrominerales Ltd. (trading symbol: PMG), which produces oil through two Incremental Production Contracts in Colombia and has exploration contracts covering 1.5 million acres in the Llanos and Putumayo Basins. WHITESANDS Insitu Ltd., Petrobank's 84% owned subsidiary, owns 39,680 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(TM) heavy oil recovery process. THAI(TM) 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.

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 and technologies which remain unproven and the expected amount and timing of capital 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. 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.



Contacts

John D. Wright
Petrobank Energy and Resources Ltd.
President and Chief Executive Officer
[phone]


Chris J. Bloomer
Petrobank Energy and Resources Ltd.
Vice-President Heavy Oil and Chief Financial Officer
[phone]


Corey C. Ruttan
Petrobank Energy and Resources Ltd.
Vice-President Finance
[phone]
[phone] (FAX)
Email: [e-mail]
Website: www.petrobank.com

[Tackler]

Globe says Clarke buying trusts, plans oil sands move

2007-04-09 06:55 MT - In the News

The Globe and Mail reports in its Saturday, April 7, edition that just days after the federal government kicked the legs out from under the income trust sector, bankers were making investor George Armoyan an offer: We will raise $100-million by selling bonds so you can go shopping for stakes in battered trusts. The Globe's Boyd Erman writes that Mr. Armoyan, a specialist in broken trusts, had already made a list of targets as the carnage in the sector played out in the hours after Finance Minister Jim Flaherty's Oct. 31 announcement. He knew he was going to need more money to buy everything he wanted, so he quickly took the investment bankers from National Bank Financial and CIBC World Markets up on the offer. Since then, through his investment vehicle Clarke, Mr. Armoyan has disclosed purchases of big positions in CanWel Building Materials Income Fund, Oceanex Income Fund, Hardwoods Distribution Income Fund and TerraVest Income Fund. His next target? The oil field services sector. He has got the cash, from a bond sale and thanks to a big cheque from the recent sale of Entertainment One Income Fund.

[johnlw]

Oilsands boom vulnerable to derailment
Lack of consultation over royalty, tax changes
Gordon Jaremko, The Edmonton Journal
Published: Thursday, April 05, 2007

EDMONTON - A cornerstone of oilsands expansion will crumble if the federal and Alberta governments continue to cut support, an industry architect of the current tax and royalty regime predicted Wednesday.

"It looks like they're chipping away at a wonderful economic driver for the country," said Brad Anderson, executive director of the 180-company Alberta Chamber of Resources.

"It worries me," he said in an interview after delivering a warning that the $100-billion bitumen-project train could be derailed at Edmonton public hearings by the province's 19-member oilsands policy committee.

"Everybody's moving their own way," Anderson said.

"Where's the consultation, the shared vision?" he asked, recalling how his group, Alberta and Ottawa collaborated in a 1990s national oilsands task force to invent the royalty and tax structure that supports the development lineup.

"Ten years ago we used to phone each other and discuss things," he said. (Now) no one in Ottawa asked Alberta industry before Finance Minister Jim Flaherty cut a $300-million annual oilsands tax break in the March 20 federal budget as obsolete, Anderson added.

The move did not by itself kill any projects. But industry leaders warned it worsened existing problems that were already eroding investment support, problems such as rising construction costs, Alberta's forthcoming royalty review and the still-unknown federal plans for controls on greenhouse-gas emissions.

"I'm not sure which chip is going to be the one that does the really significant damage. They're cumulative," Anderson said.

At the policy committee hearings, environmental groups repeated calls for Alberta to abolish royalty breaks that accelerate oilsands projects.

The current royalty regime sets rates at a nominal one per cent until construction expenses are paid off then only a net 25 per cent after production costs.

A key contributor to increased project costs -- competition for limited numbers of skilled workers -- shows no signs of going away, said Lloyd Dick, executive director of the Construction Owners Association of Alberta.

The next labour demand peak hit by projects worth $100 million or more each will be an economic Mount Everest, Dick said. The summit on the construction employment horizon tops the last Alberta record set in 2005 by about 80 per cent, an association survey shows.

Requirements for skilled talent on large industrial jobs alone -- not counting big buildings or roads -- are projected to nudge or possibly exceed 36,000 in 2009-10. The last peak two years ago was about 20,000.

A recent three-year delay and cost hike for the Mackenzie Gas Project changed but did not greatly lower the anticipated labour demand peak. As the northern natural gas pipeline's schedule melted down, oilsands export pipeline projects heated up.

Dick urged the provincial policy committee to work on opening Alberta doors wider to skilled talent removing barriers against arrivals from elsewhere in Canada, encouraging immigration and recruiting temporary foreign workers.

"Employers will take an Alberta-first approach to hiring. But the reality is we will not have enough skilled trades-people to build all the projects," Dick predicted.

[e-mail]

[johnlw]

Pipelines hold key to oilsands prosperity
Opening new U.S. markets will boost prices: Pat Daniel

Shaun Polczer
Calgary Herald

Thursday, April 05, 2007

Matching Canada's growing heavy oil production with new markets is vital to gaining top dollar for natural resources, Enbridge Inc.'s chief executive said Wednesday.

In an interview with the Herald, Pat Daniel said new pipeline infrastructure is critical to achieving the best possible price for Canada's growing oil production.

"It was probably five or six years now that we started this plan to broaden out markets for Canadian heavy crude producers, long before many companies realized the need for that," he said. "We've been able to move a lot of project concepts into the construction phase."

Enbridge, which moves about two-thirds of Canada's oil output on the longest crude-oil pipeline in the world, is looking to double its liquids capacity over the next five to 10 years, Daniel said.

Thanks to a slate of new projects, Canadian producers will be able to ship oil to wider markets in California, the Gulf of Mexico and eventually, China.

"That's the premise upon which we've proposed all these projects in the first place, in that we're concerned that we've saturated the (U.S.) Midwest market with all this Canadian heavy crude, hence the crude is being heavily discounted," he said.

"We need to push the markets further south and hopefully further east in order to improve pricing."

David MacInnis, president of the Canadian Energy Pipeline Association agreed that pipelines are a "risk mitigation" tool by directing new supplies to where they're needed most.

Given the rapid pace of production increases in Western Canada, current pipelines will be completely full by 2009, MacInnis added.

"Increased pipeline access for oilsands is especially important to address differentials and diversify markets," he said.

"Without new pipeline infrastructure, the existing oil pipeline capacity will be at the maximum and new production will be shut in. It's absolutely crucial to move new supply to market. That's why it's vital to get going on those projects now."

Although Enbridge has been working on its continental "market access" strategy for the past five years, the first pieces of the puzzle were put into place with the startup of the 125,000 bpd (barrels per day) Spearhead line from Edmonton to Cushing, Okla., last March.

The impact on differentials -- quality discounts applied to Canadian heavy oil -- was instant and dramatic, initially adding an extra $10 onto each barrel sold.

According to Calgary-based oil brokerage Peters and Co. Ltd., heavy oil prices averaged about 79 per cent of benchmark light oil prices in March, compared with 63 per cent last year.

So far this year, heavy oil has received about 76 per cent of the going world price compared to 59 per cent in 2006.

Even with the improvement, Canadian oil producers are still losing $18 to $20 a barrel, Daniel said. Enbridge hopes that discount factor will fall even further with new expansions and extensions to its mainline system.

"We'd like to see that number back in the $10 to $12 range, which is where we think it should be based on a quality basis," Daniel said.

"That's going to take much broader markets to achieve."

Earlier this month, Enbridge applied for regulatory approvals to build the Canadian portion of the $1.3-billion US Southern Lights pipeline to bring 180,000 bpd of diluents to Canadian heavy oil producers.

Diluents are chemicals such as natural gas liquids used to thin bitumen and make it flow in a pipeline.

Southern Lights is a point of pride for Daniel, who points to a photograph of rail cars loaded with both large and smaller diameter pipe to be used in the project.

"It seems pretty simplistic . . . but we're underway, we're building now rather than just talking about these projects," he said.

"That's been the biggest thing over the past year, that we've moved from the planning phase to the construction phase on these new initiatives."

Southern Lights is being built in conjunction with the $1.9-billion Alberta Clipper mainline expansion as well as the $490-million Southern Access expansion/extension.

Daniel said Enbridge has enough large-diametre construction projects on the books to keep an entire steel mill busy turning out new pipe.

Alberta Clipper, which comes into service in late 2009, will initially provide an extra 450,000 bpd to Superior, Wis., which can be upgraded to 800,000 bpd.

From Superior, the Southern Access expansion will move up to 1.2 million bpd to Flanagan, Ill., while the Southern Access extension will allow an extra 800,000 bpd to flow through to refineries south of Chicago when it is fully expanded.

The first 148,000 bpd of initial capacity is scheduled to come into service in the first quarter of 2008.

Daniel said American refiners have "stepped up to the plate" by modifying existing facilities to process more Canadian heavy crude.

At one point, Enbridge was prepared to take equity positions in American refineries, but Daniel said it was no longer necessary due to the overwhelming willingness of refiners like BP and Marathon Corp. to take more Canadian feedstocks.

He further pointed to Canadian investments in U.S. refining capacity -- a la EnCana Corp.'s joint venture with ConocoPhillips -- as a positive development for expanding markets.

"If you look right now, refining margins are at an all-time high and are forecast to stay that way, so yes I think it is a good idea. Adding the ability to crack Canadian heavy crude on the front end of an existing refinery is a very good investment."

Enbridge fell three cents Wednesday on the TSX, closing at $37.66.

[Tackler]

PBG ...

[johnlw]

Raise royalty rates
Punish those oilsands millionaires giving Alberta the middle finger

By NEIL WAUGH, EDMONTON SUN




Premier Ed Stelmach was laying it on with a brick-layer's trowel at the Edmonton Chamber of Commerce lunch last week.

Either Steady Eddy is getting serious about all those city seats that Ralph Klein frittered away in the 2005 Election About Nothing, or he's feeling a little nervous about all the time he has been spending in Calgary trying to convince skeptical Cowtowners that he's the real deal.

He praised the Chuck suits for having the largest chamber in the country.

And told a joke about when Winston Churchill was spotted in the House of Commons with his fly down.

"A dead bird never falls out of its cage," Winnie reportedly shot back.

Then spoke of "the importance of Edmonton to the economic well-being of the entire country.

"In these volatile times we need a stable environment for business," Stelmach vowed. "And this government will deliver."

Unfortunately, stuck in the mail somewhere is the premier's PC leadership campaign promise to review oil and gas royalties.

And specifically the ludicrous penny-on-the-dollar oilsands royalty that was designed to stimulate investment when oil was a third of what it's worth today.

The premier talked about the balancing act he must perform coming up with a new royalty deal that is "fair to both the industry which is making tremendous investments in our province.

"And to Albertans who own the resources," he sighed.

Last week a Calgary newspaper ran a survey that determined the top seven execs of Canadian oil companies made an incredible $37.6 million in salaries, bonuses, share options and perks last year based on securities commission filings.

Some of them were cashing in their options as fast as the board of directors could dole them out.

Which pretty well cancels out the "sky is falling" cries of anguish coming out of the Canadian Association of Petroleum Producers ever since Stelmach first started talking about royalty reform and turned loose his independent commission, which has been suspiciously silent ever since.

The other reason why the patch's sweet royalty deal can't be tampered with came when the feds got in first. And took away the oilsands developers' accelerated capital allowance credit in last month's budget.

This means the Calgary millionaires may have to start paying reasonable taxes on their plants and throttle back on their massive salaries.

Now along comes a study that explodes that myth too.

In fact, the Royal Bank of Canada's latest provincial outlook report predicts the tax clawback in the budget will have "zero economic impact" in the near term.

"By the time it is fully withdrawn by 2015," the report concluded "most of the estimated $100 billion in capital projects will have been well on their way."

To the contrary, any impact on some of the projects going forward will come from future energy prices and ballooning project costs.

The report described these as a "bigger concern."

And even though the RBC economists are predicting slower growth in 2007, the numbers can be deceptive.

"The province still ranks number one in the country in virtually every economic indicator," the document states.

A recent report from Royal Lepage described Edmonton's housing market as "outperforming expectations" in the first quarter of 2007.

"The economy in Edmonton continues to be driven by continued growth in the energy sector in the oil sands," the report crowed.

He noted the in migration of skilled labourers to build the plants has resulted in "unsurpassed demand" for housing across the city.

Unfortunately that also includes cost pressures.

And it will be inflation which puts the brakes on the economy, the RBC outlook predicts. And the levelling off of energy prices.

"Drilling activity will likely slow down," the report added.

But probably more important to a premier who was talking to the C of C about "managing growth pressures" there is another dark cloud on the horizon.

"Government royalties are well past their peak," the RBC wise guys warned.

Unless, of course, the Alberta PCs cowboy up and end the oilsands madness.

And raise royalty rates to a reasonable level.

Plus punish some of those oilsands millionaires who are giving Albertans the middle finger by paying virtually no royalty and turning a huge chunk of northern Alberta into one massive strip mine then shipping the raw bitumen and high-paying jobs down the pipeline to Illinois and Texas.

[Arctec]

Environmental groups sue over Kearl project

Friday, March 30, 2007
CALGARY — A coalition of environmental groups has launched legal action in Canada's Federal Court to try to overturn recent regulatory approval of Imperial Oil Ltd.'s massive Kearl Oil Sands project in northern Alberta.

The groups, led by Sierra Legal, say the joint federal-Alberta regulatory panel “failed to do its job” when it gave conditional approval to the $7-billion Kearl open-pit mine late last month.

They argue that a full environmental review must take place before the federal government can decide whether the project should proceed.

“The panel's conclusion that a strip mine the size of 20,000 football fields with toxic sludge-filled tailings ponds visible from space will have no significant environmental effects makes a mockery of Canada's environmental assessment process,” said Stephen Hazell of Sierra Club of Canada.

Simon Dyer of the Pembina Institute environmental think-tank group said the project was approved even though the review panel acknowledged being “deeply concerned” about the failure of government to implement systems to protect the environment.

“The joint panel has rubber-stamped another oil sands mega-project in the absence of clear answers about how to restore wetlands, rehabilitate toxic tailings ponds, protect migratory bird populations, or address escalating greenhouse gas pollution,” Mr. Dyer said in a release.

The environmental groups said the regulatory panel approved the project based on “phantom” mitigation measures that are undeveloped and unproven.

And they say the panel's job is to identify measures that can be applied now to limit environmental effects of the project.

“If those measures don't yet exist, the joint panel has to advise the federal government of the true environmental costs of proceeding with the Kearl Oil Sands project,” said Sierra Legal's Sean Nixon.

The Kearl project, 70 kilometres north of Fort McMurray, is designed to include four open-pit mines and related facilities and employ 2,000 people.

It is the third major, multi-billion dollar oil sands project to be given regulatory go-ahead in the past five months.

The first phase of the project aims at producing 100,000 barrels daily, with a potential to triple that output with expansions.

Imperial and its parent company, Exxon Mobil Corp., currently have no plans to build a new upgrader in Alberta, despite the province's desire to keep more of the value-added processing work.

The approval, following three weeks of public hearings last November, imposed 17 conditions on Imperial Oil, relating to environmental and technical aspects of the project.

The panel also made eight recommendations to the federal government dealing with such environmental issues as water management and emissions technology.

It submitted 20 additional recommendations to the Alberta government, urging the province to address the lack of land, infrastructure and social resources in the booming Fort McMurray region.

[Tackler]

Platform to propose name change to Alberta Oil Sands

2007-03-26 09:02 MT - News Release

Mr. Shabir Premji reports

PLATFORM PROPOSES NAME CHANGE TO ALBERTA OIL SANDS INC. AND ANNOUNCES SIGNIFICANT ACQUISITION OF OIL SANDS LANDS

Platform Resources Inc. will propose a name change to Alberta Oil Sands Inc. at its annual general meeting to be held in May, 2007. The company will focus on the exploitation and production of an in situ Athabasca oil sands project.

The company has accumulated, over a period of time, a 100-per-cent working interest in 23 sections (14,720 acres) of contiguous oil sands rights southwest of Ft. McMurray. Total consideration paid for the lands was approximately $3-million.

The prospective oil sand zone on these lands is the McMurray formation, a sandstone layer deposited in an estuarine channel environment. The region has multiple large SAGD (steam-assisted gravity drainage) projects in various stages of development, including production and is in close proximity to existing services and infrastructure.

Further details will be disclosed in future news releases.

[johnlw]

March 28, 2007
Oilsands frontier grows
UTS drilling reveals potential of properties further north
By DINA O'MEARA, THE CANADIAN PRESS

CALGARY -- Strong initial drilling results from a new play by UTS Energy Corp. (TSX:UTS) are pushing the boundaries of Alberta's oilsands further north, and could substantially increase the company's financial standing, according to experts.

UTS's positive outlook gives rise to the possibility of opening a new oilsands area with the potential to support additional projects, Mark Friesen, with FirstEnergy Capital said yesterday.

"This has stretched land acquisitions northward, and may continue to do that," Friesen said.

However, he added, "more overriding, macro factors are going to keep excitement levels more muted than they were on land activity."

UTS, which is developing the Fort Hills oilsands project with partners Petro-Canada (TSX:PCA) and Teck Cominco (TSX:TCK), released preliminary drilling results for its Lease 14 and Lease 311 acreages in northeastern Alberta's oilsands region Monday.

The company said recent drilling results support its plans for a separate 50,000 barrel per day stand-alone oilsands mining project on Lease 14, adding an independent estimate will be released at the end of the year.

However, the lease is widely seen as an asset waiting for the proper offer, to help fund Fort Hills, the cornerstone project for UTS.

William Roach, president and CEO of UTS, said additional exploration properties recently acquired with Teck Cominco has increased UTS's net acreage to eight times what's at the Fort Hills project.

"The numbers are pretty large," Roach said yesterday. "We now have more resources outside Fort Hills than inside it, which is a pretty staggering thought looking back three years."

UTS initiated its first public offering to finance the 100,000 barrel per day synthetic crude Fort Hills project in 2004. UTS currently owns a 30% working interest in Fort Hills. Petro-Canada owns 55% and Teck Cominco the rest.

UTS expects to release final costs numbers for Fort Hills, estimated around $4 billion to $5 billion, in June. The project is expected to be commercial by mid 2011. Cost estimates of $100,000 per flowing barrel of synthetic crude are slightly below industry standards of around $110,000 per flowing barrel, mostly due to updated technology.

"The key challenge here is being able to strike the right balance between initial costs, project size and most importantly, execution risk," Roach said.

Uncertainty surrounding federal and provincial environmental regulations cloud oil sands planning, as do looming changes to provincial royalty regimes, and the elimination of tax breaks on capital investments.

High energy costs to run operations, the shortage of skilled labour and associated high costs also combine with volatile oil prices to erode investor confidence in the oil sands Roach said.

"Individually, none of these are catastrophic," he said. "But when taken together, they represent significant uncertainty just at the time we're looking for fiscal stability."

The upside is the long lifespan of oil sands projects can overcome periods of uncertainty as long as oil prices remain above US$40 per barrel, Roach said.

The company's Lease 14, 100% owned by UTS, was used as collateral in the acquisition of exploration lands with Teck Cominco.

"It is worthwhile remembering the role of Lease 14 as the asset underpinning our Fort Hills project," Roach said.

[johnlw]

UTS early results show leases 14, 311 could stand alone

2007-03-26 19:10 ET - News Release

Dr. William Roach reports

UTS ANNOUNCES PRELIMINARY DRILLING RESULTS

UTS Energy Corp. has released preliminary results from the 185-core-hole drilling program which was completed during the first quarter of 2007.

"The drilling results on lease 14 are consistent with our previous estimates and we believe are sufficient to support a 50,000 barrels per day of bitumen stand-alone mining project," said William Roach, president and chief executive officer of UTS. Dr. Roach went on to discuss the exploration program. "Early analysis of our 2007 drilling program, derived from well-log interpretation, is extremely encouraging. We recognize that these results are preliminary in nature and that we will require an extensive drilling and delineation program over the next couple of years, but the initial indications are that we have discovered sufficient resources in the lease 311 area to enable a second stand-alone project. If this is the case, then this will provide UTS with growth opportunities and flexibility going forward."

Lease 14

Lease 14, 100 per cent owned by UTS, is located in the Athabasca oil sands area and comprises approximately 7,147 acres (2,858 hectares) in Township 98, Range 10 and Range 11 W4, on the west side of the Athabasca River, and across from the northern boundary of the Fort Hills oil sands project. It is approximately 20 kilometres north of Syncrude's Aurora North operations, and a similar distance north of CNRL's Horizon project, which is currently under development. Lease 14 is also located between Shell Canada Limited's oil sands leases 9 and 17, which are at the southern end of the proposed Pierre River mine, as announced by Shell earlier this year.

Forty of the 96 core holes drilled this year on lease 14 encountered potentially minable oil sands with preliminary estimates of thicknesses of between 15 metres and 35 metres. Overburden thicknesses range from 20 metres to 38 metres. These results are based on preliminary analysis of the well-log data. A total of 124 core holes have now been drilled on lease 14, including 28 drilled in early 2006 to delineate the resource. This drilling density represents roughly one core hole per LSD over the prospective eight sections.

These results are consistent with management's belief that lease 14 contains sufficient exploitable crude bitumen resource to support a stand-alone or a satellite mining project of 50,000 bbl/day of bitumen. Results of the detailed core analyses and the independent engineering estimate of contingent bitumen resources are expected in the fourth quarter of 2007. Teck Cominco Limited has an option to acquire 50 per cent of lease 14 at fair market value.

Lease 311 and area

Lease 311 comprises approximately 11,520 acres (4,608 hectares) and is located 10 kilometres north of lease 14 in Township 100, Range 11 W4 in the Athabasca oil sands area. Lease 311 is owned jointly with Teck Cominco on a 50:50 basis. UTS and Teck Cominco also jointly own leases 477, 610 and 840, contiguous and directly to the north of lease 311 (comprising about 43,520 acres, or 17,408 hectares) and leases 468 and 470 contiguous and directly west of lease 311 (comprising about 10,240 acres, or 4,096 hectares).

Oil sands were encountered in all 33 wells drilled on lease 311, with 25 containing potentially minable oil sands with estimated thicknesses of between 15 metres and 40 metres. Overburden thicknesses range from 14 metres to 43 metres. Including the six drilled in early 2006, a total of 39 core holes have been drilled on lease 311 to evaluate the resource potential resulting in a minimum coverage of two core holes per section throughout the entire 18-section lease.

A further 34 core holes were drilled on the leases surrounding lease 311. Of these, 23 encountered potentially minable oil sands with estimated thicknesses of between 15 metres and 41 metres. Overburden thicknesses range from 30 metres to 58 metres.

Results of the detailed core analyses and the independent engineering estimate of bitumen resources are expected by the fourth quarter of 2007.

Drilling results from lease 311 and the surrounding area comprising of leases 468, 470 and 477 are very encouraging and confirm the existence of potentially minable oil sands on the west side of the Athabasca River. Early results indicate excellent potential for a significant minable oil sands resource, estimated to be between 20 and 34 sections in extent, within this geographic area.

Additionally, 22 core holes were drilled on other exploration leases also held jointly on a 50:50 basis with Teck Cominco. Results from these core holes did not find minable oil sands and will require further analysis and additional drilling to assess the prospectivity of these other leases.

Future drilling

As a result of the successes from this winter's exploration program, UTS and Teck Cominco have commenced developing preliminary plans for a program of up to 400 core holes next winter. The focus of this program will be to extensively delineate lease 311 and surrounding area comprising leases 468, 470 and 477 with approximately 300 additional core holes. A further 70 to 100 core holes will target continued evaluation of the other exploration leases.

"This is an exciting time for UTS, with the preliminary results from our winter drilling program reflecting a successful and prudent strategy of exploration and land acquisition, which has been conducted jointly with our partner, Teck Cominco, over the last year," stated Dr. Roach. "We anticipate that the continued development of these opportunities will demonstrate significant organic growth for UTS."

We seek Safe Harbor.

[johnlw]

Tory green plan will kill oilsands

Claudia Cattaneo
Financial Post

Tuesday, March 27, 2007

CALGARY - Stephen Harper, the Prime Minister, should do himself a favour and stop running around the country talking about Canada as an emerging energy superpower.

The notion may have seemed catchy a couple of years ago, when enthusiasm for energy security and national wealth assured by the oilsands still exceeded Alberta envy or the green campaign to crush their development.

Now, it's as passe as Alberta's enchantment with the federal Tories and mismatched with Mr. Harper's own actions on the environment.

Indeed, the key people in the oil-and-gas sector who were supposed to lift Canada to superpower league are instead trying to figure out how to keep their plans afloat amid a federal and provincial government assault on the sector so severe it will take very high oil prices to pay for it. If not, expect project deferrals and cancellations.

Sure, each measure adds mere nickels and dimes to the cost of producing a barrel of Canadian oil.

Together, they shrink margins that are already challenged despite high oil prices, and show our governments are willing to change the rules in return for political payback.

The biggest blow yet could land as soon as Thursday, when Mr. Harper's government is expected to unveil national targets for greenhouse-gas emissions and air pollution for the main industrial sectors.

Word in the oilpatch is that Ottawa's plan will be tougher than Alberta's, but not as stringent as the Kyoto Protocol on climate change.

Translation: Canada's oil-and-gas sector will have to pay up to meet Alberta's new regulations, and pay up even more to meet Ottawa's.

(Under Alberta's greenhouse gas regulations, announced this month, the 100 facilities that account for about 70% of the province's total emissions are required to cut emissions intensity by 12%, starting July 1, or about six months earlier than expected. Large emitters have the option of making operating improvements, buying an Alberta-based offset or contributing to a new fund that will invest in technology to reduce emissions.)

While Ottawa's plan is not expected to kick in until 2010, the two sets of regulations are likely to stack up on top of each other.

Here's the rub: The costly environmental targets are landing on top of even more government grabs, some of them already announced, others expected.

In its latest budget, for example, Ottawa cancelled the cherished accelerated capital cost allowance, a break that allowed oilsands players to defer taxation until the cost of assets was recovered from earnings. This change punishes, in particular, Canadian oilsands startups, the innovators in the sector.

Meanwhile, the government of Alberta Premier Ed Stelmach, elected in December by promising more control over oil and gas development, is reviewing oilsands royalties.

It's expected it will result in higher payments, particularly as the provincial Tories gear up for a provincial election early next year.

Then there is Ottawa's decision to change the rules on the taxation of trusts. Even if you disagree with the move, the result is that a big part of the oil-and-gas industry is now in a deep recession.

More pain is expected from Newfoundland's energy policy, expected this spring. The government of Premier Danny Williams, another Tory, is expected to increase the rent for looking for oil and gas in his province's offshore. It shouldn't come as a surprise, then, that the rig that was supposed to drill two more wells in the Orphan Basin this year, the Eirik Raude, is instead on its way to the Gulf of Mexico and it's uncertain if it will return. That's on the heels of the loss of Hibernia South and Hebron projects due to higher provincial fiscal expectations.

Meanwhile, the Mackenzie pipeline, the biggest hope for an exploration push in northern Canada, is in need of big government help that is unlikely to materialize, since Ottawa doesn't want to be seen as helping oil companies.

The stock market response has been unforgiving.

Take a look at the stock prices of Canadian oilsands companies. They have all weakened by big amounts, making them vulnerable to takeovers by foreign multinationals, as shown by the Shell Canada Ltd. minority takeout bid by its parent, Royal Dutch Shell PLC.

The most troubling outcome of our governments' assault on a Canadian success story is that it increases the price of entry, favouring deep-pocketed foreign oil giants over dozens of smaller Canadian companies that need to watch their pennies.

Oil majors will be thrilled with the fallout, which means less competition and lower costs for their own oilsands strategies.

[e-mail]

[trosh1]

Up about 30% in last 5 days.

It is not often I get a chance to return the tips I get from here and other Ihub boards. Still a risk, but close to finding out if this might give the world a lot more sweet oil from sour.

Best,
Terry

[Tackler]

Looks like BMD may break out...

http://www.investorshub.com/boards/read_msg.asp?message_id=17421274

[trosh1]

Thought I'd mention SUF...

In oils, I'm currently down to PBG (nice), DPTR (been good but bit a bit last few months), and SUF.

SUF has been a long term pain for me with Gunnermans running things, but I thought they might actually have something and have kept some in it. That changed big time recently! Gunnermans out and competent mgm now at the helm. Been waiting to see if it is real and has the goods. Looks like it, and have begun to add.

For those of you that remember its potential, we should know in the next 1-2 mo. Might be a good time to look at re-entry with not-so-mad money anymore. (Just slightly crazy.)

Best,
Terry

[Tackler]

Diluting 5% but market missed reserves increase by 15%, also...

To date, the heavy oil business unit's reserves are still based on SAGD technology as it is the presently recognized technology used to define in situ oil sands reserves and resources. This does not reflect the technical merits of the THAI process; it is simply the only way for the company to presently recognize a portion of its reserve and contingent resource potential on the Whitesands leases using industry-accepted norms. Once McDaniel's can independently certify reserves and contingent resources associated with the THAI process, this SAGD-based analysis will be phased out. Given the estimated gross discovered resources of bitumen in place on the company's oil sands leases of 2.6 billion barrels and the improved recoveries expected from using its THAI process, management expects this to result in a significant increase in recoverable bitumen.

[johnlw]

Some sloppy reporting on their part:

There has been an additional increase in the McDaniel and Associates Consultants Ltd. estimated gross discovered resources of bitumen in place on Petrobank Energy & Resources Ltd.'s oil sands leases to 2.6 billion barrels. This represents a 400-million-barrel increase over the preliminary estimate announced in Stockwatch on March 13, 2007, and a 1.0-billion-barrel increase from the 1.6 billion barrels announced in May, 2006. This increase does not change the reserves and contingent resource estimates, summarized below, but does indicate the significant potential to add additional recoverable volumes through exploitation using the THAI process.

Petrobank Energy & Resources Ltd (C-PBG) - News Release

Petrobank Energy corrects financial highlights table

2007-03-13 12:32 ET - News Release
Shares issued 72,125,274
PBG Close 2007-03-12 C$ 24.28

Mr. John Wright reports

PETROBANK ANNOUNCES CORRECTION TO YEAR END RESULTS

Petrobank Energy & Resources Ltd. would like to correct the financial and operating highlights table contained in its news release issued earlier today. Net income of $2.4-million (three cents per share on a diluted basis) reported for the three months ended Dec. 31, 2006, should have read $2.62-million (four cents per share on a diluted basis), a decrease of 49 per cent (50 per cent on a per diluted share basis) from the fourth quarter of 2005. Basic net income per share and net income for the year ended Dec. 31, 2006, are unchanged. Net income for the year increased 80 per cent from $12.8-million in 2005 to $23.1-million in 2006.

And then throw in a new financing to boot.

[oasdihf]

Here's the NR I guess:

Petrobank Announces Increase in Bitumen-In-Place and Bought Deal Financing

08:27 EDT Monday, March 19, 2007

CALGARY, ALBERTA--(CCNMatthews - March 19, 2007) -

NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES

Petrobank Energy and Resources Ltd. (TSX:PBG) (OSLO:PBG) ("Petrobank") is pleased to announce an additional increase in the McDaniel and Associates Consultants Ltd. estimated gross discovered resources of bitumen-in-place on our oil sands leases to 2.6 billion barrels. This represents a 400 million barrel increase over the preliminary estimate announced on March 13, 2007 and a 1.0 billion barrel increase from the 1.6 billion barrels announced in May 2006. This increase does not change the reserves and contingent resource estimates, summarized below, but does indicate the significant potential to add additional recoverable volumes through exploitation using the THAI(TM) process.

Petrobank is also pleased to announce that it has entered into an agreement with a syndicate of investment dealers, led by Haywood Securities Inc. and including TD Securities Inc., FirstEnergy Capital Corp., and Fraser MacKenzie Ltd. (collectively, the "Underwriters") pursuant to which the Underwriters have agreed to purchase for resale to the public, on a bought deal basis, an aggregate of 4,000,000 common shares (the "Common Shares") of Petrobank at a price of $21.00 per Common Share resulting in gross proceeds of $84.0 million (the "Offering"). Petrobank will use the proceeds of the Offering initially for the repayment of debt and for general corporate purposes.

The Offering is subject to certain conditions including standard regulatory approvals. The Common Shares will be offered in all the provinces of Canada, other than Quebec, by way of a short form prospectus. Closing is anticipated to occur on or about April 5, 2007.


SUMMARY OF CORPORATE RESERVES/RESOURCES AND NPVs BY BUSINESS UNIT

Working Interest Reserves, Forecast Prices

                                             Latin                   Total 
                                Canada(1) America(1) Heavy Oil(2) Company(3) 
                                   (mboe)    (mbbls)      (mbbls)     (mboe) 
                                --------- ---------- ------------ ---------- 
 Developed Producing               3,050      3,947            -      6,236 
 Total Proved                      6,675     13,563            -     17,624 
 Proved + Probable                 9,148     24,531       25,290     50,195 
 Proved + Probable + Possible 
  (3P)                            12,726     33,906       70,323     99,170 
 Best Estimate Contingent 
  Resources (4)                        -          -      574,060    482,210 
 3P + Best Estimate Contingent 
  Resources                       12,726     33,906      644,383    581,380 
  
 Net Present Values, Before Tax - Working Interest Reserves, Forecast Prices 
 (Cdn.$ millions) 
  
                                              Latin                   Total 
                                Canada(1) America(1) Heavy Oil(2) Company(3) 
                                --------- ---------- ------------ ---------- 
 Developed Producing                81.0      155.8            -       206.8 
 Total Proved                      110.4      368.7            -       408.1 
 Proved + Probable                 150.2      608.1        (24.7)      620.4 
 Proved + Probable + Possible 
  (3P)                             193.9      789.7        176.1       979.3 
 3P + Best Estimate Contingent 
  Resources                        193.9      789.7      1,008.0     1,678.1 
  
 (1) NPV 10%, Latin America includes 100% of Petrominerales' reserves in 
     Colombia, NPVs converted at US$1 = Cdn.$1.1653, no reserves have been 
     booked on the Company's exploration blocks. 
 (2) Represents 100% of WHITESANDS Insitu Ltd.'s reserves and best estimate 
     contingent oil sands resource as at March 1, 2007 based on SAGD 
     technology, NPV 8%, forecast bitumen dilbit netback price case. 
 (3) Total Company includes Canadian Business Unit reserves at December 31, 
     2006, Petrobank's 80.73% share of the Latin American Business Unit's 
     reserves as December 31, 2006, and the Company's 84% share of WHITESANDS 
     Insitu Ltd. reserves as at March 1, 2007 representing the Heavy Oil 
     Business Unit. 
 (4) Contingent resources, as evaluated by McDaniel, are those quantities of 
     bitumen estimated to be potentially recoverable using SAGD technology 
     from known accumulations but are classified as a resource rather than a 
     reserve primarily due to the absence of regulatory approvals, detailed 
     design estimates and near term development plans and are in addition to 
     3P reserves. Best estimate (P50) means most likely. 
 

The full reserve disclosure tables, as required under National Instrument 51-101, will be contained in Petrobank's 2006 Annual Information Form, which will be filed on SEDAR on or before March 31, 2007.

To date, the Heavy Oil Business Unit's reserves are still based on SAGD technology as it is the presently recognized technology used to define in-situ oil sands reserves and resources. This does not reflect the technical merits of the THAI(TM) process; it is simply the only way for the Company to presently recognize a portion of our reserve and contingent resource potential on the WHITESANDS leases using industry accepted norms. Once McDaniel's can independently certify reserves and contingent resources associated with the THAI(TM) process, this SAGD-based analysis will be phased out. Given the estimated gross discovered resources of bitumen-in-place on our oil sands leases of 2.6 billion barrels and the improved recoveries expected from using our THAI(TM) process, we expect this to result in a significant increase in recoverable bitumen.

The discovered resources of bitumen-in-place represents 100% share of WHITESANDS Insitu Ltd's Whitesands Lease, with Petrobank Energy and Resources owning 84% of WHITESANDS Insitu Ltd. The Canadian Oil and Gas Evaluation Handbook (COGEH) defines discovered resources as those quantities of oil and gas estimated on a given date to be remaining in, plus those quantities already produced from, known accumulations. Discovered resources are divided into recoverable and unrecoverable categories, with the estimated future recoverable portion classified as reserves and contingent resources.

THAI(TM) has many potential benefits over SAGD including expected higher resource recovery (70%-80% versus 30%-50% for SAGD), 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(TM) process also has the potential to operate in lower pressure, lower quality, thinner and deeper reservoirs than current steam-based recovery processes. The continued field demonstration of THAI(TM) is expected to have an enormous impact of on resource recovery and estimates of reserve and contingent resource volumes.

With the completion of our additional resource delineation we are moving forward with plans that include: plant de-bottlenecking to enable the wells to produce at higher capabilities and at higher on-stream factors; an expansion of the current facilities to accommodate up to three new wells incorporating the CAPRI(TM) technology; further resource delineation; and the regulatory application, design and construction of an additional 10,000 barrel per day project. The cost to complete these plans is estimated to be up to $200 million.

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 along with light oil resource plays in southeast Saskatchewan, complemented by new exploration projects and a large undeveloped land base. The Latin American Business Unit is operated by Petrobank's 80.7% owned, TSX-listed subsidiary, Petrominerales Ltd. (trading symbol: PMG), which produces oil through two Incremental Production Contracts in Colombia and has exploration contracts covering 1.5 million acres in the Llanos and Putumayo Basins. WHITESANDS Insitu Ltd., Petrobank's 84% owned subsidiary, owns 39,680 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(TM) heavy oil recovery process. THAI(TM) 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.

Natural gas volumes have been converted to barrels of oil equivalent ("boe") so that six thousand cubic feet ("mcf") of natural gas equals one barrel based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. Boes may be misleading, particularly if used in isolation.

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 and technologies which remain unproven and the expected amount and timing of capital 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. 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.

This press release shall not constitute an offer to sell or the solicitation of an offer to buy the securities in any jurisdiction. The shares offered have not and will not be registered under the United States Securities Act of 1933, as amended, or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirement.

FOR FURTHER INFORMATION PLEASE CONTACT:

Petrobank Energy and Resources Ltd.
John D. Wright
President and Chief Executive Officer
[phone]

[oasdihf]

That's odd:

Issuer Name: Petrobank Energy and Resources Ltd.
TSX Ticker Symbol: PBG
Time of Halt: 08:37 EST
Reason for Halt: Dissemination of News

and five minutes later:

Market Regulation Services - Trade Resumption - Petrobank Energy and Resources Ltd. - PBG
Monday March 19, 8:52 am ET

[johnlw]

Oilsands fear tax program may end
Budget watch on over capital cost allowances

Geoffrey Scotton
Calgary Herald

Monday, March 19, 2007

Oilsands and mining industry officials expect a firestorm of outrage from westerners and the Alberta government if Ottawa moves in today's federal budget to chop the Accelerated Capital Cost Allowance for oilsands projects -- a step some environmentalists and opposition parties are calling for.

"We're concerned. It would have a devastating impact," Canadian Mining Association vice-president of economic affairs Paul Stothart said Friday, arguing any potential change is being driven by politics generally and the politics of climate change.

"It would be a fairly shocking thing for a government to do that has a strength in Alberta. They may be doing some political calculations," Stothart suggested.

"My sense is that if they were to remove it, they would remove it from the oilsands projects because of an environmental and climate change rationale. It would be opening a can of dynamite in Western Canada, no question about it, because it's a pretty provocative thing to do."

It's unlikely the Alberta government would accept such a decision. The ACCA is part of a landmark federal-provincial oilsands tax policy package that grew out of the National Oilsands Task Force in the mid-'90s to spur oilsands development.

"It is part of that original deal. The province's position is that it is still an integral part of oilsands development," said Jason Chance, a spokesman for Alberta Energy Minister Mel Knight. "It's one part of continued development and investment in oilsands, which benefits not only Alberta, but the entire country."

Chance noted that the Canadian Energy Research Institute has estimated that 41 per cent of the $123 billion in government revenue expected from the oilsands between 2000 and 2020 will go to Ottawa, by far the largest share.

"Fifty-one billion (dollars) of that will go to the federal government, higher than the percentage that is going to the Alberta government, 36 per cent or $44 billion. So there are benefits to the entire country," Chance said.

The original program, in place since 1974 and extended to oilsands in situ projects in 1997, allows revenue-earning firms that mine -- including oilsands mining and in situ production -- to deduct capital investment to reduce taxes. Over time those deductions are reduced and taxes payable rise.

The ACCA deferral acknowledges that very large amounts of money are invested for long periods of time in oilsands projects before a return in seen, and make financing easier to obtain.

Critics of the oilsands industry and its production of so-called greenhouse gases have labelled the ACCA a subsidy. However, the tax deferral mechanism is revenue neutral over time and applies to all types of mining, not just oilsands, including other types of energy production.

Nonetheless, pressured by environmentalists and the opposition parties, some believe the government may move to end the measure as it applies to oilsands projects in today's budget to attract votes in riding-rich Ontario and Quebec.

"If there would be one worry we would have for Monday, it would be that it's targeted only at the oilsands, which would then not be fair because they would leave it in place for the rest of the mining sector," said Canadian Association of Petroleum Producers vice-president Greg Stringham .

Stringham said the ACCA program is "critical" to the health of the oilsands sector and noted the oil and gas industry paid $27 billion in taxes and royalties in 2006. Investment in the oilsands is expected to hit $12.5 billion this year, up from $11 billion in 2006.

"In particular for small mining companies, whether they be oilsands or otherwise, the fact that they can actually get their capital paid off first and then start paying taxes later means that they're able to attract financing to be able to do that," said Stringham. "Without that, financing would be much more difficult."

Some observers have also noted that if the ACCA is axed for oilsands projects, it could impact the value of oilsands leases. That in turn would be likely to lower the provincial government's take in land sales, which nets Alberta billions of dollars each year.

[johnlw]

Western seen as next Shell target
Takeover successful: More deals for Royal Dutch in oilsands: analyst

Jon Harding
Financial Post

Monday, March 19, 2007

CALGARY - With Royal Dutch Shell PLC well on its way to consolidating its Canadian oilsands assets, the Anglo-Dutch super major's next step could involve deals or takeovers of oilsands players in need of refining access.

A logical target, one analyst said yesterday in the wake of Royal Dutch's successful takeover of Shell Canada Ltd. late on Friday, could be Athabasca Oil Sands Project partner Western Oil Sands Inc., a company now looking for exactly what Royal Dutch's oilsands strategy offers.

"I don't think for a second that Royal Dutch is done buying assets in Western Canada," said the Calgary-based analyst. "They were able to pay a lot of money for Shell Canada because they can extract value out of the company that Shell Canada couldn't have got on its own," he said.

"That value is ? instead of building expensive upgraders in Alberta, having the flexibility to move the bitumen to the Gulf Coast or even maybe, at some point, the West Coast. And all those synergies that they can get out of Shell Canada, they'll be able to get out of a Western Oil Sands or any other bitumen asset."

Over the weekend, Royal Dutch's ownership of Shell Canada climbed to 89.6% from 78% as Canadian shareholders accepted the parent's $8.7-billion, $45-a-share bid to turn Shell Canada private.

The Hague-based Royal Dutch said 53.1% of minority shareholders tendered their Shell Canada stock before Friday night's 8 p.m. ET deadline, surpassing a minimum condition of 50% and all but ending a contentious process that began with last October's offer by Royal Dutch of $40 a share.

The bid was upgraded to $45 in January and was still seen as too low by several large Canadian investors.

In addition to announcing its successful takeover, Royal Dutch extended its $45 offer to March 30 to pick up the remainder of the Shell Canada minority shares.

Royal Dutch, which is expected to run all of its North American operations from Houston, now controls Shell Canada assets such as its stake in the Sable Island offshore natural gas project and Shell Canada's piece of the $16.2-billion Mackenzie Valley natural gas pipeline project.

It also gets a bigger piece of the Athabasca Oil Sands Project, an expanding mining development north of Fort Mc- Murray, Alta., with upgrading and refining operations near Edmonton. Shell Canada holds a 60% stake in the project, where output is expected to grow fivefold toward 770,000 barrels of oil a day. Chevron Corp. and Western are each 20% partners, but their access to the upgrading business hits a cutoff point at the end of the next expansive expansion phase, due to take production from about 155,000 barrels a day today to 255,000 by 2010 at a cost of up to $12.8-billion.

That circumstance, the analyst said, is part of the reason why Western now is on the block and a potential Royal Dutch target. Western has already hired advisors to help it look for strategic alternatives that could include its outright sale, the signing of a supply agreement with a U.S. refinery or partnership to build an upgrader.

"Those are the synergies a big company with U.S. refining assests can get out of the oilsands," the analyst said.

Last November, Western said it had not received an offer for the company, nor was it in any discussions. But last week it took the unusual step of pushing back its annual shareholders' meeting by a month to June 12 without giving any reason, a move interpreted by investors as a sign some kind of deal could be in the offing.

With Shell Canada in hand, Royal Dutch chief executive Jeroen van der Veer suggested the buyout was just part of what lies ahead in Canada, where Royal Dutch is in the process of building an "integrated unconventional oil business on an international scale.

"This is a positive outcome, and a further step toward building on our strong position in Canada, using the strengths that only a company of our global scale can bring," he said in a release on Saturday.

Royal Dutch Shell spokeswoman Alexandra Wright said yesterday the company expects the transaction to close in the second quarter. She also said if Royal Dutch winds up with less than 90% of the Shell Canada shares by the new March 30 expiry date, a meeting of Shell Canada shareholders would be called to finalize the deal with a vote, which, given the number of shares secured, Royal Dutch "is certain" would be in favour.

"If we end up with more than 90% of the shares, we may be able to use a shorter process [to legally finalize the deal]," Ms. Wright said.

[e-mail]

[kraftdinner]

Royal Dutch Shell PLC on verge of Shell Canada takeover
By DAVID EBNER, Globe and Mail Update




CALGARY — Royal Dutch Shell PLC is on the verge of taking over Shell Canada Ltd., announcing early Saturday morning that it has scored a significant victory in its $8.7-billion bid for the firm.

Royal Dutch, one of the largest public oil companies in the world, already owns about 78 per cent of Shell Canada and is trying to buy the rest. In a press release issued early Saturday morning, Royal Dutch said that about 97 million shares were tendered to its $45 a share offer, which was put forth in January. The shares represent about 53 per cent of the minority stake in Shell Canada.

Royal Dutch had said its offer was contingent on attracting more than half of the minority. With the new shares in hand, Royal Dutch is in a position to take control of the rest of the shares.

Several large minority shareholders, led by Jarislowksy Fraser Ltd., said the $45 a share offer was inadequate and said they would refuse to tender their shares. However, now that Royal Dutch controls about 90 per cent of all the shares of Shell Canada, it is in the position to squeeze out the remaining dissident investors to take over the company completely. Shell Canada stock will likely be delisted from the Toronto Stock Exchange and the company would likely stop issue independent financial reports.

Royal Dutch is buying the rest of Shell Canada for its position in the oil sands. Royal Dutch wants to export the raw output from the oil sands to process the material into gasoline and other products in the United States and internationally.

“This is a positive outcome, and a further step towards building on our strong position in Canada, using the strengths that only a company of our global scale can bring. This is an opportunity to create an integrated unconventional oil business on an international scale,” Jeroen van der Veer, chief executive officer of Royal Dutch, said in a press release.

Royal Dutch, which has struggled badly in the past several years, decided in October to bid for Shell Canada, offering $40 a share of $7.7-billion for the part of Shell Canada it did not own.

That bid was met with derision by many shareholders and wasn't endorsed by Shell Canada's board of directors. But after negotiations, Shell Canada's board endorsed the $8.7-billion, $45 a share offer put forth in January.

Royal Dutch's offer had been set to expire at 8 p.m ET on March 16. The company said early Saturday that it was extending its offer until March 30 at 8 p.m ET for investors who have not sold their shares.

Dissent investors have previously told The Globe and Mail that they would take Royal Dutch to court if the $45 offer succeeded, arguing that the bid undervalues Shell Canada. However, such cases are difficult to win. When the majority of investors tender their shares to a bid, courts generally conclude that such deals are considered fair.

Capital Research & Management Co. is likely the key investor behind the scenes. The Los Angeles-based money manager controls almost $1-trillion and is the largest shareholder of Royal Dutch. It is also among the largest Shell Canada investors. Capital Research was believed to support the deal.

After the October offer, a number of Shell Canada shares went into the hands of hedge funds, most of which are short-term investors. One New York hedge fund source, which owned about one million Shell Canada shares, told The Globe on Thursday that most hedge funds were ready to sell their holdings to Royal Dutch rather than wait for a potentially higher bid.

Royal Dutch had threatened to walk away if the $45 offer was rejected, suggesting it had better options elsewhere. It has had problems elsewhere, however. In December, the Russian government forced the company to sell its majority stake in a huge energy development in the country to OAO Gazprom, which is controlled by the Kremlin.

Financial analysts had said Shell Canada stock, which closed at $44.68 on the Toronto Stock Exchange on Friday, could fall to about $30 is Royal Dutch revoked its offer.

Shell Canada stock's all-time high is about $47, reached in January, 2006.

For Shell Canada, the takeover ends a long history in Canada. The subsidiary of Royal Dutch was created in Canada in 1911 with capital of only $50,000, about $1-million in current currency. Its first business was selling gasoline in Montreal.

In 1944, it discovered a major natural gas field at Jumping Pound west of Calgary, between the city and the Rocky Mountains. In 1957, Shell found the Waterton gas field in southeastern Alberta, one of the largest in Canadian history.

Shell Canada is expected to be subsumed by Royal Dutch's sprawling international operations. Its natural gas business in Canada could be sold, industry sources in Calgary have speculated. It is expected that Shell Canada will be run from Houston, which is the headquarters of Royal Dutch's business in the United States.

Shell Canada owns 60 per cent of the Athabasca oil sands project, which began operation in 2003 and is designed to produce 155,000 barrels of bitumen a day. An expansion to add 100,000 more barrels a day is underway, budgeted at as much as $12.8-billion. Shell Canada has said its goal is to reach more than 700,000 barrels a day in the oil sands.

[trosh1]

PBG news not exciting but...

Still my biggest oil. The earnings and NG developments weak but solvable and short term. This too shall pass.

THAI, of course, is my biggest interest. It continues to go well and I think it is only a matter of time before it makes us even happier.

Looking to get back into UPL when people realize we are not looking good for the future in NG. SU when I get bored with U. Could be awhile. :)

Cheers,
Terry

[johnlw]

Cdn Oil's Syncrude to remove coker build-up

2007-03-13 17:05 ET - News Release

Mr. Marcel Coutu reports

SYNCRUDE TO PERFORM MAINTENANCE ON COKER 8-3

Canadian Oil Sands Trust's Syncrude plans to perform maintenance on Coker 8-3 to remove coke residue build-up within the vessel. Following several weeks of analysis regarding the coker's performance, Syncrude believes this residue has led to fouling within the coker reactor, resulting in constrained production rates from the unit since late 2006. Syncrude anticipates that the work will occur during the second quarter of 2007.

Coker 8-3 is Syncrude's newest coker and came on stream in 2006 as part of the stage 3 expansion. The company had expected that a period of optimizing the performance of the new stage 3 operating units would be required before it could ramp up to total productive capacity of 350,000 barrels per day, gross to Syncrude.

Syncrude is in the process of rescheduling the turnarounds for its original cokers with the turnaround planned for the fall of 2007 possibly being postponed to early 2008. The decision to proceed with the maintenance work on Coker 8-3 in the second quarter is expected to enable the coker to return to service at higher production rates, which will allow Syncrude to reduce throughput on the other cokers and thereby extend their run lengths. It expects the modifications to the new hydrogen plant steam-generation system will be performed as planned in the fall of 2007, which should enable Syncrude to transition all of its production volumes to the higher Syncrude sweet, premium-quality level by the fourth quarter of this year.

Canadian Oil Sands is maintaining its current production estimate for Syncrude of 110 million barrels annually or 40.4 million barrels net to the trust. This estimate is based on quarterly production of 27 million barrels in the first quarter, 23 million barrels in the second quarter, 30 million barrels in the third quarter and 30 million barrels in the fourth quarter. This quarterly production outlook has been revised from the breakdown provided in its Jan. 29, 2007, guidance document. It has also reduced the top end of its annual production range from 120 million barrels to 115 million barrels, gross to Syncrude, to reflect the reduced likelihood of achieving higher-than-expected operational reliability and stability. The low end of the range has been maintained at 105 million barrels as the possibility of an additional coker turnaround continues to exist, particularly given the uncertainty in postponing the fall 2007 turnaround. The current production range estimate, net to the trust, is 39 to 42 million barrels.

Non-resident ownership declines to 33 per cent

Based on information from the statutory declarations by unitholders, it estimates that, as of Feb. 8, 2007, approximately 33 per cent of its unitholders are non-Canadian residents with the remaining 67 per cent being Canadian residents. The Canadian Oil Sands Trust indenture currently provides that not more than 49 per cent of its units can be held by non-Canadian residents.

The trust continues to monitor its foreign ownership levels on a regular basis through declarations from unitholders, and posts the results of the declarations on its website under investor information, frequently asked questions. This section of the website and page 45 of the management's discussion and analysis section of the trust's 2005 annual report describe the trust's steps for managing its non-Canadian, resident-ownership levels.

Canadian Oil Sands Trust provides a pure investment opportunity in the oil sands through its 36.74-per-cent working interest in the Syncrude project. Located near Fort McMurray, Alta., Syncrude operates large oil sand mines and an upgrading facility that produces a light, sweet crude oil.

We seek Safe Harbor.

[johnlw]

Petrobank Energy earns $23.1-million in 2006

2007-03-13 08:05 ET - News Release

PETROBANK ANNOUNCES YEAR END RESULTS, RESERVES AND BOARD CHANGES

Petrobank Energy & Resources Ltd. has released the year-end financial and operating results, along with the results of its year-end reserve evaluations.

Highlights:

Petrobank entered 2006 with an excellent portfolio of opportunities and a solid base of production and reserves. Some of the highlights of 2006 include the following:

* funds flow from operations more than doubled to $61.4-million from $29.2-million in 2005;
* net income increased 80 per cent to $23.1-million from $12.8-million in 2005;
* consolidated conventional production increased 53 per cent from 3,451 barrels of oil equivalent per day in 2005 to 5,269 barrels of oil equivalent per day in 2006;
* conventional production from the Canadian business unit increased 27 per cent to 3,075 barrels of oil equivalent per day from 2,420 barrels of oil equivalent per day in 2005 and increased further to 4,192 barrels of oil equivalent per day in the first two months of 2007;
* Latin American business unit production more than doubled to 2,194 barrels of oil per day;
* the heavy oil business unit completed construction and initiated combustion and production from the world's first Thai project at Whitesands;
* oil sands acreage under lease expanded to 62 sections.
* heavy oil business unit's 3P reserves plus best estimate contingent recoverable bitumen resources increased by 48 per cent from the first evaluation dated May 1, 2006, to 644.4 million barrels (as at March 1, 2007).
* conventional Canadian 3P reserves totalled 12.7 million barrels of oil equivalent at Dec. 31, 2006;
* Latin American business unit 3P reserves totalled 33.9 million barrels at Dec. 31, 2006.
* Petrominerales Ltd., the company's Latin America business unit, completed its initial public offering in June, 2006. Petrobank retains an 80.7-per-cent ownership stake;
* Petrominerales amassed a 1.5-million-acre exploration land base in Colombia's highly prospective Llanos and Putumayo basins; and
* in early 2006, Petrobank listed on Norway's Oslo Stock Exchange in connection with a $33-million offering.

            FINANCIAL AND OPERATING HIGHLIGHTS 
                           (thousands of dollars) 
  
                          Three months ended             Years ended 
                                     Dec. 31,     %          Dec. 31,     % 
                                 2006   2005 change     2006    2005 change 
  
 Oil and natural gas revenue   25,729 22,510     14   99,228  65,081     52 
 Funds flow from operations(1) 16,057 12,304     31   61,425  29,152    111 
 Per share -- basic ($)          0.24   0.20     20     0.92    0.50     84 
 Per share -- diluted ($)        0.23   0.19     21     0.89    0.49     82 
 Net income                     2,400  5,184    (54)  23,106  12,808     80 
 Per share -- basic ($)          0.04   0.08    (50)    0.35    0.22     59 
 Per share -- diluted ($)        0.03   0.08    (63)    0.33    0.21     57 
 Capital expenditures          71,337 58,436     22  229,693 118,152     94 
 Net debt(2)                   40,545 60,808    (33)  40,545  60,808    (33) 
 Operations(3) 
 Canadian operating netback 
 ($/boe except where noted) 
 Oil and NGL revenue ($/bbl)(4) 54.83  62.35    (12)   61.18   60.96      - 
 Natural gas revenue ($/mcf)(4)  6.15  10.36    (41)    6.21    8.09    (23) 
 Oil and natural gas revenue(4) 43.86  62.21    (29)   44.40   50.84    (13) 
 Royalties                       4.47  13.00    (66)    6.28   10.46    (40) 
 Production expenses             8.06   5.07     59     6.89    6.05     14 
 Transportation expenses         0.27   0.53    (49)    0.39    0.98    (60) 
 Operating netback              31.06  43.61    (29)   30.84   33.35     (8) 
 Colombian operating 
 netback ($/bbl) 
 Oil revenue                    57.68  52.50     10    61.68   53.62     15 
 Royalties                       4.61   4.20     10     4.95    4.29     15 
 Production expenses             8.39  10.08    (17)    7.78    9.49    (18) 
 Operating netback              44.68  38.22     17    48.95   39.84     23 
 Average daily 
 production 
 Canada -- oil and NGL (bbl)    1,265    662     91      918     452    103 
 Canada -- natural gas (mcf)   11,968 14,792    (19)  12,940  11,810     10 
 Total Canada (boe)             3,260  3,127      4    3,075   2,420     27 
 Colombia -- oil (bbl)          2,372    955    148    2,194   1,031    113 
 Total company (boe)            5,632  4,082     38    5,269   3,451     53 
 Reserves/resources by 
 business unit(5) 
 Heavy oil (mbbl) --  
 84 per cent                  541,282      -      -  541,282       -      - 
 Canadian (mboe)               12,726 16,188    (21)  12,726  16,188    (21) 
 Latin American -- 
 Colombia (mbbl) --  
 80.73 per cent                27,372 22,263     23   27,372  22,263     23 
 Total company (mboe)         581,380 38,451  1,412  581,380  38,451  1,412 
 

(1) Calculated based on cash flow from operations before changes in other
non-cash working capital and asset retirement obligations settled.
(2) Includes working capital (deficiency), bank debt and subordinated
notes.
(3) Six mcf of natural gas is equivalent to one barrel of oil equivalent
(boe). Bitumen volumes are excluded from average daily production as
Whitesands operations are considered to be in the development stage and
accordingly are capitalized.
(4) Canadian sales prices are shown after transportation and forward gas
sales contracts.
(5) Company working interest proved plus probable plus possible reserves
and contingent recoverable resources (best estimate) excluding royalty
interest reserves and before deduction of royalties payable. The heavy
oil business unit represents information effective as of March 1, 2007.
Only represents Petrobank's 84-per-cent share of the heavy oil business
unit's (Whitesands Insitu Ltd.) reserves and Petrobank's share (80.73
per cent at Dec. 31, 2006, and 100 per cent at Dec. 31, 2005) of the
Latin American business unit's (Petrominerales Ltd.) reserves.

CORPORATE RESERVES/RESOURCES SUMMARY BY BUSINESS UNIT
working interest reserves, forecast prices

                   Canada   Latin America  Heavy oil   Total company 
                           (mboe)          (mbbl)     (mbbl)          (mboe) 
  
 Developed producing       3,050           3,947          -           6,236 
 Total proved              6,675          13,563          -          10,949 
 Proved + probable         9,148          24,531     25,290          50,195 
 Proved + probable 
 + possible               12,726          33,906     70,323          99,170 
 Best estimate 
 contingent 
 resources(3)(4)          12,726          33,906    574,060         522,309 
 3P + best estimate 
 contingent resources     12,726          33,906    644,383         581,380 
 

(1) Total company includes Canadian business unit reserves at Dec. 31,
2006, Petrobank's 80.73-per-cent share of the Latin American business
unit's reserves as Dec. 31, 2006, and the company's 84-per-cent share of
Whitesands Insitu Ltd. reserves as at March 1, 2007, representing the
heavy oil business unit.

The full reserve disclosure tables, as required under National Instrument 51-101, will be contained in Petrobank's 2006 annual information form.

 
                                     Reserves and resources as of: 
                                      Dec. 31, 2006  March 1, 2007 
  
                                              Gross(1)       Gross(1) 
 Based on Dilbit blending scenario         (mbbl)(4)      (mbbl)(4) Change 
  
 Probable reserves (2P)                      25,290         25,290          - 
 Probable plus possible reserves (3P)        70,323         70,323          - 
 Low estimate contingent resources(2)(3)    335,689        405,263     69,574 
 Best estimate contingent resources(2)(3)   468,009        574,060    106,051 
 High estimate contingent resources(2)(3)   590,064        728,491    138,427 
 3P + low estimate contingent resource      406,012        475,586     69,574 
 3P + best estimate contingent resources    538,332        644,383    106,051 
 3P + high estimate contingent resources    660,387        798,814    138,427 
  
 (1) Gross resources include the working interest reserves and resources 
     before deductions of royalties payable to others. 
 (2) Contingent resources, as evaluated by McDaniel, are those quantities of 
     bitumen estimated to be potentially recoverable using SAGD technology 
     from known accumulations but are classified as a resource rather than a 
     reserve primarily due to the absence of regulatory approvals, detailed 
     design estimates and near-term development plans and are in addition to 
     3P reserves. 
 (3) A low estimate means higher certainty (P90), a best estimate (P50) 
     means most likely and a high estimate means lower certainty (P10). 
 (4) mbbl means thousands of barrels. 
  
  
  WHITESANDS'S BEFORE TAX NET PRESENT VALUES AS OF DEC. 31, 2006 
                      (millions of dollars) 
  
 Based on Dilbit blending scenario 
 Net present value discounted at:                      0%     5%     8%  10% 
  
 Probable reserves (2P)                               97      9    (25) (41) 
 Probable plus possible reserves (3P)                726    295    163  104 
 Low estimate contingent resources                 2,387    584    120  (63) 
 Best estimate contingent resources                5,078  1,432    605  292 
 High estimate contingent resources                8,389  2,265  1,047  606 
 3P + low estimate contingent resource             3,113    879    283   41 
 3P + best estimate contingent resources           5,804  1,727    768  396 
 3P + high estimate contingent resources           9,115  2,560  1,211  710 
  
     WHITESANDS'S BEFORE TAX NET PRESENT VALUES AS OF MARCH 1, 2007 
                      (millions of dollars) 
  
 Based on Dilbit blending scenario 
 Net present value discounted at:                      0%     5%     8%  10% 
  
 Probable reserves (2P)                               93      8    (25) (41) 
 Probable plus possible reserves (3P)                742    310    176  115 
 Low estimate contingent resources                 3,120    830    226  (17) 
 Best estimate contingent resources                6,424  1,882    832  429 
 High estimate contingent resources               10,578  2,925  1,385  822 
 3P + low estimate contingent resource             3,862  1,140    402   98 
 3P + best estimate contingent resources           7,166  2,192  1,008  544 
 3P + high estimate contingent resources          11,320  3,235  1,561  937 
 

(1) Based on McDaniel forecast bitumen netback prices.
(2) Interest expenses and corporate overhead, etc. Petrobankre not included.
(3) The net present values may not necessarily represent the fair market
value of the reserves and resources.
(4) A low estimate means higher certainty (P90), a best estimate (P50)
means most likely and a high estimate means lower certainty (P10).

To date, the McDaniel's reports are still based on SAGD technology as it is the presently recognized technology used to define in situ oil sands reserves. This does not in any way reflect the technical merits of the Thai process; it is simply the only way for the company to presently recognize a portion of the reserve and resource potential on the Whitesands leases using industry accepted norms. Once McDaniel's can independently certify reserves associated with the Thai process, this SAGD-based analysis will be phased out.

Thai has many potential benefits over SAGD including expected higher resource recovery (70 per cent to 80 per cent versus 30 per cent to 50 per cent for SAGD), 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. The continued field demonstration of Thai is expected to have an enormous impact of on resource recovery and estimates of reserve volumes.

In connection with the recent updated reserve evaluations, McDaniels also conducted a preliminary estimate of gross bitumen in place on 60 of the 62 sections of oil sands leases. Their preliminary estimate of gross bitumen in place on the leases is approximately 2.2 billion barrels, which is a 38-per-cent increase from the earlier estimate of 1.6 billion barrels of gross bitumen in place from Fekete Associates in 2005. The company is continuing to assess the ultimate potential bitumen in place on the lands, since the Thai technology is applicable over a broader range of reservoir characteristics than the SAGD process. This represents a significant opportunity to not only continue to increase the total amount of recoverable bitumen relative to the SAGD-based estimates, but also for the Thai technology to greatly improve the ultimate recoverable volume and the per-barrel economics of fully developing the oil sands resthece base.

Whitesands operational update

Further to the Jan. 16, 2007, update, combustion operations continue on the first two well pairs and the preignition heating cycle (PIHC) is nearing completion in the third well pair. The start of air injection and combustion in the third well pair is expected to occur around the end of the first quarter 2007. The PIHC phase for the third well is expected to be half the duration of the first well pair, similar to the second well. As a result, the company is able to initiate combustion faster and minimize the amount of steam injected. Minimizing steam injection results in lower initial water cuts and a more rapid increase in oil cut. This is a significant improvement in operating performance from that experienced on the first well pair.

The second well's gross fluid production rates, on a restricted choke, have been up to 1,000 barrels per day with oil cuts of between 30 to 40 per cent when producing at stable flow rates. Petrobank expects to achieve similar results when the company starts combustion operations on the third well.

Air injection in the first well has continued since July, 2006, and production has continued on a restricted choke with a gross fluid rate of up to 1,000 barrels per day and oil cut in the 40- to 50-per-cent range. Restricted rates are necessary at this time to manage sand production and fluid rates in to the plant until the company completes planned debottlenecking to enable the wells to produce at their higher capability.

While the company has not expected to see a material and consistently upgraded produced oil this early in the process, the company now believes that The company is beginning to see some partially upgraded bitumen. One of the unique aspects of the oil produced by the Thai process is the lack of difficult emulsions and a clean oil/water separation. Recent production from the first well pair has demonstrated further improvements in oil/water separation and a reduced viscosity compared to the earlier production, leading Petrobank to believe that The company is beginning to see an upgrading effect. The company has initiated a third party analysis to determine the extent to which the oil is being upgraded.

Plant operations have experienced frequent downtime due to recent modifications to the sand-handling equipment, turnaround of the vent gas sthe companyetening unit as well as periods of very cold the companyather in the first quarter. The company is still in the early stages of the Thai process and in a state of continual adjustment of the operations. This continuous improvement process is consistent with starting up the first field scale demonstration of a new technology, allowing us to modify, on a controlled basis, the surface facilities and operating procedures. The company foresees the continuing process of technical improvement and innovation as the company enhances the ability to produce oil using Thai.

With completion of the recent delineation drilling the company has now confirmed the geological parameters of the oil sands reservoir proximal to the current project site. This will allow for expansion of the current facilities by up to three wells, incorporating the Capri technology, as well as further commercial expansion to 10,000 barrels per day. Project scoping and preliminary engineering for debottlenecking the current facilities and the design of a 10,000 barrel per day project are proceeding.

The company believes that Thai can also be applied to other heavy oil deposits beyond the Canadian oil sands and it is the strategy to next initiate projects in mobile conventional heavy oil reservoirs in Canada and/or internationally. The goal is to capture a global portfolio of heavy oil restheces where the application of the Thai technology can lead to greatly improved recovery rates and significant long-term value for the company. In support of this activity, the company is evaluating, with the Latin American subsidiary Petrominerales Ltd., three exploration blocks in Colombia's Llanos basin heavy oil belt covering 800,000 acres with a potential for large heavy oil accumulations.

Canadian business unit

Reserves

The Canadian business unit reserve engineers, Sproule Associates Ltd., have completed the evaluation of the conventional Canadian reserves as at Dec. 31, 2006. All reserves are based on forecast prices and costs and are Company gross reserves. Summary results of the Sproule report are highlighted as follows:

* total proved reserves of 6.7 million barrels of oil equivalent;
* proved plus probable reserves of 9.1 million barrels of oil equivalent;
* proved, probable and possible (3P) reserves of 12.7 million barrels of oil equivalent; and
* NPV 10 per cent (before taxes) of $150.2-million (P+P) $193.9-million (3P).

 
                     WORKING INTEREST RESERVES(1) 
                           FORECAST PRICES(2) 
  
                                Natural    Light and  Heavy 
                                    gas   medium oil    oil    NGL    Total 
                                  (mmcf)       (mbbl) (mbbl) (mbbl)   (mboe) 
  
 Developed producing             12,864          858     14     34    3,050 
 Total proved                    30,956        1,425     14     77    6,675 
 Proved + probable               39,257        2,460     17    129    9,148 
 Proved + probable + possible    53,544        3,433    129    240   12,726 
 

(1) Company working interest reserves excluding royalty income reserves
and before deduction of royalties payable.
(2) Based on the Sproule Associates Limited price forecast effective
Dec.31, 2006.

                    NET PRESENT VALUE -- BEFORE TAX  
                     Forecast prices As at Dec. 31, 2006 
    
                                                0%       5%      10%      15% 
  
 Developed producing                        105.9     91.3     81.0     73.3 
 Total proved                               174.2    135.1    110.4     93.6 
 Proved + probable                          262.8    191.1    150.2    123.9 
 Proved + probable + possible               384.5    257.5    193.9    156.0 
 

Royalty income volumes are excluded from company gross reserves noted above but are included in calculating Company net reserves and net present values. Production in the fourth quarter of 2006 included 491 barrels of oil equivalent per day of royalty income production.

              RESERVE RECONCILIATION -- FORECAST PRICES  
                                  (mboe) 
                                                                   Proved + 
                                              Total    Proved +  probable + 
                                             proved    probable    possible 
 Dec. 31, 2005, reserves                      7,372      11,635      16,188 
 2006 production net of royalty income         (950)       (950)       (950) 
 Net change in reserves                         253      (1,537)     (2,512) 
                                             ------      ------      ------ 
 Dec. 31, 2006, reserves                      6,675       9,148      12,726 
                                             ======      ======      ====== 
 

The Canadian business unit's reserve growth for 2006 was disappointing, due to delays earlier in 2006, most new production was not added until late in the year and the company the companyre unable to collect sufficient new production data to support the oil and gas reserves representative of what the company actually believe the company added during the year. The current audited reserve estimates are down from the previous year, although the company produced 27 per cent more oil and gas last year then the company did the year before, and the current production is 36 per cent higher than the average production for 2006. Much of the new production at Red Willow and in the Bakken/Torquay play was added late in the year or early in 2007, resulting in conservative initial reserve estimates, due to lack of production history. Furthermore, the Jumpbush property experienced large negative reserve revisions due to lothe companyr gas prices and the deferral of development drilling and production maintenance from 2006 into 2007 and beyond. At Jumpbush, the company has initiated the continuing field and well maintenance program to optimize the production and recover reserves temporarily revised downward that, by analogy with offsetting production, are expected to be recovered. The results of this production maintenance program, the increased production history at key properties, and the continuation of the Bakken and Torquay drilling programs will likely result in an updated reserve evaluation being commissioned later in 2007.

Canadian business unit operational update

Petrobank's conventional Canadian production averaged 3,075 barrels of oil equivalent per day during 2006 and 3,260 barrels of oil equivalent per day during the fourth quarter of 2006 compared to 2,420 barrels of oil equivalent per day during 2005. In 2006, Petrobank drilled 95 (79.6 net) wells resulting in 59 (50.3 net) gas wells and 29 (22.8 net) oil wells. During the first two months of 2007 production has increased further with the tie-in of a large portion of the 2006 drilling program either late in 2006 or early 2007. For the first two months of 2007 the company averaged 4,192 barrels of oil equivalent per day. In addition, the company has just begun to add production from the continuing 2007 drilling program, which will be largely focused on the Bakken and Torquay plays in southeast Saskatchewan, and souththe companyst Manitoba.

Latin American business unit -- Petrominerales Ltd.

Petrominerales is also pleased to report on the 2006 year-end third party reserve report. Total proved plus probable reserves in Colombia have increased by 53 per cent, based on the DeGolyer and MacNaughton evaluation as at Dec. 31, 2006. All reserves stated herein are based on forecast prices and costs and are company interest reserves after Ecopetrol's (the state oil company) share and before 8-per-cent royalties. D&M's work incorporates an update of their comprehensive geological and petrophysical evaluation of both the Orito and Neiva properties but, to date, does not include any reserves associated with the 13 exploration blocks.

Summary results of the D&M report are highlighted as follows:

* total proved reserves increased by 42 per cent to 13.6 million barrels.
* total proved plus probable reserves increased by 53 per cent to 24.5 million barrels.
* total proved, probable and possible reserves of 33.9 million barrels.
* total proved plus probable NPV 10 per cent (before taxes) increased 93 per cent to $521.8-million (U.S.) (3P -- $677.7-million (U.S.)).

                 RESERVES -- COMPANY INTEREST 
  
                                                 Light and medium oil (mbbl) 
  
 Developed producing                                                  3,947 
 Total proved                                                        13,563 
 Total proved + probable                                             24,531 
 Total proved + probable + possible                                  33,906 
   
                               RESERVE RECONCILIATION 
  
                                                                   Proved + 
                                              Total    proved +  probable + 
                                             proved    probable    possible 
  
 Dec. 31, 2005, reserves                      9,582      16,085      22,263 
 2006 production                             (2,194)     (2,194)     (2,194) 
 Net additions                                6,175      10,640      13,837 
                                            -------     -------     ------- 
 Dec. 31, 2006, reserves                     13,563      24,531      33,906 
                                            =======     =======     ======= 
  
                    NET PRESENT VALUE -- BEFORE TAX  
                         (millions of dollars) 
                                                          2006 
  
                                                0%       5%      10%      15% 
 Proved developed                           179.2    153.1    133.7    118.8 
 Total proved                               497.7    391.6    316.4    261.2 
 Proved + probable                          858.7    660.5    521.8    421.3 
 Proved + probable + possible             1,166.9    876.8    677.7    536.1 
 

Latin American business unit update

Joropo exploration success

the Ojo de Tigre-2 well on the Joropo block in the Llanos Basin was initially drilled to a total depth of 8,309 feet, and logged and evaluated. Based on the evaluation, and the geological and hydrocarbon indications in this initial well, a decision was made to sidetrack to a more favorable bottom-hole location. This second well, Ojo de Tigre-2 sidetrack, was drilled to a total depth of 8,419 feet and has been cased as a potential oil well. The well was cored through certain prospective intervals with indications of high-quality oil-bearing sands, which was confirmed by subsequent logs indicating a primary target with net oil pay in excess of 25 feet. The well is currently being completed with production results expected over the next several the companyeks. Unfortunately, this portion of the Llanos Basin is subject to the companyt surface conditions during the summer months, but the company is evaluating alternatives to allow long-term, year-round production of this well. The ultimate size of the prospect will be determined through long-term production testing and potential follow-up drilling. Successful development of this discovery will most likely include upgraded surface access, which would allow for year-round production.

This initial result at Joropo is very enctheaging as the company has only evaluated a very small part of the 72,257-acre Joropo block to date, and the company has now submitted applications for two blocks adjoining Joropo totalling an additional 69,122 acres. This was the first of five exploration wells to be drilled in 2007 on the extensive exploration acreage. The company has either executed or the company is finalizing 13 exploration block contracts totalling 1.5 million acres in the Llanos and Putumayo basins, making Petrominerales one of the largest exploration landholders in Colombia.

Development blocks

During the fourth quarter the activities of Petrominerales the companyre focused on continuing development in Orito, implementing the pilot fracture stimulation program in Neiva and preparing for a significant exploration drilling program in the Llanos and Putumayo basins.

fourth quarter 2006 production averaged 2,372 barrels of oil per day compared 955 barrels of oil per day in the fourth quarter of 2005 and 2,420 barrels of oil per day in the third quarter of 2006. The significant increase from the prior year period is mainly due to the success of the Orito-117 and 118 completions at the end of the first quarter of 2006 which proved-up a significant souththe companyst extension to the Orito field. The decrease from the prior quarter is mainly a result of certain wells being taken off production during the period for workovers, delays in bringing new production on-line and due to natural declines.

Since closing the Petrominerales IPO at the end of the second quarter of 2006 the company has now drilled fthe new wells at Orito, but have been delayed in bringing production on-line due to limited access to equipment and services or downhole mechanical problems. As can be seen from the independent reserve report, the company has had a very successful drilling year in 2006. All of the development wells encountered significant oil columns. Hothe companyver, at the present time, a number of these wells are off-line or awaiting services, final completion or equipment installation due to the lack of sufficient or suitable services. In an effort to mitigate these challenges the company has placed three drilling rigs under long-term contract and the company also plan to secure the required completion equipment under long-term contract to ensure existing wells and the new wells planned for 2007 are brought onstream as quickly as possible. This remains a significant challenge for the operations group given the record activity levels in the Colombian oil industry.

Board changes

Petrobank has accepted the resignation of Robert G. Puchniak from its board of directors, effective March 12, 2007. The company would like to thank Mr. Puchniak for his services as a director and wishes him well in his future endeavours. The company is pleased to announce the appointment of Chris J. Bloomer to the company's board of directors, effective March 12, 2007. Mr. Bloomer currently serves the company in the role of vice-president of heavy oil and chief financial officer, and brings a the companyalth of public company experience to the board.

[johnlw]

Huge oilsands forum set to open (8:20 p.m.)
Andrea Sands, edmontonjournal.com
Published: Sunday, March 11, 2007

Oilfield suppliers from across the country will flock to Edmonton this week to cash in on Alberta’s booming oilsands development at the largest-ever forum of its kind in Canada.
The event will give out-of-province companies access to major oilsands players and their tier-one suppliers.
Representatives from big-name companies including Imperial Oil, Suncor, Shell Canada, Petro-Canada, Syncrude and Atlantic Canada’s Irving Oil are expected to attend the Alberta Buyer-Seller Forum in the Shaw Conference Centre, which kicks off Tuesday with a speech from Premier Ed Stelmach.
Close to 850 people are registered for the event, which was originally set to accommodate 650, said Brian McCready, Alberta and Saskatchewan vice-president for Canadian Manufacturers and Exporters.
“It’s probably the largest buyer-seller forum, or the bringing together of buyers and sellers, for the oilsands industry from across Canada,” McCready said. “We are definitely full.”
The Alberta economy is so hot there are not enough local suppliers to meet oilsands demand, McCready said. “We all know the heat that the Alberta economy is in. Our traditional suppliers to the oilsands are at capacity.”
That means oilsands companies along with their main suppliers — such as engineering procurement firms, large fabricators and manufacturers — need to look outside the province, McCready said.
Without those new suppliers, oilsands companies risk delaying major projects or inflating their costs, said Myron Borys, vice-president of economic development for the Edmonton Economic Development Corporation.
“What’s important is that all these major projects get done, because that’s what’s really driving our economy and creating the jobs and everything else,” Borys said.
“In Northern Alberta, there’s more than $100 billion worth of projects on the books for the next 10 years and there are very few regions in the world that have that amount of concentrated investment, so it really attracts a lot of attention nationally and internationally.”
The forum will help Alberta companies spread their work across Canada instead of bringing more out-of-province workers into the province, said Greg Stringham, vice-president of the Canadian Association of Petroleum Producers.
That way, Alberta still benefits from the economic growth without paying related costs for infrastructure.
Stringham will speak at the forum Thursday about oilsands development in Alberta, where production is expected to leap from one million barrels of oil per day to 3.5 million barrels by 2015.
“Certainly, the opportunity is very big,” he said. “There’s going to be a lot of capital spent in the country, so Canadian firms that can secure a piece of that will actually do very well.”
There is simply too much work to keep it all in Alberta, said Larry Wall, executive director of Alberta’s Industrial Heartland Association, a partnership between Fort Saskatchewan, Strathcona County, Sturgeon County and Lamont County.
Without the out-of-province relief, intense demand here for workers will inflate oilsands-project costs and make them less competitive worldwide, he said.
“It will also create inflationary impacts on our day-to-day lives as residents and as people who perhaps aren’t working in this industry and who don’t have the opportunity to see their salaries increase based upon the demand,” said Wall. “We still have to go out and buy our goods and services and our places to live and our clothes and everything else.”
[e-mail]

[kidl]

TD Newcrest raises target on PBG to $31.00.
(Posted by vip vix on Stockhouse)

Raising Target Price on Anticipated Fireflood Success
Event
We are increasing our Target Price to $31.00 from $21.00, based on our
assessment of the WHITESANDS project and new discoveries from a recent field trip to the project itself.
Impact
Positive Details
Based on our new discoveries and forecasts, we feel we have turned the
corner and have now started to “de-risk” some of the project. We are optimistic enough to:
• Begin estimating the upside associated with developing Petrobank’s
existing leases on a commercial scale. Based on what we know today, we
estimate that the Whitesands leases are capable of being developed to
100,000 bbl/d, at a capital cost of $1.5–2.0 billion, in about half the time
it takes a standard SAGD project, and at less than half the operating
costs. (This is our estimate and not Petrobank’s.)
• Begin de-risking THAI™ in our valuation and to begin putting in some
value for the blue sky upside associated with this process, should it
unfold as Petrobank expects. Thus, our target price increase to $31/share.
• As a backstop to its oil sands value should THAI™ fail, PBG can still
develop the lease through SAGD. In this case our forecast ‘SAGD’ value
of PBG as a whole is between $19.50 and $27.30 at $45 and $60 WTI
Risked NAV scenarios. Our methodology and valuation are outlined in Exhibit 1.
• For a complete discussion regarding our findings, estimates and
valuation methodologies, please refer to our report entitled “It’s Getting Hot in Here…”, dated March 8, 2007.
Valuation
PBG trades at a risked base case ($45/bbl WTI) P/NAV of 93% vs. its peer group at 121% and a risked high
case P/NAV of 71% vs. its peer group at 87%.
Justification of Target Price
Our $31.00 target price was derived by calculating the midpoint of our base NAV (using the TD price deck)
and current case NAV (calculated using US$60 WTI). Our target price is based on the midpoint of our $45
WTI Risked NAV at $26.53 and $60 WTI Risked NAV ($34.61), but with additional risking added to the
THAI™ process (25% risking). We are arguing that the risk/reward profile is attractive at these levels, with a
potential upside of more than $30/share, versus a potential downside of less than $8/share if both THAI™ and
CAPRI™ fail.
Key Risks to Target Price
Risks associated with this target price include those business risks of the company and industry, including but
not limited to: loss of key employees, drilling success, volatile commodity prices, product supply and demand,
capex overruns, government regulations and taxes, exchange rates, interest rates, environmental and weather
concerns. In addition to these risks, PBG faces potential project risks from the fire flood, including reservoir
temperature maintenance, early air breakthrough and timing/ execution risk.
Investment Conclusion
Despite the fact that it is supposed to be an early stage experimental pilot (i.e., it is overloaded with monitoring
equipment), we believe that it is working well and is already close to being cash flow positive. This should
become evident by the Q2 results. In our initiation of coverage research report on Petrobank, we mentioned
that the THAI™ process would initially look good, but that the risks would likely dissipate slowly, as we gain
information over time. We are not in the clear yet. However, the reality is that the process is de-risking— to
our mind, it has gone from about a 10% chance of working to over 75%. This is why our target price valuation
now includes a 75% chance of success of THAI™ working (on Petrobank’s leases only). Clearly, if it is indeed
a success, the ‘blue sky’ option of leveraging this technology to other areas is significant. Based on this, we are
increasing our Target Price to $31.00 and maintaining our SPEC BUY Recommendation.

[Tackler]

EDMONTON (Sun Media) - A Quebec ironworker is accusing Suncor of discrimination after he was fired for poor English, but a spokesman for the oil giant says poor communication can be dangerous.

The dismissal prompted a second Quebecer to quit Suncor in protest and has incensed the local ironworkers union, which is demanding Suncor do more to accommodate French-speaking tradesmen.

"They aggressively recruit labourers from China, Mexico and Germany, but won't hire us because our English isn't great," journeyman steelworker Marco Pelletier of Cowansville, Que., told the Sun in a French-language interview.

Pelletier, 35, quit his Suncor job north of Fort McMurray Monday after his friend Carol Rioux was fired for failing English-language orientation tests. Pelletier passed them.

Rioux, 43, of Gaspesie, Que., has been a steelworker for 25 years. He and Pelletier were recently recommended to Suncor by the Ironworkers union.

"These guys came highly recommended and are extremely well-qualified," said Pete Anderson of Edmonton Ironworkers Local 720.

"If they'd have just given him the tests in French he'd have passed with flying colours," he said.

As shop steward at the Suncor plant, Anderson liaises between unionized steelworkers, the subcontractors who hire them, and Suncor, which runs the entire project.

"Suncor has turned away expert Canadian workers at a time when there's a terrible shortage of tradesmen. It's shameful. The foreman is bilingual, Rioux would have been fine.

"I've been up here four years and I've seen people with more (language) difficulty get along."

Last fall, he said, Suncor hired 30 non-unionized Filipino tradesmen to work at their Firebag site farther north.

"They hired translators for them," Anderson said, although Suncor spokesman Patti Lewis said the Filipinos all passed English-language testing.

Translators "were only hired for an interim period to welcome the Filipinos to the community," she said.

Pelletier and Rioux said they feel duped.

"Come work in Alberta, they say. Just not if you speak French - that's what they mean," Pelletier said.

"In Quebec we work together with non-French- speaking tradesmen. I don't understand why Suncor can't."

Lewis countered that it was Rioux's lack of English skills that led to his dismissal, not discrimination.

"We operate in an English environment. Apart from job testing, there's a variety of things like signs, work permits and safety briefings that would be problematic (for non-English-speaking) tradesmen, and could pose unacceptable risks," she said.

"In the end, everyone has to pass the training and must be able to communicate in the event of a crisis," Lewis said.

"Safety is our number 1 priority."

[Arctec]

Canadian Natural Resources upgrader on hold

Wednesday, March 07, 2007
CALGARY — Canadian Natural Resources Ltd. has decided to put its heavy-oil upgrader project on hold until federal and provincial environmental laws gain clarity and service costs cool down, the oilpatch heavyweight said Wednesday.

The company decided to shelve temporarily the long-term plan to build an upgrader in northeastern Alberta after preliminary studies indicated the legislative and cost risks were too high.

“It's the prudent thing to do,” chief executive officer Steve Laut said during a conference call.

”We don't know what kind of greenhouse gas regulations are coming at us, and as you go into second phase of [planning], you start scoping out the size of the vessels, and of the flow, and we're not going to waste money designing something that may not be effective.”

The federal government has not made clear its position on how it will proceed with efforts to curb greenhouse gas emissions. And the government of Alberta, seat of the bulk of Canada's oil and gas industry, has also not put forth definite guidelines on emission control.

Canadian Natural Resources reported earlier an 18-per-cent drop in adjusted operating income for 2006, primarily due to sharply lower natural gas prices and high service costs.

Adjusted for the impacts of risk management, tax rate changes, foreign-exchange effects and stock-based compensation, the firm's 2006 earnings from operations declined to $1.66-billion, from $2.03-billion in 2005.

Fourth-quarter earnings fell 72 per cent to $313-million, or 58 cents per share, from $1.1-billion, or $2.06 per share the previous year, when the company made an $825-million risk management, or hedging, gain.

Adjusted quarterly operating profit slipped to $412-million from $470-million despite a 9-per-cent increase in production to 613,764 barrels of oil equivalent per day.

Revenue declined to $2.51-billion from $2.9-billion as CNQ's average fourth-quarter netback was down 27 per cent from a year earlier at $29.13 a barrel of oil equivalent amid natural gas prices barely half of year-ago levels.

At the Horizon oil sands project, 57 per cent complete at year-end, “our project management and construction teams continue to deliver,” Mr. Laut said earlier Wednesday, and “at present we continue to expect final phase one construction costs to not be materially different than our original $6.8-billion target cost with an on-schedule commissioning in the third quarter of 2008.”

Vice-chairman John Langille, added that “based upon current strip pricing and projected production levels, we would expect to generate 2007 cash flows in excess of $6 billion, above the high end of our original 2007 financial budget.”

Along with its financial results, CNQ announced a penny-per-share dividend increase to 8.5 cents quarterly.

[kraftdinner]

CALGARY (CP) - Privately owned energy company Value Creation Inc. announced plans Wednesday for a $4-billion oilsands project in northeastern Alberta, using new upgrading technology that promises to slash operating costs.

The company's Terre de Grace project in the Athabasca region of Alberta will be developed in two 40,000 barrel a day phases, with first production coming onstream by the 2011, subject to regulatory approval.

It is the latest of a flood of oilsands projects eager to capitalize on growing demand for North American sources of crude, and modest compared to other massive, multi-billion dollar expansions.

"We don't have to compete with them because there's a market for our product, there's more demand than supply," David Tuer, a Value Creation advisory board member said.

Sitting on 290 sections of oil sands, the Terre de Grace block has 2.45 billion barrels to 2.77 billion barrels of exploitable bitumen in place. Value Creation plans on developing at least of third of its lease in eight phases.

Value Creation said the project will combine in situ recovery - heating heavy oil underground and pumping it to the surface - and the company's proprietary bitumen upgrading technologies to reduce costs.

The Heartland upgrader, being built by BA Energy Inc., a unit of Value Creation, will have an approved capacity of about 260,000 barrels a day. The first phase of the upgrader is planned for startup in 2008 and will refine 77,500 barrels of tar-like bitumen blend.

The upgrader will use the hot water from the produced bitumen, and the separated largest particles of the bitumen, asphaltenes, to fuel operations. Once the process has passed the start-up phase, the upgraded bitumen will be able to flow through pipelines without costly diluent.

"That obviously has quite a significant impact on operating cost, that and the fact that we will be displacing natural gas over time," Tuer said. "Those two factors will have quite an impact on operating costs."

In late 2005, Value Creation and Calgary-based energy giant Enbridge Inc. (TSX:ENB), which operates the major oil pipeline between Western Canada and eastern markets, announced a strategic alliance to pursue oilsands development.

As part of that deal, Enbridge invested $25 million for a minority equity stake in the company.
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