back in pbg here
after another bounce will see

Oil jumps by over two dollars to set new record high of 107.77 usd
March 10, 2008: 12:54 PM EST

LONDON, Mar. 10, 2008 (Thomson Financial delivered by Newstex) -- Oil reversed earlier losses, jumping by over two dollars to set a fresh record high approaching 108 usd in New York as a weak dollar and unimpressive equities encouraged a fresh round of fund money into commodities.

At 4.34 pm, New York's WTI crude for April delivery was up 2.35 usd at 107.50 usd per barrel. Earlier, WTI hit an all-time high of 107.77 usd per barrel.

In London, Brent crude for April delivery was up 1.75 usd at 104.12 usd per barrel.

While US demand projections are weakening as the world's largest consumer of oil teeters on the brink of recession, crude markets have surged to a series of record highs above 100 usd in recent weeks.

Speculative buyers have poured into commodities in reaction to tumbling equity markets and US dollar weakness, with tangible assets seen as a safer bet by some financial players during the ongoing economic turmoil. A weaker dollar also makes commodities priced in the US currency cheaper for overseas investors.

However with US employment figures showing steep declines on Friday, and speculative investors keen to lock in profits, recent gains could be vulnerable.

'The disconnect between slowing US growth and a soaring commodity/energy complex has truly been quite remarkable,' said MF Global (NYSE:MF) analyst Ed Meir. 'Friday's surprisingly large drop in February non-farm payrolls was the latest evidence of a rapidly weakening US economy, as jobs retrenched by 63,000 on the month.'
While financial speculation has been seen as one of the key reasons for oil's recent gains, many investors still view the market as well enough supported by the traditional drivers of supply and demand to justify a move higher.

'Tight fundamentals remain the dominant force underpinning prices in our view, with the combination of disappointing non-OPEC production, solid non-OECD demand and defensive OPEC output policy all exerting upward pressure on prices,' said Kevin Norrish at Barclays (NYSE:BCS) Capital,
adding that Chinese crude imports increased by 14 pct year-on-year in February to hit 3.6 mln bpd.

The head of the International Energy (OOTC:ILGL) Agency, Nobuo Tanaka also told Reuters today that global oil demand is holding up despite prices above 100 usd, though he expressed concern about the long-term impact on the global economy.

The OPEC oil producer's cartel decided against upping production quotas last week, despite calls from consumer nations led by the United States for more oil in the market to help cool prices. The dollar's decline has hit producer revenues hard, leading the organisation -- which is responsible for almost 40 pct of global supplies -- to adopt a more cautious approach.

OPEC has consistently blamed the dollar's weakness combined with increased financial speculation for oil's steep gains, arguing that the market is well supplied with crude.

While US crude inventories have been rising heading into the second quarter, where demand is seasonally lower, some market watchers believe booming demand in developing nations could soon outstrip supplies. Some investors suggest recent price increases are justified, as long dated future contracts -- for delivery much further down the line -- have also pushed above 100 usd

PBG worth a look here unless Chinese go back to bicycles

Alberta oilsands get failing grade on environment
Wanda Praamsma, CanWest News Service
Published: Thursday, January 10, 2008

All but one of 10 Alberta oilsands mines received a failing grade on environmental performance in a report released Thursday by the Pembina Institute and the World Wildlife Fund.

The report says the mines have substantial room for improvement in their environmental practices. They need to "step up and work together to solve these environmental challenges," a news release from the study's authors said.

Pembina and WWF graded 10 mines in areas such as environmental management, land impacts, air pollution, water use and management of greenhouse gases, using information provided by the companies.

The average score among the mines assessed was 33 per cent. Albian Sands Muskeg River mine scored the highest, with 56 per cent, while Syncrude and the proposed Synenco Northern Lights Mine had the weakest scores, both with 18 per cent.

"The poor environmental performance reflects badly on the oilsands mining companies, which include the largest and most profitable major oil companies in the world," said WWF Canada's Rob Powell in the release. "These companies have both the expertise and the resources to do much better.

"Government must establish limits to curb impacts on fresh water, the global atmosphere, wildlife and public health."

Syncrude rejected the report's findings.

"We obviously don't agree with their findings," said company spokesman Alain Moore. "In fact, we consider ourselves a leader in sustainability in the oilsands."

Moore said the company is the most efficient user of water in the industry. And the company has an emissions-reduction project worth $772 million that will bring down sulphur pollution in phases between 2009 and 2011, he said.

The study found that while the majority of oilsands operations have environmental policies in place, only two provided evidence of having an independently-accredited environmental management system.

In addition, no operation, except Albian Muskeg River Mine, has voluntary targets to limit greenhouse gases and no mine has publicly reported targets to reduce water usage from the region's Athabasca River, the report said.

The 10 companies reviewed, in order of ranking, are Albian Sands Muskeg, Total E&P, Petro-Canada Oil Sands, Shell Canada, Imperial Oil, Suncor, Canadian Natural, Albian Sands Muskeg, Syncrude and Synenco.

Alberta Environment spokesman Jim Law said that as companies come into the oilsands business and as technology improves, the department does require that the new technology be implemented. As for the older companies, the department does require continuous improvement in environmental performance, he said.

Future of oilsands is a game
Computer-based simulation called Producers Dilemma delivers 'realistic, dynamic' picture of how industry likely to unfold

Gordon Jaremko
The Edmonton Journal

Monday, December 24, 2007

EDMONTON / Not all of Alberta's industrial officer class was taken by surprise when the province increased oil and gas royalties.

An inner circle saw the writing on the wall early. Eyes were opened by a business counterpart to video games which accounting giant Deloitte & Touche LLP devised.

Brant Sangster, retired Petro-Canada oilsands chief and a director of Syncrude ownership partner Canadian Oil Sands Trust, led the Deloitte initiative. The team included industry executives and Priiva Consulting Corp., a game theory firm in the Ontario university town of Waterloo.

"It communicates a realistic, dynamic picture of how the industry is likely to unfold," Sangster said in describing the exercise in economic, social, political and environmental engineering, titled Producers Dilemma. It could also be called Oilsands Wars.

The program has not yet fully evolved into an automated energy executive simulator akin to the virtual cockpits for training pilots. Users get personal help from Deloitte team of experts.

But by last August the system predicted key elements of the provincial royalty review panel's report and the government response. The result is growing interest in participating in the next stage of developing the program, Sangster said. Research sessions are planned early in the new year.

The approach parts company with financial analysts and conventional managers who did not participate in the royalty review hearings, then howled in startled outrage when political leaders acted on panel recommendations.

"This is a dispassionate tool. It's objective," said Sangster, whose recent roles also included a seat on the province's latest "multi-stakeholder task force" review of oilsands development.

As a starting point, his team accepted there are multiple legitimate interests in economic development besides the stock markets -- and not least Premier Ed Stelmach's regime as trustee of the public share in the wealth under the province's constitutional ownership of four-fifths of Alberta's mineral resources.

Sangster's crew canvassed senior government personnel. Unofficially at least, provincial interest in helping with planned refinements of the economic development simulator appears to be on the rise, he said.

"We chatted with government people," he reported. "They can use this to help understand how industry might unfold if they pull this lever or that lever."

The overhaul of Alberta's energy revenue sharing machinery only made a start on dealing with issues highlighted by Sangster's team.

The group generated about 33 million "scenarios" or possible future events by compiling facets of the oilsands scene from northern aboriginal attitudes to construction costs and labour requirements then translating them into possible interactions described by game theory mathematics.

The combinations and permutations were distilled into two main scenarios rated as most likely to happen: the status quo or "maintaining pace," and a reform regime called "maintaining peace."

The status quo, of 53 projects competing to build more than $100 billion worth of plants within the next 10 years, is in trouble, Deloitte says in a report on results of the oilsands game.

The potential industrial construction boom is only warming up, with 13 projects valued at about $25 billion currently underway.

"Even at this initial stage there is a growing possibility that the current pace of development in the oilsands is approaching the point at which it could potentially become unsustainable," Deloitte warns.

Major unresolved issues include inflating costs, losing half the benefits of development by exporting raw bitumen for "upgrading" elsewhere, growing needs for infrastructure, public services, and managing effects on the land, air, water and wildlife.

"There are a number of significant questions," Deloitte reports. For instance: "Will growth collapse under the burden of the short-term 'gold-rush' mentality? Will projects face serious delays due to severe cost and regulatory pressures?"

Captains of Alberta industry know and confront big issues for society, such as whether to postpone projects until the economy cools down and cost increases moderate, Sangster indicated.

But executives also have to earn their keep by answering big business questions posed by limited global oil supplies, rising demand, high prices and the resulting huge Alberta opportunities, he added. "If you wait, is anything actually going to get better?

"Your investors don't reward delay. They want to see growth. That truly is a dilemma," Sangster said in describing issues faced by oil leaders.

In the oilsands game's alternative future of maintaining peace, government agencies, public interest groups and industry co-operate to evolve workable environment, labour and value-added bitumen upgrading policies.

"Industry players would delay development plans but possibly increase refining and upgrading activities in Alberta," Deloitte says.

The improvement requires clear, fair incentives and policies, the firm adds.

"While this would be a challenging task of fiscal engineering, the (game theory) simulation contends this is increasingly likely as the consequences of unmitigated competition within the industry become ever more difficult for stakeholders to bear," Deloitte says.

gjaremko@thejournal.canwest.com
© The Edmonton Journal 2007

The Reckoning

Cooper Langford, Financial Post Business Published: Tuesday, December 04, 2007

"What do you expect from a pig farmer?"

Alberta premier Ed Stelmach had barely finished his brief Oct. 25 televised speech announcing the details of the province's long-awaited new oil and gas royalty regime when the "Sound Off" board at the Calgary Herald website lit up. It was a remarkable moment, not only for the crush of postings, but also for the sheer vitriol. "You've shot Alberta in the foot." "Ed needs to be voted off the island." "This is a black day for Alberta."

The pressure, of course, had been building. In mid-September, a provincial panel that was appointed to make recommendations on overhauling Alberta's royalty system called for a 20% increase in what oil and gas companies should be charged for the right to extract the resources that have made the province Canada's new economic powerhouse. The increase would have amounted to a $2-billion hit annually at current prices, and major energy firms immediately threatened to pull billions of dollars of investment if Stelmach took the advice. Public opinion, meanwhile, was split over whether such changes would punish industry for its success or hand over the province's resource riches on all-too-easy terms.

After several agonizing weeks of consultation and deliberation, Stelmach, an old-school Tory who still lives on the farm his grandparents founded a century ago, opted to split the difference. He announced a plan to hike royalties on a sliding scale tied to energy prices, with the promise of bringing in $1.4 billion in new revenue to the province by 2010. While Stelmach was widely quoted afterward saying his government "got it right," politically it was a no-win decision. As such, the wrath on the Herald website from constituents fearing anything that might slow the pace and profitability of development was a predictable attack.

Lost in the rancour - and in the relentless parsing of revenue figures and royalty percentages that followed - was the fact that Stelmach had effectively marked October 2007 as the official coming of age for the Athabasca oil sands, a resource that today accounts for 50% of the province's petroleum production and, in a few years, will utterly dominate its industry. How so? By including under the new regime oil sands pioneers Syncrude Canada Ltd. and Suncor Inc., which had benefited greatly from special royalty treatment introduced in the 1990s. Incentives were needed a decade ago, when methods were less proven, few players were on the scene and oil prices were low. Amid the hurly-burly of today's oil sands rush - capital investment in 2006 jumped nearly 50%, to $14.3 billion, while industry revenue topped $23 billion - that notion seemed not just costly, but quaint.

By telling the world just how much money his government thinks is a fair return to the province, Stelmach also served notice to everyone with a stake in the oil sands chain - the public, main street investors, labourers, bankers, politicians and multinational oil company CEOs - that the resource does not have an eternal upside. Current estimates peg total reserves at 175 billion barrels of extractable oil, and production volume could increase five-fold by 2020 if all the projects announced or in development come to fruition on schedule. But that doesn't mean there's going to be five times more money for everyone. Growth in the oil sands will be matched by growth in costs, public demands and the number of obstacles that confront oil sands developers.

To some, the latter might seem painfully obvious, but the fact that the reaction to Stelmach's calculus at times bordered on the hysterical is a clear indication that not everyone has caught on. The unfortunate truth is that the global economic boom, which made the oil sands more viable than at any time in history, has at the same time fuelled inflationary pressures that have sent development costs into orbit. Labour shortages in Alberta are reaching crisis levels, while existing pipeline capacity - critical to getting oil sands products to market - is maxing out. The province, meanwhile, has fallen behind as booming growth pushes demand for everything from highways to high schools and health centres ever higher. In the near future, there is also the possibility of tightened environmental regulation, fuelled chiefly by worries about CO2 emissions and climate change, along with fears, rational or otherwise, that the scale of development will scar Alberta massively and irreparably.

What this amounts to, then, is a time of reckoning - not merely for the oil sands, but for everyone and everything with a stake in the outcome. It's a period in which the hype, the dreams and the fears that surround the oil sands are colliding hard with the reality of not only how much development can actually be absorbed, but how much will ultimately be tolerated. "We have a tough transition to manage through," says Eric Newell, an oil sands pioneer and former chief executive of Syncrude, the largest producer in the oil sands. You could frame that thought in blunter terms: The rules of the game have changed. Now deal.

If you could travel back 15 years or so, the oil sands would still look like a problem, but one wholly different from that of today. Back then, the Alberta energy industry was happily on its feet. Oil prices were hovering steadily around $20 a barrel and the memories of the bust that had punished the industry and the province in the 1980s were growing dim.

Up in the "tar sands," as the oil sands were then more widely known, two companies, Suncor and Syncrude, were collectively producing more than of 400,000 barrels per day. It was a time of quiet progress for the resource's true believers, like Newell, then still in the early stages of his 14-year tenure at Syncrude. But it was also a period of frustration. The prospect of mining dirt or injecting steam deep into the ground to extract bitumen, the bottom-of-the-barrel form of crude that's wrung from oil sands ore, had failed to excite the world.

"What was it going to take to get this thing going?" That was the question Newell and his colleagues kept asking themselves. Their solution: a national task force composed of industry and government representatives that would draft a framework to turn the oil sands - as they would rebrand the resource to make it sound more appealing - from an expensive backwater project to a world-class investment opportunity.

The National Oil Sands Task force released its report in 1995, establishing a vision for the future in which daily oil sands production would double, maybe even triple, to between 800,000 and 1.2 million barrels within 25 years. "I used to shake when I had to say that," Newell recalls. "People would look at you like you were smoking something funny."

But however optimistic those projections seemed, the arguments advanced by Newell and his expert group were persuasive. In 1997, the Alberta government, under Premier Ralph Klein, implemented one of their key recommendations: lowering royalties on oil sands projects to 1% of revenue a year until project costs were fully recovered. After that, a royalty of 25% would kick in. While nobody knew it then, Klein had just laid the foundations for what would become the greatest boom story in Canadian history, and the task force leaders who thought of themselves as radicals would soon look like timid conservatives.

Today, there are 19 new projects and expansions underway, with another 30 that have been announced but not started. If they all go ahead as planned and on schedule, daily production will rise from current levels of around 1.1 million barrels to as much as six million barrels by 2020. Resource experts say actual production growth will almost certainly be lower, more like four million barrels daily and possibly less. But even if six million barrels were achievable, there is still enough recoverable oil in the granular muck that lies beneath northeastern Alberta to keep production going for 80 years, using current technology. If technological advances increase the resource, the sands could be going strong well into the next century.

Even given what analysts call "constrained" development projections, the economic impacts are staggering. According to a 2005 study by the Canadian Energy Research Institute (CERI), an independent Calgary-based economics and policy think tank, oil sands development will, by 2020, add almost $800 billion to Canada's gross domestic product, equivalent to about two-thirds of current annual GDP. Total returns to government in royalties and corporate and income taxes will total more than $120 billion, with some $44 billion accruing to Alberta alone. Job creation is measured in the millions of person years.

The investment scenario, meanwhile, presents an intriguing, but more challenging picture. Right now, with demand from China and India driving oil prices close to US$100 per barrel, the opportunity seems limitless. But the oil sands industry is extremely sensitive to oil prices, and most return projections are based on more conservative outlooks. Oil, after all, only broke the US$40 mark three years ago. Less than a decade ago, it was below US$15.

Given that projects can also take 15 to 20 years from the start of construction to hit payout, it makes sense not to be too optimistic. William Lacey, managing director for institutional investment at First Energy Capital Corp. in Calgary, estimates returns at a modest 9%, assuming US$60 oil and a US85¢ dollar. Returns and prices may be higher now, "but what goes up can also come down," he says. "This isn't a business for the faint of heart."

In other words, no matter how big the resource, the oil sands have vulnerabilities and must compete for investment dollars. The advantage is that once projects are paid out - and assuming oil prices remain strong - they will be stable money-spinners for decades.

Inflationary pressures have already been eating away at potential margins. According to a CERI outlook report published in October, operating costs for producers - not including fuel - have essentially doubled since 2005. Total costs of delivering a barrel of tradeable product, either bitumen or upgraded synthetic crude oil, have risen anywhere from 23% to 86%, depending on the individual project.

Beyond that are issues deriving from Alberta's ability to keep pace with development. Its capacity to accommodate further activity is already strained, quite possibly to the breaking point.

At the most fundamental operational level, pipeline capacity is maxing out. The prospect of periods of rationing access is very real over the next few years. But human costs are mounting, too. This past July, five unions representing 25,000 tradesmen cast near-unanimous strike votes, raising the spectre that development could come to a crashing halt. Some of the issues involved the frustration of workers having to travel for hours to reach project sites and then spend days at a time in construction camps. The major point, however, was rampant inflation. At least one union, the International Brotherhood of Electrical Workers, negotiated successfully for minimum increases of more than 20% over the next four years - and more if the consumer price index outpaces wage growth.

Not long after the Klein government brought in its oil sands royalty regime, both Syncrude and Suncor announced major expansions to their operations. It was big news, nowhere more so than in Fort McMurray, the hub of oil sands operations some 400 kilometres northeast of Edmonton. An easygoing suburban rhythm had become part of the life for this growing community, nestled along the banks of the Athabasca River. But memories of the boom periods remained strong, and tales of those crazier times were often told with nostalgic relish. With the Syncrude and Suncor announcements, people knew another one was on the way.

Today, Fort McMurray is at the sharp end of a very large stick. The population, in the mid-30,000s by the late 1990s, has swollen to 60,000. The housing shortage is acute, and services - from schools to roads to water - are stretched beyond their limits. It's a story that has intrigued the national and international media, which has tramped to the city's doorstep to chronicle its challenges. That many of the reports have portrayed the community as a Wild West irks local leaders. So much so that the Wood Buffalo Regional Municipality, the local government for Fort McMurray and smaller communities in the region, has launched a $400,000 image campaign.

Those leaders also know, better than most, what's needed to keep the region from sinking under the weight of prosperity. In 2005, the Wood Buffalo Municipality released a study detailing the precise cost of the infrastructure it needed to keep up with the pace of development. The final tally: $1.2 billion by 2009. The priority list included more than $370 million for rec centres and urgent upgrades to Fort McMurray's water-treatment system and roads, along with $236 million for schools and health facilities.

In February of this year, the provincial government started to play catch up, committing $396 million over the next three years to infrastructure spending, including more than $200 million for new schools and $100 million for new sewage and waste-water treatment plants. But even with new money flowing to the community, the costs of what it takes to keep up have increased.

"Numbers never stand," says Melissa Blake, a former Syncrude employee who recently won a second term as Wood Buffalo's mayor. "The needs have advanced." Her most pressing concern now? The province must speed up the release of lands that the municipality can zone for housing a population now expected to reach 80,000, maybe more, by 2010. "Everything comes back to land," Blake says. "Once you get yourself a place, you have a world of opportunity."

If Fort McMurray were the province's only problem, coping with the pace of oil sands development might be easier to handle. As the Wood Buffalo costs study argued, after all, meeting costs today would enable orderly development, an investment that would produce multi-billion-dollar returns in royalties and taxes.

But Fort McMurray is only the epicentre for issues that are rattling both government and industry province-wide. The biggest one of all: the environment, a challenge with national ramifications. The issues are complex and widespread, ranging from land reclamation, management of tailings ponds and water withdrawal from the Athabasca River, which critics fear will put habitat at risk, particularly during the low-flow winter season.

Over the past few months, water has come to the forefront, with industry pitting new recycling and reservoir technologies against calls for tighter government regulation and the possibility of requiring companies to pay for usage. But the concern likely to stir the greatest controversy, particularly at the national level, is greenhouse gas emissions.

Evidence of that was abundantly clear a few weeks ago when Peter Lougheed, who presided over Alberta as premier during the oil boom in the 1970s and the subsequent bust in the 1980s, delivered a speech saying the debate for greenhouse gas reduction could lead to a constitutional crisis if federal rules ever start putting limits on provincially regulated industries like the oil sands.

That such comments would come from a politician like Lougheed - once known as the 'blue-eyed sheik' of Alberta - speaks to how deeply climate-change concerns have seeped into public debate. "We're approaching a tipping point in public opinion," says Dan Woynillowicz, an oil sands policy analyst with the Pembina Institute, an Alberta-based sustainable energy research and consulting organization.

That's a worrying prospect from a development perspective, one that's already had measurable impact on oil sands development. This past March, for example, Canadian Natural Resources shelved plans for a multi-billion dollar upgrading project, citing, among its reasons, uncertainty over federal environmental policy. Obviously, Canadian Natural, or any other oil sands player, is not looking for a licence to pollute with abandon. But this example is a clear indicator of how the risk of regulatory change adds new layers of cost insecurity to an industry struggling with budgets.

With expectations that environmental frameworks will change - and a longer view towards industry sustainability - oil sands developers have succeeded in recent years in reducing the volume of greenhouse gas emissions per barrel of oil. Those efficiencies, however, pale in comparison to net emissions increases. Oil sands companies are already the fastest-growing greenhouse gas emitters in Canada, and some observers forecast that total emissions will increase to 100 megatonnes a year by 2020, up from 40 megatonnes today.

Still, the outlook is not desperately gloomy. In a 2006 report, for instance, the Pembina Institute argued that the oil sands could achieve carbon neutrality within 15 years - using mechanisms ranging from offset purchases to carbon capture and sequestration programs - at costs ranging from about $2 to $13 per barrel, depending on the specifics of individual projects.

New technology, meanwhile, holds out more hope. One of the most promising is a technique known as "gasification." The process involves using so-called low-value fuels, such as coal or biomass, which are broken down in a pressure chamber, without combusting. This releases assorted gases, including carbon dioxide, that can be used to power various components of the oil production process, and produces heat, which can be used to generate steam that is injected into the ground to make bitumen viscous for extraction.

The primary goal of gasification in oil sands production is to decrease the burning of natural gas to power operations, thus reducing a major cost. But because its reactions don't involve combustion, it also makes it easier - and cheaper - to capture carbon dioxide for sequestration. The first oil sands application of gasification technology is now being developed at a two-billion barrel joint-venture project by Nexen Inc. and Opti Canada Inc. called Long Lake, about 40 kilometres south of Fort McMurray. Progress, however, has been slower than projected. Due to labour shortages, Long Lake's expected start date in 2008 has been pushed back by at least six months, maybe a year. Development costs, meanwhile, have spiralled to about $6 billion from initial estimates of $3.4 billion.

So what should we expect to see going forward? More than anything, that depends on the price of oil. For the sake of argument, imagine you have a barrel of oil that you had upgraded to synthetic crude from bitumen and were ready to take to market. According to an October report from CERI - the total operating and capital costs of getting that theoretical barrel to market would be more than $60 under today's conditions, including a 15% return. Given the high level of current oil prices, the additional margins on the sale of that barrel would look pretty good - even when you allow for the fact that oil sands crude trades at a discount to benchmark products of higher grades. The problem is that there's no guarantee oil prices will remain this high. And even if they do, given the rate at which supply costs are increasing, that headroom could start to narrow quickly.

At the third OPEC summit in November, Ali al-Naimi, Saudi Arabia's influential oil minister, cited $60 as a likely long-term benchmark for world prices - precisely because it reflects, in his view, a threshold at which oil sands oil can be worked profitably.

To many in Alberta, hitting that level might be a good thing. At current prices, producers can't get going fast enough. And as we've seen, that crushing demand is pushing up costs across the board. Lower the incentive, and perhaps you moderate the pace of development. (Just don't lower it too much.) The worst case, as far as industry is concerned, would be for government to step in with measures aimed at slowing down development, to keep costs and liabilities contained. In its view, the government's job is to deal with infrastructure and the regulatory environment and let market forces take care of the rest. "Some people think you can sit at a desk, twiddle a few knobs and come up with a perfect rate of development," Newell says. "I don't think you can do that by artificial means." Pierre Alvarez, president of the Canadian Association of Petroleum Producers, agrees. "Markets are much better than government in deciding the nature and pace of development."

In a worst-case scenario, mounting pressures could yet turn the oil sands boom into a bust. That's extremely unlikely, but if it happens, then all bets are off. The 1980s meltdown in Alberta's energy sector - which many blamed on Pierre Trudeau's National Energy Program - altered the balance of power in the country. Resentment over the NEP and other federal policies stoked the fires of "western alienation." That led to the growth of the Reform Party and, after its merger with the Progressive Conservatives, Stephen Harper's election as Prime Minister.

Today's most likely outcome? That industry's appetite for further investment and development in the oil sands will ease off as the realities of cost, timelines and returns sink in. As an indication of that prospect, in a mid-November report, the National Energy Board lowered its estimates for oil sands production to about 2.8 million barrels a day, from three million, by 2015. A trend towards restraint is also evident in the stock charts of major players such as Suncor, Nexen and Canadian Natural Resources. All follow a similar pattern, rising rapidly in early 2006, only to peak and then retreat. Stelmach's October announcement was among the latest events to spark a brief pullback. Whatever else is in store, it's safe to say that it won't be the last.

Hope my BQI gets bought put!!!

I appreciate all your posts hear John!

Todd

Scientists use fertilizer to quickly produce methane from old oil wells

2 hours ago

CALGARY - Researchers at the University of Calgary say they may have tapped into a vast new source of clean energy by harnessing the power of oil-eating bacteria that dwell deep beneath the surface of the earth.

The naturally occurring microbes convert crude oil into methane in a process that normally takes tens of thousands of years. The researchers were able to get the same result in just two years by feeding fertilizer to the tiny critters.

Methane is the main ingredient in natural gas - a fuel that expels fewer greenhouse gases than conventional oil when burned.

"We've got a process that naturally turns oil into natural gas," said Steve Larter, the University of Calgary petroleum geologist who led the research published Wednesday in the science journal "Nature."

"Why not just speed up the process by just lobbing in some fertilizer."

The discovery has been enticing to energy companies, who until now have been able to recover only about 17 per cent of oil from the ground.

"This is deemed fairly interesting technology, especially since we get such poor recovery from standard recovery methods of heavy oil," research co-author Jennifer Adams said in an interview.

"To get heavy oil out you've basically got to melt it ... it's like turning gold into lead," Larter said on the journal's website.

The scientists hope to do some field tests in 2009.

The researchers admit proving their process could work on a large scale, economically and in real world conditions, is the big unknown.

Adams said a few companies have expressed interest so far, but she wouldn't say which ones.

Larter said it was hard to come up with just how much energy they could produce, but speculated it could be near the equivalent of the world's conventional oil reserves.

"You're talking a very substantial amount of energy," he said on the journal's website. "It's potentially a game changer if it can be demonstrated."

The bacteria, which have existed underground for hundreds of millions of years, ferment the oil and expel natural gas without requiring oxygen.

Others have tried the approach used by Larter and his colleagues before, seeking to speed up the process by injecting more bacteria. But Larter says the key is giving the microbes their own version of vitamins.

"You'd basically feed them Miracle-Gro or fertilizer to accelerate their growth rate," he said.

The discovery could have big implications in Alberta's oilsands, which according the Canadian Association of Petroleum Producers contain up to 175 billion barrels of oil. Canada's reserves are second only to Saudi Arabia's in size.

The problem is that the process of extracting the tar-like bitumen takes up a lot of money, energy and water.

Steam Assisted Gravity Drainage, or SAGD, oilsands operations use natural gas to heat up the bitumen, making it less viscous and therefore easier to draw to the surface. Enviromentalists have decried that process as a waste of the clean burning fuel.

So the discovery is good news for Simon Dyer, a senior policy analyst with the Pembina Institute, a think tank that advocates sustainable energy.

"I can certainly say that Pembina Institute is supportive of any sort of technology that is going to reduce the environmental impacts associated with oilsands development and the massive amount of energy and greenhouse gases and water use associated with current oilsands production," he said.

But in order to get a project like this off the ground, there needs to be the political will, Dyer said.

"We're continually approving new oilsands projects based on old technologies and we're going to be locked into using these more destructive technologies even if better approaches are waiting in the wings," he said.

"I think the real obstacle is that we don't really have the regulatory framework that demands best practices or the sort of improvements to the environmental performance that would encourage the economic development of these technologies."

Speaking to a business audience in Regina on Wednesday, Saskatchewan Premier Brad Wall said new technology is key to developing his province's oilsands resources.

The province contains 27,000 square kilometres of potential oilsands reserves. If technology increased recovery rates by five per cent, the province's remaining recoverable reserves would more than double from current levels, Wall said.

"Saskatchewan has an energy diversity that no other Canadian province can match in terms of primary energy supply," Wall said. "Oil is a critical part of that diversity, but we need research and new technology to unlock the resource that we have in not only oil sands but light, medium and heavy crude as well."

Have to agree on PBG, Bobwins!

Been awhile since posting, been busy elsewhere and have kept only two oils for awhile. (And, yes John, i see your posts and appreciate them. Will buy you a beer if I ever get up to the northland.)

PBG is my secone biggest position to POT Leaps. Have had it since $8.57 and am adding to it Mon. By the way, Tackler, you looked at SUF a while back and it has since gone through a Gunnerman removal and is ready for process confirmation in the near future. Might be worth another look.


DrBob follows and knows more about PBG than anyone I know.
This is his post on SI:


*** My take on PBG.TO's Qtr Rept:

What strikes me is that they are no longer being conservative in their description of THAI:

"THAI(TM) is a field-proven technology that will be deployed globally.

"The activities are now at the stage where we expect to have a pipeline of licensing opportunities and projects for the implementation of THAI(TM) on a global basis."

Thus, Petrobank Energy is now saying to the world unequivocally that THAI works and they are going to be JV'ing it all over the world. Duvernay is just the beginning.

They also state:

"Petrobank's wholly-owned subsidiary, Archon Technologies Ltd. ("Archon"), has also been actively evaluating the acquisition and development of several new technologies and innovations around the base THAI(TM) and CAPRI(TM) technologies to capture the full commercial benefits of a THAI(TM) project.

These technologies are in the areas of sulfur recovery, innovative additional surface upgrading processes, produced water processing, oxygen enriched air injection to increase combustion efficiency, CO2 capture, and heat recovery for power generation.

Archon has its own research and development facilities in Calgary and a full time staff of researchers who also perform fluids and gas analysis for the current WHITESANDS project. We operate the only three dimensional combustion reactors in the world capable of evaluating the combustion properties of any oil.

Archon is building a portfolio of technologies to provide an integrated solution designed to maximize the overall efficiency and economics of a THAI(TM)/CAPRI(TM) project. Archon is also the vehicle for licensing any of the technology or intellectual property to third parties."

Thus, other companies that may try to replicate PBG's patented THAI process, will have the disadvantage of not knowing these associated technologies and techniques and methods that maximize THAI or THAI-like processes.

So other companies can try to re-invent the wheel so to speak, at their own added expense, lower efficiencies, and time-delays and frustrations, or they can negotiate with PBG and get it right the first time.

And if they try to duplicate THAI in the U.S., Canada, or Venezuela, where it is patented, they will get their butts sued.

In terms of other aspects of the report, the EPS of .25/share is pretty good, as it shows that PBG has great leverage with every additional 1,000 bbl/day production.

Cash flow is increasing quickly now and when Whitesands is no longer just capitalized accounting-wise, but gets to be included as part of the regular revenues and income, it will make a big difference to the bottom line.

As will the time when the reserves are stated in THAI terms instead of SAGD.

Arguably the most important event for Petrobank Energy in terms of a company-maker, is the expected announcement in 2-3 months that they have reached steady state, which will include actual optimal production numbers of around 1,000 bbls/day of oil per well and upgraded bitumen to perhaps 15-20 degrees API, and that is without CAPRI.

This much-anticipated announcement will blow the socks off of the heavy oil and oil industry because it will prove the enormous commerciality of THAI and engender serious interest from major oil companies to JV with PBG, and start some of them to think about acquiring PBG.

I would not want to be a non-shareholder of PBG.TO when this occurs, and it, steady state, could occur in late December or January.

Of course there are other price catalysts for PBG such as more drill results from Petrominerales Energy and further increases in Bakken production.

Technically, PBG tested the low 49 area and could firm up on Monday and rally next week to test its ATH 54.10, with a 6 handle in its sights in the near future. I expect one or more broker-dealers to up their target to $60 next week.

PMG was a little weak today as well but has had a big run and is pausing to refresh, before it takes off again to test its ATH 20.76 in late November or December.

Sure am glad I bought more PBG shares today, Friday, and this week, on every dip, so now I am overweighted in PBG vs. PMG shares, and am very overweighted in those two vis-a-vis my overall portfolio.

jmho,

drbob

ok, this is my biggest holding so excuse the irrational exuberance but Petrobank is on fire. Read this report and you can see big results coming. Doubled production from last year to 9975boepd for Q3 and already hitting 16,000boepd in November. That means Q4 is going to be 50 to 60% better than Q3. Three more THAI wells by early 2008, hooking up Corcel wells in Colombia(first one is a monster at 10,000bpd possible after above ground facilities are built)and those beautiful little BAKKEN wells. 4 rigs drilling as fast as they can with 80 wells goal for 2008. Petrobank is headed for $100 in the next 12-24 months. If the Jt Venture with Duvernay works out, there will be a line out the door to JV with them. This is a must own for unconventional energy. Bobwins

Petrobank Announces Record Production and Third Quarter Results
Friday November 9, 5:57 pm ET


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

HIGHLIGHTS

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

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

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

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

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

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

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

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

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

 
  
                         Three months ended         Nine months ended 
                               September 30,     %       September 30,     % 
 Financial                  2007       2006 change     2007      2006 change 
 ---------------------------------------------------------------------------- 
 ($000s, except where 
  noted) 
 Oil and natural gas 
  revenue                 61,567     24,639    150  127,897    73,499     74 
 Funds flow from 
  operations (1)          42,316     14,706    188   82,131    45,208     82 
  Per share - basic ($)     0.55       0.22    150     1.09      0.68     60 
  Per share 
   - diluted ($)            0.48       0.21    129     1.01      0.66     53 
 Net income               20,978      5,169    306   41,281    20,486    102 
  Per share - basic ($)     0.27       0.08    238     0.55      0.31     77 
  Per share 
   - diluted ($)            0.25       0.07    257     0.53      0.30     77 
 Capital expenditures    135,417     57,904    134  373,736   158,356    136 
 Total assets            930,855    395,654    135  930,855   395,654    135 
 Net debt (2)             37,762     70,366    (46)  37,762    70,366    (46) 
 Common shares 
  outstanding, end of 
  period (000s) 
  Basic                   76,897     67,293     14   76,897    67,293     14 
  Diluted                 90,083     71,346     26   90,083    71,346     26 
 ---------------------------------------------------------------------------- 
 ---------------------------------------------------------------------------- 
  
 Operations 
 Canadian Business Unit 
  operating netback 
  ($/boe except where 
  noted) (3)(4) 
  Oil and NGL revenue 
   ($/bbl)                 76.56      72.13      6    71.00     64.52     10 
  Natural gas revenue 
   ($/mcf) (5)              5.35       5.39     (1)    6.51      6.23      4 
  Oil and natural gas 
   revenue (5)             62.86      44.28     42    56.87     44.61     27 
  Royalties                 4.18       6.00    (30)    4.71      6.94    (32) 
  Production expenses       8.26       8.63     (4)    8.31      6.47     28 
  Transportation 
   expenses                 0.18       0.42    (57)    0.24      0.43    (44) 
 ---------------------------------------------------------------------------- 
  Operating netback        50.24      29.23     72    43.61     30.77     42 
  
 Colombian operating 
  netback ($/bbl) (3) 
  Oil revenue              72.74      64.58     13    66.84     63.20      6 
  Royalties                 6.32       5.16     22     5.60      5.07     10 
  Production expenses       7.42       7.80     (5)    7.40      7.56     (2) 
 ---------------------------------------------------------------------------- 
  Operating netback        59.00      51.62     14    53.84     50.57      6 
  
 Average daily 
  production (4) 
  Canada - oil and NGL 
   (bbls)                  3,745        756    395    2,531       802    216 
  Canada - natural gas 
   (mcf)                  10,006     10,578     (5)  12,053    13,267     (9) 
 ---------------------------------------------------------------------------- 
  Total Canada 
   conventional (boe)      5,413      2,519    115    4,540     3,013     51 
  Colombia - oil (bbls)    4,522      2,420     87    3,146     2,133     47 
 ---------------------------------------------------------------------------- 
  Total Company 
   conventional (boe)      9,935      4,939    101    7,686     5,146     49 
 ---------------------------------------------------------------------------- 
 ---------------------------------------------------------------------------- 
 

(1) Non-GAAP measure calculated based on cash flow from operations before
changes in non-cash working capital.
(2) Non-GAAP measure includes bank debt plus accounts payable and accrued
liabilities less current assets.
(3) Non-GAAP measure demonstrating Company's revenue less royalties,
production and transportation expenses per unit produced.
(4) Six mcf of natural gas is equivalent to one barrel of oil equivalent
("boe"). Heavy Oil Business Unit bitumen volumes are excluded from
average daily production as WHITESANDS operations are considered to be
in the pre-operating stage and accordingly are capitalized.
(5) Canadian sales prices are shown after forward gas sales contracts.


Heavy Oil Business Unit

WHITESANDS Operations

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

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

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

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

WHITESANDS Project Development

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

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

THAI(TM) Business Development

Along with our project development plans for our oil sands leases, we continue to evaluate the use of the THAI(TM) technology in various reservoirs in other regions of the world, including conventional heavy oil reservoirs in Canada. These evaluations are being conducted with third parties that have executed technology evaluation agreements and are aimed at demonstrating the applicability of the THAI(TM) technology in other potential projects, and include provisions for future licensing opportunities. The activities are now at the stage where we expect to have a pipeline of licensing opportunities and projects for the implementation of THAI(TM) on a global basis.

The Dawson Property Acquisition

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

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

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

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

THAI(TM) License Agreement

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

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

Expanding Oil Sands Land Base

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

Resource Delineation

In the first quarter of 2007, Petrobank drilled eight delineation wells on the WHITESANDS lands and increased the gross discovered resources of bitumen-in-place on our oil sands leases to 2.6 billion barrels, as estimated in our March 2007 McDaniel and Associates Consultants Ltd. ("McDaniel") reserve report. This represented a 1.0 billion barrel increase from the 1.6 billion barrels first announced in May 2006. McDaniel assigned a recoverable bitumen resource of up to 799 million barrels at March 1, 2007 which compares to 660 million barrels estimated at December 31, 2006. Further delineation drilling to be conducted in late 2007 or early 2008 is expected to add additional recoverable volumes from the existing and recently acquired Alberta oil sands lands. We plan to commence our winter drilling program before the end of the year. Since the current recoverable resource evaluations are based only on SAGD recovery technology, the incorporation of the THAI(TM) technology into our evaluation is expected to materially increase future estimated recoverable bitumen resource and reflect the lower capital and operating costs associated with our process. McDaniel has been engaged to conduct an evaluation of our resource utilizing the THAI(TM) technology recovery method.

Archon Technologies Ltd.

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

Canadian Business Unit

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

Bakken Light Oil Resource Play

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

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

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

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

The Bakken Formation

The Bakken formation is found in the Williston Basin, underlying much of North Dakota, eastern Montana and extending up into southern Saskatchewan. The expansion of our presence in the play began with a drilling program that commenced in late 2006. The Mississippian aged Bakken is an extensive regional resource play with the oil contained mostly in siltstones and thin sandstone reservoirs with low porosity and permeability. The formation is capable of high initial production rates of sweet, light, 41+ degree API gravity oil, and liquids-rich solution gas. This resource is significant with approximately 4.5 million barrels of original oil-in-place per section (square mile or 640 acres) of land within the defined play area.

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

Petrobank's independent reserve evaluator, Sproule Associates Limited ("Sproule"), currently assigns a proved, probable plus possible (3P) reserves estimate of 125,000 barrels per Bakken well. With our high initial production rates from our 100 percent working interest wells, we are producing in excess of the forecast type curves used in this preliminary evaluation. Petrobank's internal estimate is that each well will recover in excess of 150,000 barrels. We expect our next reserve evaluation to more appropriately reflect our actual performance to-date. We also anticipate material reserve additions related to solution gas conservation and liquids recovery through our new gas facility.

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

Additional Canadian Business Unit Focus Areas

In addition to our Bakken light oil asset, we have a long-term legacy shallow gas asset at Jumpbush with an inventory of over 175 low-risk development drilling locations. We continue to discuss our development drilling plans with the Siksika First Nation.

Petrobank is also aggressively moving forward on new, potentially high-impact exploration prospects in two key areas of northwestern Alberta where we are targeting multi-zone oil and gas prospects with at least two exploration wells in 2007. The first well was completed and cased as a light oil well in the Beaver Hill Lake sand play. Although production from this initial well is not material to Petrobank, the knowledge gained from this early success added greatly to our play understanding, resulting in an expanded northwest Alberta drilling program. We are currently drilling our second exploration well in this area. Further exploration and development wells will be drilled in northwestern Alberta through the balance of 2007 and into 2008, depending on weather and ground conditions. Petrobank continues to leverage our large undeveloped land base into exciting new opportunities.

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

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

DEVELOPMENT BLOCKS

Orito

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

Neiva

At Neiva, production has increased as a result of well optimizations and the initial success of our pilot waterflood program. Due to the results from the well optimization program and an earlier than expected waterflood response, we will continue the well optimization program and we plan to expand the waterflood. In addition, we have an inventory of approximately 31 infill locations and 25 fracture stimulation candidates.

EXPLORATION PROGRAM

Petrominerales has completed drilling all five wells planned for the 2007 exploration program. Four of these wells were drilled in the Llanos Basin, two of which were completed as new pool discoveries (Joropo and Corcel). The final 2007 exploration well, Conga-1, has now been drilled and will be completed as a potential oil well on the Las Aguilas Block adjacent to Orito, in the Putumayo Basin. Petrominerales holds over 1.5 million acres of land in Colombia, on which we have acquired 357 square kilometres of 3D seismic and reprocessed all available 2D seismic data. Currently we have an additional 18 leads and prospects on these lands. In 2008, we plan to drill eight exploration wells focused primarily in the Llanos Basin. We continue to acquire additional 2D and 3D seismic, which should result in an expanded exploration drilling programs beyond 2008.

Corcel Block

The Corcel-1 exploration well, located in the southern Llanos Basin, was drilled to a total depth of 12,000 feet. Logs indicated that the target reservoir sands in the Tertiary Mirador and Cretaceous Guadalupe formations were primarily oil bearing with total potential net pay of approximately 140 feet of high quality sand. The Guadalupe and Mirador intervals were completed and commingled for an initial six-day test that was conducted at rates increasing to 2,500 bopd. A six-month extended production test then commenced on September 7, 2007 at initial rates of 4,000 bopd. We have been slowly ramping up production rates and the well is now producing in excess of 4,500 bopd.

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

This initial Mirador completion is being executed with the drilling rig. The rig will then move to drill the third well from the same platform, Corcel-3, to further delineate our first Corcel discovery. After drilling Corcel-3 we expect to use the drilling rig to drill at least one of our Llanos Basin dry-season-only exploration wells, after which we plan to resume our Corcel drilling program starting with the Corcel-C exploration well. The rig is then expected to remain at Corcel for the rest of 2008 to continue drilling additional exploration and delineation wells.

The Corcel Block is situated in a drier region of the Llanos Basin and we have an all-weather road to the location which will accommodate year round production. Production is currently being processed through temporary facilities and trucked. We are designing permanent production facilities and a pipeline and applying for required governmental approvals.

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

Joropo Block

Our Ojo de Tigre-2 well on the Joropo Block in the Llanos Basin was completed and initial production testing commenced, but was suspended with the onset of the rainy season earlier in 2007. Initial test rates reached 450 barrels of fluid per day with a water cut of 20 percent and a gravity of 29 degrees API. The test interpretation indicated very high skin damage which was likely caused by the gravel pack completion. We will be returning to remediate the skin damage and conduct further testing of the well after the end of the rainy season in late 2007 or early 2008. The ultimate size of the prospect will be determined through long-term production testing and follow-up drilling. A second Joropo exploration well is planned for the first quarter of 2008. Successful development of the Joropo Block will require upgraded surface access to support year-round production.

This initial result at Joropo is very encouraging as we have only evaluated a very small part of the 72,257 acre Joropo Block to-date, and we have now acquired two adjoining Blocks, Jabali and Jaguar, totalling an additional 69,122 acres.

Las Aguilas Block

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

2008 Exploration Program

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

Heavy Oil

Petrominerales has three large blocks in the southern Llanos Basin heavy oil belt, Chiguiro Oeste, Chiguiro Este and Rio Ariari. Our heavy oil blocks offset the Cano Sur Block, which is being developed by a recently announced partnership between Shell and Ecopetrol, reflecting the increasing interest in the heavy oil potential of this area.

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

In addition, Petrominerales intends to participate in the upcoming Heavy Oil Bid Round, expected to be announced early next year. Petrobank's proprietary THAI(TM) technology, which Petrominerales has licensed, represents a paradigm shift in heavy oil recovery technology. THAI(TM) is well suited to the Colombian heavy oil environment and should give us a competitive advantage to efficiently develop Colombian heavy oil opportunities in an environmentally and socially responsible fashion.

Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas exploration and production company with operations in western Canada and Colombia. The Company operates high-impact projects through three business units. The Canadian Business Unit is developing a solid production platform from low risk gas opportunities in central Alberta and an extensive inventory of Bakken light oil locations in southeast Saskatchewan, complemented by new exploration projects and a large undeveloped land base. The Latin American Business Unit, operated by Petrobank's 76.6% owned TSX-listed subsidiary, Petrominerales Ltd. (trading symbol: PMG), is a Latin American-based exploration and production company producing oil from three blocks in Colombia and has contracts on 13 exploration blocks covering a total of 1.5 million acres in the Llanos and Putumayo Basins. WHITESANDS Insitu Ltd., Petrobank's wholly-owned subsidiary, owns 70,720 net acres of oil sands leases with an estimated 2.6 billion barrels of gross bitumen-in-place and operates the WHITESANDS project which is field-demonstrating Petrobank's patented THAI(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. THAI(TM) is a registered trademark of Archon Technologies Ltd., a wholly-owned subsidiary of Petrobank Energy and Resources Ltd.

Invest in Alberta Real estate

visit:

http://www.westerninvest.com

Ya keep em coming John, hopefully Ed will act bravely and fix the mess.

Royalty review just good business

Diane Francis
Financial Post

Saturday, September 22, 2007

The Americans are frothing at the mouth. So are oil company CEOs, but Alberta Premier Ed Stelmach was absolutely correct in commissioning a report to examine oil royalties in Alberta.

The report, made public this week, recommends increasing overall royalties by 20%, equivalent to $2-billion based on 2006 revenues.

It's important to note that what is being discussed is not taxation but the royalty paid to Albertans who own the lion's share of subsurface mineral rights in the province. And they are not getting as much revenue from their resources as competing jurisdictions are, according to the report. Industry spokesmen dispute the numbers and say Alberta's take is already high enough, and any higher will drive away investment.

"We will make sure we get it right," said the Premier in a luncheon address at the Global Business Forum in Banff attended by CEOs and others.

That's, quite frankly, his job to juggle public and private interests for mutual benefit, which is why the most critical figures in this report are comparisons.

For instance, conventional oil and gas royalties and taxes in the U.S. average 67% while they are 50% in Alberta, said the report.

Non-conventional oil production -- offshore and heavy oil -- is another interesting story. Heavy oil royalties in Cold Lake are 60% compared with Nor-way's offshore royalties of 76%, California's heavy-oil royalties (and taxes) of 67.5% and Venezuela's 72%.

If these figures are substantiated then the argument for higher royalties is compelling. If not, then the recommendations should be placed in a dust-bin.

There are also those industry sources who say that even if Alberta's numbers lag and royalties go up, activity will fall, which will hurt Albertans. They point out that there are already idle rigs in the province, mostly due to low natural gas prices and high costs driven by the oilsands boom.

The boom has imposed a "tax" on most Albertans and they're not happy about it. Housing costs have leaped along with rents, labour rates, labour shortages and there are crowded schools, hospitals and roads. It's Albertans, who own the oil, whose tax dollars are financing the enhancement of provincial infrastructure.

Unfortunately, the review comes on the heels of Ottawa's income trust debacle and has led many, including American investment guru Dennis Gartman, to conclude that Canadian governments are revenue-grabbers without reason. He said he's exiting Canada.Many American investors followed his advice and hammered stocks. One analyst called the province "Albertastan".

To me, both the markets and media have been hysterical about nothing. Stelmach is not some fiscal confiscator. He's the CEO of the most valuable jurisdiction in the Western hemisphere and his review of royalties is simply prudent business practice.

As for the trigger-happy Mr. Gartner, I say good riddance and good luck. Where will he and his investing flock find another oil Promised Land? California? Norway? Venezuela? Or perhaps Putin's Russia?

dfrancis@nationalpost.com
© National Post 2007

Anybody reading this stuff?

Alberta's fate in Eduardo's hands

Don Braid
Calgary Herald

Saturday, September 22, 2007

The government is already polling furiously to find out what Albertans think of the startling royalty report released this week.

But the strategists think (or hope) they already know the answer -- most people will find it quite good in part, but too radical to be swallowed whole.

Specifically, they expect the majority to be uneasy with the recommendation against "grandfathering" existing oil and gas deals.

If that part of the report is adopted, new royalties would be charged on all old projects.

The very idea of rewriting

legal deals is so inflammatory that it has already prompted a private warning to the government from Washington. (As usual, the Americans can find us on the map when there's money at stake.)

That single suggestion is the basis of the spreading comparisons between Venezuela's Hugo Chavez and our own

Premier Eduardo Stelmach.

The linkage is ridiculous. Chavez nationalized some companies. Stelmach will drive energy investment out of

Alberta the day ND Leader Brian Mason seizes the Petroleum Club.

Historically, the very notion of an Alberta Tory government turning hostile to the industry is absurd. For 35 years, Toryism and oil have gone together like coffee and cream, with huge benefits to politicians, business, and the province at large.

But the balance has gradually shifted over a long period of rising prices and profits. The companies, and many individuals, have grown wealthy from an oil and gas regime that is now too soft. It has to change.

In this situation, the great political trick is to keep the golden goose healthy, while diverting some of its daily feed back to the public good.

That's why the anti-granddaddy bombshell is having its political uses. Oilpatch leaders will probably agree to significant royalty increases, just to make sure that existing projects are grandfathered.

They also know -- as does Stelmach -- that industry reaction to the report is not uniformly hostile.

Alberta oilmen who span the world get annoyed at the deals offered state oil companies in Alberta, when the terms in their home countries are always more stringent.

And you won't find a brighter icon of Big Oil than Sam Spanglet, the retired Shell executive who sat on the panel. The Liberals accused him of conflict of interest because he still owns some Shell options. "The review process is tarnished from day one," Liberal Leader Kevin Taft fumed in February.

But Spanglet, to the Liberals' shock and awe, turned out to be a man of high integrity.

He was the toughest questioner on the panel and now backs the report. Spanglet says the industry should stop whining and control its costs -- implying that the royalty regime is so lush there's not much incentive to do that.

Now, why would a guy like Spanglet take this view if there were no truth in it? Why would these establishment panelists, all with a strong understanding of the industry, risk their Pete Club invitations if they didn't believe passionately that they're doing the right thing for the province?

Maybe they went too far. It seems unfair to change existing deals. But the panel's general call to action is irresistible.

Successful Alberta premiers, from Ernest Manning to Peter Lougheed, never lost sight of some vital points: the province owns the oil; the companies pay for the privilege of profiting from it; the government sets the rate of payment; and one fine day that rate will change. That's the deal, and everyone knows it.

Industry leaders can warn of disaster all they like. They can threaten to pull out. They can even compare Stelmach to a South American populist/nationalist demagogue.

But no premier who wants to survive can submit to threats and bluster, or leave the decisions to the oil industry.

If he remembers all that, and gets the details right, Eduardo from Andrew could be one popular leader within a few months.

Chicken Little still hasn't got it right
Royalty review recommendations evoked much sound and fury -- apparently signifying nothing

Gary Lamphier
The Edmonton Journal

Saturday, September 22, 2007

EDMONACAS, Albertazuela - Sadly, the party may be coming to an end. At least, that's the ominous warning from Big Oil.

A stunned silence is said to have descended on downtown Calgary, as shell-shocked energy execs ponder the potentially devastating implications of this week's royalty review report, which calls for a $2-billion -- or 20 per cent -- increase in the province's annual oil and gas take.

The very future of Alberta's $140-billion oilsands megaboom -- the province's primary economic driver -- now hangs in the balance as Ed Stelmach's neophyte Tory government stares down the powerful oil lobby, and considers whether to adopt the royalty panel's recommendations.

Why, the well-coiffed salesmen at Calgary's Bentley dealership must be tossing and turning in their sleep, fearing a slowdown in luxury car sales.

Talk about drama. Talk about high stakes.

Talk about a world-class gusher of ridiculously overblown rhetoric.

Welcome to Albertazuela -- or "Albertastan" as one overheated energy analyst dubs it -- where the fear mongerers want you to believe that any talk of updating the province's royalties (especially the decade-old oilsands royalty regime) is merely the first step toward embracing the extremist, nationalist policies of Venezuelan strongman Hugo Chavez. Give me a break. What complete and utter nonsense.

Of course, the oil lobby will never admit this in public. The suits are well paid, thank you, to represent the interests of their shareholders, and that's just what they'll do.

Damn the facts.

As the review panel's 104-page report confirms in exhaustive detail, the Alberta government's resource take now lags that of many other jurisdictions around the world -- including several (obviously communist-infiltrated) U.S. states.

While oil prices have quadrupled since 1996, when the oilsands royalty regime was adopted, Alberta has stood pat as other jurisdictions hiked their royalty rates. No wonder the number of multi-billion-dollar oilsands projects in this province has mushroomed in recent years, despite the huge cost overruns.

And no wonder Pedro Van Meurs, one of the world's top experts in royalty rates, regards the self-serving rhetoric of Calgary's oil companies -- many of which racked up record-level profits in 2006 -- as entirely predictable.

"The reaction from the oil industry is always 'don't do it, leave it alone,' " he told Journal reporter Archie McLean, after the royalty report was released Tuesday.

"Obviously, that is what they're supposed to say." Right.

Ironically, several industry reps who attended the review panel's hearings referred to a decade-old Van Meurs study, showing Alberta ranked high in terms of the overall government take. But they conveniently ignored a Van Meurs study done earlier this year, which came to the opposite conclusion.

"The (review panel's) recommendations are entirely reasonable. If I was premier I would implement them in their entirety," says Van Meurs. Full Stop.

Needless to say, oil and gas stocks, especially those most exposed to the oilsands, have been savagely crushed since the review panel released its report, and the hysterics in Calgary began screaming from the rooftops.

Why, the Toronto Stock Exchange's lead energy index plunged a staggering, ah, 2.7 per cent in value over the past three sessions. One has to reach all the way back to mid-August, when the index fell 4.5 per cent over three days.

Sure, most oilsands stocks took a slight hit on Wednesday, and many were down again Thursday -- no doubt partly driven by the alarmists themselves, who were doing their best to scare the daylights out of investors.

But by Friday, the correction was already over, and virtually every oilsands stock on the board was back in gear.

Moreover, although major players like Suncor and Canadian Natural Resources hit all-time record highs on Tuesday, not a single newspaper reported this Wednesday, when the stocks fell. It didn't fit the prevailing narrative of doom and gloom, I suppose.

What matters is whether Stelmach has the guts to stand up to Big Oil.

Although the premier told reporters he wouldn't be "intimidated" by the oil lobby the day after the report came out, he sounded much more conciliatory by Thursday, telling reporters at a business conference in Banff that he's ready to discuss the report with industry.

Meanwhile, Murray Edwards, vice-chairman of Canadian Natural Resources was busy damning the report's "draconian" proposals and "shrill" tone.

I'm guessing Edwards was feeling considerably more sanguine by the close of trading Friday. Canadian Natural's shares jumped $1.64 or 2.2 per cent on the day, leaving the stock within four per cent of its all-time high. Looks to me like investors already smell a deal coming.

glamphier@thejournal.canwest.com
© The Edmonton Journal 2007

This pro-business panel put Albertans first

Graham Thomson
The Edmonton Journal

Saturday, September 22, 2007

I hope you'll bear with me through another column on the royalty review report.

It'll be my third this week and I'm beginning to wonder if I'm obsessed with the thing. I mean, I carry a copy with me wherever I go like a teenager with an edition of Catcher in the Rye.

I've read the report so many times it's as dog-eared as a beagle puppy -- and, I have to say, it's just as adorable.

It is a clear-headed, powerfully written, 104-page indictment of how Albertans have not been treated fairly on energy royalties despite government protests to the contrary the past five or six years.

I even took the report to bed this week to reread the bits about how to fix government ineptitude, increase royalties and ensure we as Albertans get "our fair share."

For an observer of Alberta politics it's as good as porn. I should be reading it under the covers with a flashlight.

And I have to admit to a guilty pleasure when realizing how the report has sent a shock wave through the energy industry and Alberta's governmental establishment. As wake-up calls go, this is a howitzer.

Critics of the report are slamming it as something of a communist plot, calling it draconian and warning if its recommendations are adopted our province will become akin to socialist Venezuela or a third-world "Albertastan."

The report's critics make it sound as if the report was written by Alberta NDP leader Brian Mason.

Mason, of course, had nothing to do with the report. Neither did Liberal leader Kevin Taft.

The report was written by a six-member, blue-ribbon panel named by the government. The members included two economics professors, a chief economist for an Calgary-based energy research firm, a businessman, a forestry executive and a former senior executive with an oil company.

If anything, the panel was seen as too pro-business. In fact, the appointment of Sam Spanglet to the panel caused a stir back in February when news broke that the former oil executive still had "a couple of million" dollars worth of stock options with Shell Canada.

At the time, Liberal leader Taft said "this royalty review process is tarnished from day one."

And the NDP's Mason said in February, "It looks to me like most of the members of this committee are attached to the corporate sector in some way."

As if to bolster the opposition's accusation, the Canadian Association of Petroleum Producers was reportedly pleased with the panel's members and their credibility.

It seemed just about everyone was predicting the panel would deliver an industry-friendly conclusion.

Viewed through that perspective, the recommendations in "Our Fair Share" are all the more remarkable. The expert panel of strong thinkers, some of whom did indeed have ties to corporate Alberta, came up with a logical and potent argument government must raise royalties on energy development by $2 billion a year.

As the report repeatedly points out: "Albertans own the resource."

That statement goes to the crux of the report's argument. And the report does a wonderful job of dismantling claims by companies that the energy industry is already paying its fair share in royalties.

On page 23, for example, the report points out "The panel was constantly told by companies and by energy industry trade groups that Alberta ranked very high in Government Take." However, those companies and groups were citing from an outdated 1997 report by an international expert. The review panel commissioned the same international expert who compiled new data and concluded "the very opposite is now unequivocally true."

The report's recommendations have the energy industry and its supporters in such a tizzy they're issuing statements that can only be described as pretzel logic.

To argue, as some have done, that it is better for the oil companies to keep surplus profits because they will generate more wealth is missing the point that the energy resources belong to the people.

The government collects the royalties on our behalf. You could certainly argue over how best to handle that money, but the $2 billion in extra royalties recommended by the review panel is our money to spend.

Or save for the future.

Or you could certainly make an argument for lower taxes or even rebate cheques.

But letting oil companies keep the money and then hand it over to shareholders would be cheating us and our children.

As the report says: "Alberta's natural resources belong to Albertans."

It's a quote worth clipping and sending to energy companies. So is, "Albertans do not receive their fair share from energy development."

It is such a great report I just might read it again tonight. Could somebody get me a flashlight?

gthomson@thejournal.canwest.com
© The Edmonton Journal 2007

I think this guy probably has the right idea:

153-unit condo for Lamont next to Upgrader Alley
'Low-end' project aimed at oilpatch construction workers

Ron Chalmers
The Edmonton Journal

Saturday, September 22, 2007

EDMONTON - Upgrader Alley has attracted a 153-unit condominium project to the town of Lamont.

Wim Jonk, owner of Wimco Properties, hopes to start work in January on his 4.5-hectare site in this town 20 kilometres northeast of Edmonton.

He bought the land in April and already has received a re-zoning from agricultural to residential use. Wimco's architect, A & E Architectural & Engineering Group, in Edmonton, is finalizing a development application, while Jonk is talking to contractors.

He expects prices in the three-storey wood-frame structures, with plastic siding and surface parking, to range from $160,000 to $250,000.

"I'm going low-end," Jonk says, although every unit will have a balcony facing an interior park on the spacious grounds.

"Later, there will be some commercial, perhaps a bakery and coffee shop and offices," he speculates. "That will take some years."

Sales of the first of three residential buildings will start when construction starts. Timing of the other two buildings will depend on sales.

Jonk says he launched this project in a town of only 1,700 people because "the land was fairly cheap and the upgraders -- and thousands of construction people -- are coming into this heartland area."

The Shell and BA Energy upgraders are under construction in the area, with six other upgraders planned.

Jonk expects buyers to include engineering and construction workers on nearby projects, other workers who will commute to Strathcona County, Edmonton or Fort McMurray, current Lamont residents and investors.

The condos will be just inside Lamont's western town limits.

This is Jonk's first development since selling his staffing service in Holland and moving to Edmonton last December.

rchalmers@thejournal.canwest.com
© The Edmonton Journal 2007

Royalty storm can't dampen upbeat mood at oilsands trade fair
Firms display inventions and muscular machines

Gordon Jaremko
The Edmonton Journal

Friday, September 21, 2007



EDMONTON - Not a discouraging word was heard Thursday as dealers in industrial supplies from cleaning fluids to computer software courted potential customers at Edmonton's first annual oilsands trade fair.

"The mood's very upbeat and positive," said Garry Bondarevich of Stewart Weir & Co., an engineering and surveying firm heavily involved in bitumen belt and upgrader alley projects.

"We're a little bit concerned," said his show booth partner, Ron McGaffin. But the province's proposed royalty hikes, revealed on the eve of the trade fair, did not cast the same shadow on the industry as on stock markets, where shares in oilsands developers dropped, he added.

"We're desperately looking for engineers and surveyors. We're short. We have the work but can't find the people," McGaffin said in reporting the industry did not change overnight after the provincial royalty review panel released its report Tuesday.

"It's a tempest in a teapot," said exhibitor Bill Hume.

As a mining engineer with North American Construction Group, a major oilsands construction contractor, he pointed out that an immediate bitumen belt slump is unlikely. "The projects that are out there working now are committed for the long term," Hume said.

"There was no panic," North American business development manager Barry Grundy agreed.

Hume added that as an avid oilsands investor in his personal affairs, "I was upset" at first by the royalty report and the market reaction. But after working out the effects of the proposed increases he said "it's been a bit overblown."

If the proposed royalty increases go into effect, the extra burden on the industry works out to about 32 cents per barrel of production currently, 86 cents in 2010 and $1.35 in 2016, the engineer calculated.

Linus Hakimattar, an exhibitor for the IBM "oilsands centre of excellence," called morale at the trade fair "very positive. With oil and the Canadian dollar at all-time highs there's a lot of optimism about the long-term future," he said.

He echoed fair goers in predicting "a political settlement" on royalties between industry and government.

"There's a lot of tire-kickers here," said Stuart Wright, demonstrating a line of industrial cleaning products that his Evergreen Solutions already markets to oilsands projects.

"Conventional oil and natural gas drilling has been on the down slide for six months. That has nothing to do with any talk about royalties," said Wright.

When it comes to the oilsands fair, "there's no sign of a slowdown" in early work on the second annual Edmonton show next year, said event director Wes Scott of dmg world media (Canada) inc.

This year's inaugural show outperformed its former Fort McMurray location by attracting more than 600 exhibitors and registered visitors.

gjaremko@thejournal.canwest.com
© The Edmonton Journal 2007


Close

Stelmach's moment of truth
Will he have the backbone to bring in royalty changes and face down the oilpatch?

Graham Thomson
The Edmonton Journal

Thursday, September 20, 2007

CALGARY - When Alberta government MLAs left their special caucus on Wednesday, they didn't walk out as much as they scurried out.

They scurried past the news media and out the door of McDougall Centre, refusing to comment to reporters who had spent hours waiting for the meeting to break up.

Even MLAs who stopped to answer questions were scurrying verbally -- using all their political skills to speak without saying anything.

Not one of them wanted to give a definitive opinion on the most explosive issue to hit provincial politics in years: the report by Alberta's royalty review panel claiming we don't get our fair share from energy development.

The MLAs' reaction shouldn't be surprising. They are still reeling from the report that hit them like a runaway oilsands truck on Tuesday. The report offers a logical, comprehensive and powerful argument that government should substantially raise energy royalties.

Some MLAs talked but it's obvious they don't know what to say.

"It's the report we asked for," said Health Minister Dave Hancock.

"It's got a lot of good information in it and it requires a thorough reading and understanding and digestion."

"I agree that Albertans need to be treated fairly," said MLA Jack Hayden. "We definitely need to treat Albertans fairly."

"It's been a while since there's been a review and it was time to do another one," said MLA Doug Griffiths.

Harvey Cenaiko, a Calgary MLA who won't be running next election, came the closest to giving an opinion. "The contents of the report are very good," he said.

But nobody came out and said the report should be adopted or rejected.

In fact, nobody admitted to actually reading it. MLAs said they hadn't had time.

During Wednesday's caucus, they were briefed by Bill Hunter, the chairman of the panel that wrote the report.

Afterwards, Hunter said diplomatically he got a varied response from MLAs in the meeting. Some MLAs congratulated him, others were skeptical of his findings that Albertans were shortchanged by $1.9 billion in royalties last year alone.

PERCEPTION OF INEPTITUDE

One MLA told me later that Hunter had received a "frosty" reception from some in the room.

These are the MLAs who won't or can't believe the government was so inept as to let billions of dollars slip through its fingers over the past five or six years.

They support the energy company argument that, if adopted, the report's recommendations would damage the industry by raising royalty rates too high.

Their argument is not just economic, of course, it's also political.

If Premier Ed Stelmach accepts the report's recommendation he will be admitting the government under former premier Ralph Klein was inept -- and that government was made up of just about every MLA in Wednesday's caucus meeting.

And that is why Bill Hunter's report is so exceptional. It is not just a smoking gun proving Albertans did not get their fair share of energy revenues, it is still very much a loaded gun pointed at the head of the Stelmach government.

If he accepts the report, he risks implicating himself and fellow MLAs as being derelict in their fiduciary responsibilities under Klein. If he rejects the report, he might as well hand it over to the opposition to use as their platform in the next election.

No matter what decision Stelmach makes, he risks shooting himself in the head.

He is in a precarious position which is all the more exceptional because he did this to himself by commissioning the report as part of a promise made during the leadership race.

For that Stelmach should be given considerable credit.

He formed the review panel, gave it a generous mandate and set it loose upon the energy sector. When the panel submitted the report on Tuesday, Stelmach made it public minutes after receiving a copy himself.

It is the kind of behaviour that would have been unthinkable under the Klein government that saw controversial reports as akin to radioactive waste suitable only for disposal deep underground or, if technology allowed, being shot into the sun.

Stelmach won't say what he'll do with the report until mid-October. However, on Wednesday he hinted broadly he just might accept it.

When asked what he would say to critics who think he doesn't have the backbone to implement the report's recommendations, Stelmach said: "They're in for a surprise. I won't be intimidated, as I said before, by any position taken by either the oil industry or others that may take a different opposing position. We're there to make the best decision."

That decision will come mid-October. We'll see then if the rookie premier will demonstrate leadership and take a strong stand -- and end 10 months of Stelmachian scurrying.

gthomson@thejournal.canwest.com
© The Edmonton Journal 2007

More room to manoeuvre
Royalty report allows Stelmach chance to fine-tune new terms

Calgary Herald

Thursday, September 20, 2007

Premier Ed Stelmach's government cannot ignore the royalty review it asked for, but neither should it adopt it paragraph by paragraph, as review-panel chairman Bill Hunter demanded last week, saying it should not be "cherry-picked."

The report is a radical document, here and there recommending arbitrary measures over market solutions, that old contracts not be grandfathered, and treating consultation with industry as a barely necessary inconvenience.

Yet, strangely that all works to Stelmach's advantage.

For, change is in the offing, and the energy industry, especially that part of it working in the oil sands, knows it. The 1997 agreement that coaxed today's extraction complexes into existence, has more than done its job. It makes sense to rewrite the rules so that future projects yield a higher return to the taxpayers.

The problem for any Alberta government would be the howls emanating from the industry.

Enter Hunter, with "Our Fair Share." By presenting such an extreme solution, it gives Stelmach room to come back with less onerous terms, that would still extend the province's total take -- even if not by the $2 billion that Hunter says would have come its way, had his principles been applied to 2006 production at 2006 prices.

Where Stelmach can easily give is in dropping such recommendations of the Hunter panel, as that old contracts not be grandfathered.

Alberta's energy industry has been built on trust, and the expectation that a deal made with government, would stay made. Yet, this report effectively proposes the province unilaterally terminate contracts entered into in good faith between former governments and investors, and arbitrarily establish new ones.

It was a surprising, even offensive, recommendation. One wonders how rich last year's $2.1 billion bonus bids would have been, had the Hunter review's proposals governed the market.

Nor is it conducive to investment that consultation with industry be for appearances sake only. Speaking of a new regimen to establish a market price for bitumen, for example, the report first dismisses market forces as "unlikely to resolve this issue in the best interests of Albertans," then continues, "Consultation for this purpose, as a point of clarification, would not entail or imply negotiation nor is it intended to introduce any sense of veto power or consent requirement on the part of the oilsands industry."

Stelmach should be able to give that away with little fuss, as well. Then, he may start to pick cherries.

While high oil prices do not translate directly into surplus profits -- exporters lose on the Canadian dollar's galloping value much of what they make on oil's galloping price denominated in US dollars -- industry has this ace: An insatiable market, just across the border, in a tense world, with the ability to pay. A government that acknowledges its higher costs, and defers to Alberta's tradition of honest dealing, can reach a satisfactory arrangement with industry.

Above all, Stelmach is as entitled as the Hunter panel -- as leader of an elected government, more so, perhaps -- to decide what is, in fact, fair.

It is an unfortunate hole in the Our Fair Share report, that nowhere does it define "fair."

What is fair? An agreed rate of return on investment, or revenue? A 50-50 split between Alberta and the producer? Two thirds-one third, as Hunter suggests for oilsands and natural gas? To the extent the report answers the question, it infers that Alberta should be in the middle of a pack that includes countries with vastly differing geologies and recovery costs, and not a few political systems.

To that point, it is hardly an argument for Alberta being shortchanged, that it squeezes less from producers than Angola, or Venezuela. Fair, then, becomes what Hunter thinks is fair.

And, that's fair enough, as long as everybody knows there's no objective standard in use here, and that Hunter appears at home with arbitrary dictums.

He presents his report as a whole prescription for Alberta's royalty future, but it would be better treated as the opening bid in a process to recalibrate the province's royalty structure.

Stelmach and his cabinet must examine it carefully. Then, they must decide what they think is fair to both Albertans and the industry, and act accordingly. But make no mistake, there is no question industry will pay more: The question is: What is really fair?
© The Calgary Herald 2007

September 20, 2007
Oil suits reeling at royalty report
By NEIL WAUGH

They didn't actually have grief counsellors standing by in the Calgary oil towers yesterday morning.

But there was enough outrage and anguish for the Bow River to burst its banks with crocodile tears.

"At first blush," gulped Canadian Association of Petroleum Producers spokesman Greg "Sky is Falling" Stringham, "this is far worse than anticipated."

He branded Bill Hunter's insightful probe into Alberta's oil and gas royalty troubles and ways to fix them a "bad report."

And warned darkly of political consequences.

Expect Ghost Resources or Mirage Oil and Gas to announce the never-was Phantom Project is on hold any day now.

"It's only a report so far," he said. "The real crunch comes when they decide what to do and what to take out of the report."

Which, in a sentence, is Big Oil's strategy as the Stelmach Tories attempt to claw back $2 billion a year in energy revenues - largely from Calgary's oilsands aristocrats,who have been awarding themselves multimillion-dollar annual salaries while the owners of the resource get a penny on the dollar payout until the massive capital costs are recovered.

Hunter and his panel revealed a disturbing problem when they recommended "ring fencing" around each oilsands project to make it "absolutely clear, transparent and auditable" what are the "eligible expenditures."

Hunter is upfront and explicit about what the problem is.

"Albertans do not receive their fair share from energy development," he spat in his letter to Finance Minister Lyle Oberg, who still appears to be a royalty review skeptic.

"And they have not been receiving their fair share for quite some time," he added.

Former Tory energy ministers Pat Nelson, Murray Smith and Greg Melchin should hang their heads in shame. Even Premier Ed's energy czar, Mel Knight, appears to be in trouble here. His defence of the indefensible at the Energy and Utilities Board has not impressed the premier's office.

And now he and his bumbling bureaucrats will be tasked with cleaning up this mess of their own creation.

Hunter complained at his press conference of the morass of regulations and royalty rates which he branded "patches on patches."

He said their entire department was in a conflict of interest as both development promoters and royalty collectors.

There was also a sweet smell of vindication wafting through the legislature yesterday as Hunter's report pretty well confirmed everything this column has been saying for the last three years.

Oilsands royalty rates are ridiculously low.

The report recommends the rate after payout be jacked up from 25% to 33%. And there should be a "severance tax" that kicks in when oil hits $40 US a barrel and rises at 0.1% per buck increase. Plus the above-mentioned "ring fencing."

The panel went beyond its mandate and recommended an upgrader tax credit to encourage more bitumen refining. The premier and his caucus will make the final decision.

Maybe Stelmach already has done so, despite distressing reports of intense lobbying (I thought these guys were supposed to register?) of government MLAs by the oil tower spin doctors.

NDP Leader Brian Mason scolded that the report doesn't go far enough. But he privately admits the Tories just chopped off one of his platform legs.

Alberta Liberal energy critic Hugh MacDonald confessed "everything we have touched on has been addressed in this document."

And yesterday the premier warned the oil suits that if they think he's going to blink after they started leaning on the MLAs, "they're in for a surprise. I won't be intimidated," Stelmach snapped.

Expect the premier to outline his royalty plans to Albertans on his Ed TV broadcast in late October, and to make royalty reform his Bill No. 1 in the spring session.

That will be followed by a budget speech from Treasury Board president Lloyd Snelgrove (Oberg will have worn out his welcome by then) announcing a nice personal tax cut thanks to new oil- sands billions. The election will soon follow.

Gonna get a lot of press this one


September 19, 2007
Stelmach ready for oil wrestle

CALGARY — Alberta Premier Ed Stelmach says he “won’t be intimidated” by the oilpatch as his government decides how to handle a report urging the province to grab $2 billion more annually from oil and gas companies.

Emerging from a government caucus meeting on the “challenging” royalty review report Wednesday, Stelmach said he expects it to provoke strong views from the energy industry and all Albertans.

A final decision on the royalty regime will be announced within weeks. To see the report, click here.

“The report’s significance is huge. It’s huge for Albertans, for the future of this province and really for the country of Canada,” Stelmach said.

“We will be listening to all Albertans, but I won’t be intimidated by any positions taken. We’re going to review it, calculate it carefully and see what the implications are because this is really setting a policy for the next 20 or 30 years.”

The royalty review panel’s report, called “Our Fair Share,” said Albertans have been shortchanged by the oilpatch for quite some time.

And it said oilsands projects should pay roughly 36 per cent — with no retroactivity for older, existing facilities. But it said a royalty holiday would continue for new projects to encourage companies to undertake the multibillion dollar commitment required to produce oil in the northern Alberta oilsands.

High-production oil and natural gas wells should also pay higher royalties, although a large number of low-production wells would pay less.

The report also raised questions about how the Alberta government regulates the energy industry, noting that the Department of Energy shouldn’t be responsible for maximizing activity in the oilpatch and ensuring Albertans get their fair share from royalty programs.

Former premier Ralph Klein, who refused to increase Alberta’s take from the oilpatch over the past half-decade as oil and gas prices soared to unprecedented levels, lashed out at the panel Wednesday.

“My province has a fair, clear and comprehensive regulatory regime where the rules are the same for everyone — and those rules don’t change on a whim,” Klein said during a speech to a petrochemical convention.

“Predictability and stability are what separate Alberta from places like Venezuela, where the government holds foreign companies hostage by arbitrarily imposing massive hikes in royalties and taxes.”

Klein refused comment after his speech.

Alberta businessman Bill Hunter, who chaired the royalty review panel, said Wednesday that great efforts were taken to make sure Alberta remains the best “investment opportunity in this world for oil and gas.”

And Hunter disregarded initial oilpatch reaction that said the report was too punitive and would cripple the sector.

“We used international analysis that say our neighbours get much more than we do. We’re in the basement in the rating of our government take,” he said.

“I think the point of our recommendations is that as Albertans, we own the resource and there’s an expectation that we should get 100 per cent of the rent. And it’s up to industry to convince us why we would take anything less than 100 per cent.”

Stelmach said Alberta’s response to the report needs to balance the needs of Albertans as owners of the resource against the energy industry’s need for a competitive fiscal regime in an era of swirling cost pressures.

On the Toronto stock market Wednesday, shares in most of the major oilsands players slid by several per cent.

Energy analyst Andrew Potter said in a research note that he’d expected a “slight negative reaction” in the markets, although most of the news was likely anticipated and already discounted in the share prices.

Pretty quiet here with all the hubbub about the royalty review elsewhere.

Nuclear power buyer not for real
Firm behind Peace River reactor plan calls claim a misunderstanding

Gordon Jaremko
The Edmonton Journal

Monday, September 10, 2007

No deals or commitments have been made, said Energy Alberta Corp. public relations director Guy Huntingford, who called the claim an unfortunate misunderstanding.

There was one inquiry about the potential for such a large power supply, he said.

Huntingford said Energy Alberta, created by Calgary entrepreneurs Wayne Henuset and Hank Swartout as a marketing partner for Atomic Energy of Canada Ltd., is still meeting with prospective customers who can't be named for confidentiality reasons.

The company did not purchase the Peace River site, but rather reserved it by purchasing an option to buy the land if needed for the planned $6.2-billion reactor, Huntingford said.

When Peace River was announced as the location for the proposed nuclear plant on Aug. 27, many Albertans were left wondering who Energy Alberta's claimed mystery buyer could be.

"We are really wondering who that buyer might be," said Marwan Masri, president of the Canadian Energy Research Institute.

The most popular guess, an oilsands project, especially puzzled those at the institute, a semi-official agency supported by government and business foundations that has access to industry information. Its data identifies the northern Alberta bitumen belt as a net electricity supplier, not a buyer.

A CERI study, done while Energy Alberta and AECL negotiated the Peace River reactor location, concluded northern Alberta will soon produce more electricity than it uses.

"Alberta's oilsands operators are an independent breed. The less they have to rely on anyone else the better," said a summary of the CERI report. "They need lots of steam and some electricity to produce the bitumen and synthetic crude oil, and prefer their operations to be self-sufficient if at all possible."

By spinning turbines with steam from thermal production processes, a chain of "co-generation" plants makes power for oilsands complexes and sells surpluses into the Alberta electricity grid.

North of Fort McMurray, Suncor has 410 megawatts of power generation. Syncrude makes 350 megawatts.

The Athabasca Oil Sands Project generates 340 magawatts with co-generation units at its northern mine and Scotford bitumen upgrader near Edmonton.

The Horizon and Long Lake mega-projects, currently under construction in the Fort McMurray region, both include power plants.

The oilsands project that would be closest to the proposed CANDU reactor, Shell Canada's Carmon Creek development 40 kilometres northeast of Peace River, has its own plan for steam-powered co-generation.

All the projects make excess electricity and currently sell an estimated 500 megawatts into the grid.

At Cold Lake, for instance, Imperial Oil makes 170 megawatts, enough to pump out 150,000 barrels of oil per day, with about 50 megawatts of electricity left over for sale to the grid.

Chevron Canada gave a one-word answer when asked if it would want atomic power for its Ells River project west of Fort McMurray. "No," said company spokesman Dave Pommer.

Royal Dutch Shell subsidiary Sure Northern Energy is also not using nuclear power for its bitumen leases in a new development area northwest Fort McMurray.

"It's premature for us to have made any commitment with respect to power needs," spokesman Kurt Kadatz said. "It's not really a project yet."

Test drilling is underway to determine the nature of the deposit, he said.

Companies with projects in upgrader alley northeast of Edmonton say they will decide later on a mixture of do-it-yourself power generation and purchases from the provincial grid.

No Edmonton-area development would come close to using the amount of power the Peace River reactor would generate.

The biggest project, Shell's 400,000-barrel-a-day chain of four new Scotford upgraders needs 425 megawatts -- about 19 per cent of the initial 2,200 megawatts the Peace River nuclear plant would initially produce. Regulatory applications say co-generation is a possibility and do not even mention atomic power as an option.

Only one known project, a plan by TransCanada Corp., involves electricity on the scale offered by Energy Alberta.

But TransCanada's Northern Lights Transmission proposal is dedicated to exporting excess electricity produced by oilsands complexes. The plan calls for a new power line out of Fort McMurray to run south through eastern Alberta then angle west into the northwestern United States.

TransCanada and CERI estimate oilsands co-generation could produce more than 3,000 megawatts of surplus electricity for export.

There have been no talks or contacts between the nuclear power promoters and Northern Lights, said TransCanada communications officer Shela Shapiro.

Oil patch feeding frenzy predicted

DAVID PARKINSON

September 7, 2007

The Canadian oil patch could be hit by a major round of takeovers by multinational giants in the next year, Jeff Rubin of CIBC World Markets predicts, as the global energy industry looks increasingly to Alberta's rich oil sands as one of the few major world oil reserves unfettered by political meddling.

Speaking at a conference for institutional clients, Mr. Rubin, the investment bank's chief economist and chief strategist, anticipates oil sands firms will receive premiums of 40 to 45 per cent - roughly in line with the prices paid in major takeovers in the energy sector as well as the premiums paid for major Canadian mining companies in the past year.

"The Canadian oil sands, as the single most important energy asset in the world open to private capital, its ownership will reflect the global oil industry. And the process in which the global oil industry is going to assert ownership over that sector is by buying out the people who own it now."

He said the oil sands offer both deep reserves and a government that doesn't insist on owning a piece of the action - which has fast become a rare combination as governments stake a bigger claim on key oil resources. In such places as Venezuela, Russia and Kazakhstan, governments have demanded ownership in major deposits, delaying development, chasing away major energy companies and costing them billions in writedowns.

"The fact of the matter is that most oil reserves in the world are now the exclusive preserve of state oil companies." As a result, he said, "the Canadian oil sands represent somewhere between 50 and 70 per cent of the investable oil reserves in the world."

He said that given the strong cash flows generated at current commodity prices, big oil companies wouldn't have to rely on debt markets to finance acquisitions, meaning the crunch in credit markets wouldn't pose an impediment.

Mr. Rubin also predicted that global oil prices will continue to climb, as the global economy remains "better than just fine," despite stumbles in the U.S. economy linked to the subprime. He predicted West Texas intermediate oil prices would average $80 (U.S.) a barrel in the fourth quarter, $90 a barrel in 2008, "and will hit triple digits by the fourth quarter of next year," fuelled by surging demand among developing economies.

Mr. Rubin's bullish outlook for energy is a key factor behind his prediction that Canadian stocks are poised for strong gains. "The meltdown of the U.S. subprime mortgage market will be temporary and a non-lethal shock to a continuing bull market in Canadian equities," he said.

He forecast that the S&P/TSX composite index would reach 15,000 within the next six months, and would reach 16,200 by the end of 2008 - up 17 per cent from yesterday's close of 13,795.69.

"If we're talking about the TSX, what really matters is how strong the global economy is, because so much of the TSX is energy and resources."

Statoil forges ahead in Alberta oilsands
Engineering studies now underway

Ashok Dutta
Calgary Herald

Friday, September 07, 2007

Norway's Statoil will carry out three stages of front-end loading (FEL) studies for its proposed 200,000-barrel-per-day oilsands upgrader to be built at Fort Saskatchewan, as part of efforts to handle rising capital costs and get a better estimate on required investment levels.

FEL is defined as basic engineering to determine the various elements of a project or a processing plant.

"We are at the tail end of FEL-2," Geir Jossang, president and chief executive of Calgary-based North American Oil Sands Corp., said on Thursday. "The next stage will be to complete FEL-3, before preparing a basic design to serve as the basis to move forward."

He did not commit to any timeline for completing the various stages of engineering studies, stating that it was still early stages.

NAOSC is 100 per cent owned by Statoil and is the owner and operator of 1,110 square kilometres of oilsands leases in the Athabasca region, estimated to contain recoverable resources of 2.2 billion barrels. The portfolio is expected to yield more than 200,000 bpd of synthetic crude oil at the end of the next decade through construction of an upgrader.

"At present, we are producing globally 1.2 million barrels per day of oil equivalent," said Statoil's president and chief executive, Helge Lund. "Of this, the Norwegian continental shelf accounts for one million barrels and the remaining volume is from outside of Norway. Looking ahead, we want to maintain output levels until 2015. The aim will be to increase production elsewhere and our entry into Alberta's oilsands has to be viewed in that context."

In August, NAOSC said it had received approval from the Alberta Energy and Utilities Board for its Leismer demonstration plant in northern Alberta. First production is planned for late 2009/early 2010. The steam-assisted gravity drainage project calls for bitumen production from 22 horizontal well pairs linked to four well pads. Site preparation is already underway for the Leismer plant.

"We are at the very beginning of the project and our first goal will be to produce 10,000 bpd," Lund reiterated.

"Rising costs is not specific to Calgary, but is today an industry-wide issue. However, there are valid reasons for Statoil to invest in Calgary."

According to Lund, the lure of long-term barrels, political stability and access to the world's largest oil consumer have been major deciding factors.

"We also wish to strengthen our heavy oil portfolio," he said, adding that Statoil already has a 10 per cent stake in the Sincor extra heavy oil project in Venezuela. The $4.2-billion project, which is a joint venture between France's Total and Caracas-based PDVSA, is designed to produce about 200,000 bpd of heavy oil.

In late August, Statoil also announced that it was awarded 36 leases in the Alaminos Canyon and Keathley Canyon in the Gulf of Mexico.

"Globally, there is a shift towards the development of heavy oil resources," commented Paul Horsnell of London-based Barclays Capital. "Even conventional giants like Saudi Aramco, which is still home to the world's largest reserves of light oil, has embarked on the 900,000-bpd offshore Manifa field."

Lund believes that there is logic for international and state-owned oil companies to look into "unconventional resources" to meet the growing global energy demand.

"Oil output from OECD (Organization for Economic Cooperation and Development) nations are expected to peak around 2105 and the world will depend increasingly on a few nations . . . Russia, Middle East and Canada," he said, adding "The way to make up for it would be to access tight gas and oilsands resources."

Admitting the offshore sector is also receiving a fair share of attraction, he pointed out that Statoil's expertise in handling complex subsea pipelines, production platforms and related structures will come in handy for its future operations.

"We think Statoil will have an edge, but a lot needs to be done further to develop new technology," Lund said.

Colin Lothian, Middle East senior analyst with Edinburgh-based Wood Mackenzie, said two significant challenges for oil companies looking for oil offshore are rising costs of operation and the availability of rigs.

"Reservoirs to depths of 3,500 metres and more are being targeted now by the industry," he said.

Offshore Canada will also be a target area for Statoil, which is bracing itself for a merger on Oct. 1 with the oil and gas assets of fellow Norwegian producer Norsk Hydro.

"We view the fields as a good portfolio of assets," said Lund.

Norsk Hydro is a stakeholder in the Hibernia, Hebron and Terra Nova fields in offshore Newfoundland. Shares of Statoil closed at $30.67 US Thursday in New York, up one per cent.

adutta@theherald.canwest.com
© The Calgary Herald 2007

Alberta deals OSUM a blow with test decision

NORVAL SCOTT

September 6, 2007

CALGARY -- Alberta Premier Ed Stelmach bowed to public pressure late Tuesday and stopped companies from testing for oil beneath water bodies in the province, a decision that was welcomed by environmental protesters but could threaten the future of OSUM Oil Sands Corp.'s crude project at Marie Lake.

Privately held OSUM had secured approval from provincial regulators to test for oil contained underneath the lake, which is 300 kilometres northeast of Edmonton, and plans to develop a crude project there. But Mr. Stelmach overturned that decision, calling the technology that OSUM plans to use to extract crude as "unproven" ... "I have decided that seismic testing on Marie Lake will not proceed," he told reporters in Edmonton late Tuesday.

That's a setback for Calgary-based OSUM, which is essentially being prevented by Alberta from pursuing a crude project on land leased to it for that very purpose. OSUM bought the Marie Lake lease last fall for about $3-million in a Crown land sale held by the provincial government's Department of Alberta Energy.

The company had hoped to extract 30,000 barrels of crude a day from under the lake via shaft-and-tunnel technology, accessing the oil via wells drilled from below the crude reservoir, rather than from above.

Last month, Alberta Sustainable Resources Minister Ted Morton approved OSUM's plans to test for crude at the site, albeit with strict environmental and safety conditions. But local residents object to the plans, alleging Alberta Energy failed to consider whether Marie Lake is suitable for development. The residents say seismic testing could damage the lake's fish stocks and ecosystem. They also registered concern about the potential impact of the oil project itself, which has yet to receive regulatory approval.

OSUM, which recently raised $56-million to pursue development of Marie Lake and other projects, says seismic testing has occurred on many lakes in Alberta without incident, and notes that its shaft-and-tunnel plan was developed in the Alberta government's underground test facility near Fort McMurray in the 1970s and 1980s. It also says the tunnel system has a smaller environmental footprint than traditional oil sands extraction methods, requiring fewer wells and less steam production.

But after protests last week at his riding office, the Premier overturned the regulator's decision on testing. No company will be allowed to test under any Albertan water body until ministers complete a policy for bitumen extraction in such regions, said Alberta Energy spokesman Jason Chance. He couldn't estimate how long before a policy is in place.

Mr. Chance did say Mr. Stelmach's decision was made specifically in response to concerns over the shaft-and-tunnel technology, rather than the seismic testing, but wouldn't comment on why the testing has been prevented from taking place if it wasn't a concern.

OSUM CEO Richard Todd said he learned of the Premier's decision only late Tuesday, when told by journalists, He said the company has not received a formal written indication of why the seismic application for Marie Lake has been suspended.

"We're a responsible corporate citizen who has had their regulatory approval overturned. My question is, is Mr. Stelmach really open for business to responsible Albertan companies or not?" he said in an interview. He said OSUM aims to pursue "every alternative to recover the costs of this knee-jerk action."

He added the company is treating the suspension not as a cancellation but as a delay, and looks forward to demonstrating the benefits of its technology to the provincial government and regulators.

Alberta Oilsands acquires Athabasca leases


Alberta Oilsands Inc (C:AOS)
Shares Issued 39,025,144
Last Close 9/5/2007 $1.34
Wednesday September 05 2007 - News Release

Mr. Shabir Premji reports

ALBERTA OILSANDS INC. OPERATIONAL AND FINANCIAL UPDATE

Alberta Oilsands Inc. (AOS) has acquired 22.5 sections (14,400 acres) of contiguous oil sands leases, at 100-per-cent working interest, in the heart of the Athabasca oil sands fairway near Fort McMurray.

To date there have been five penetrations drilled on the acquired oil sands leases surrounded by approximately 100 wells drilled on adjacent sections that confirms the presence of the reservoir oil sands with bitumen pay thickness ranging from 25 to 60 metres. The Alberta Energy and Utilities Board crude bitumen reserves atlas estimates that the leases contain undiscovered resource in excess of two billion barrels of original bitumen in place (OBIP).

Drilling is planned for the 2007/first quarter 2008 season to further delineate the potential for an in situ project. The prospective zone on the oil sand leases is the McMurray formation, which comprises high-quality fluvial and estuarine channel sands. The company has engaged Ryder Scott Petroleum Consultants to complete a National Instrument 51-101-compliant resource assessment on the acquired leases.

The acquisition of the additional oil sands leases increases the company's land base to a total of 107.5 sections (68,800 acres). The acquired leases in conjunction with AOS's Hangingstone assets will form the basis of the company's plan for a series of successive in situ bitumen extraction projects, likely applying SAGD (steam-assisted gravity drainage) technology.

In addition, AOS has acquired and interpreted 60 kilometres of trade 2-D seismic on its 23-section Hangingstone parcel. The data reveal four main anomalies indicating potential bitumen pay similar to the Hangingstone Meadow Creek reservoir to the south.

Shabir Premji, executive chairman of the company, stated: "AOS is very pleased to have added this large-scale oil sands property to its portfolio. We intend to aggressively pursue moving this resource to the reserves category."

As at Sept. 5, 2007, AOS had positive working capital of $14.5-million.

Pengrowth to apply the Powerwave Process
09:00 EDT Tuesday, July 31, 2007
FSC / Press Release

Edmonton, Alberta CANADA, July 31, 2007 /FSC/ - Wavefront Energy and Environmental Services Inc. (WEE - TSX Venture, WEESF - OTCBB_Pink_Sheets), a leader in technology development and implementation for improved oil recovery and optimized groundwater remediation is pleased to announce that it has entered into a pre-commercialization agreement with the heavy oil business unit of Pengrowth Corporation ("Pengrowth") to implement the Powerwave Process in an active waterflood.

Initially three, (3) Powerwave Mantis tool systems will be installed at an undisclosed Pengrowth operation in Alberta. Pengrowth's interest in Powerwave is to improve water injection rates and achieve more uniform water distribution in the reservoir as a means of increasing overall oil recovery.

Wavefront President and CEO Brett Davidson stated, "As one of North America's leading energy income trusts we are very pleased that the heavy oil business unit of Pengrowth has chosen to apply Powerwave. Pengrowth now joins Encana and ARG Resources to the growing list of oil producers who have entered into agreements with Wavefront to utilize Powerwave to unlock more oil from their reservoirs. Wavefront continues to pursue additional high-profile opportunities and anticipate similar announcements in the coming weeks."

About Wavefront Energy and Environmental Services Inc.

Wavefront is a technology-based company with a focused, strategic plan to leverage the value of our intellectual property in order to maximize oil production recovery operations, as well as provide additional solutions for environmental applications.

For further information please contact: D. Brad Paterson, CFO
780-486-2222 x224 Tel
investor.info@onthewavefront.com

ON BEHALF OF THE BOARD OF DIRECTORS
WAVEFRONT ENERGY AND ENVIRONMENTAL SERVICES INC.

"D. Brad Paterson" (signed)
D. Brad Paterson, CFO & Director

Cautionary Disclaimer - Forward Looking Statements

Certain statements contained herein regarding Wavefront and its operations constitute "forward-looking statements" within the meaning of Canadian securities laws and the United States Private Securities Litigation Reform Act of 1995. All statements that are not historical facts, including without limitation statements regarding future estimates, plans, objectives, assumptions or expectations or future performance, are "forward-looking statements". In some cases, forward-looking statements can be identified by terminology such as 'may', 'will', 'should', 'expect', 'plan', 'anticipate', 'believe', 'estimate', 'predict', 'potential', 'continue' or the negative of these terms or other comparable terminology. We caution that such "forward-looking statements" involve known and unknown risks and uncertainties that could cause actual results and future events to differ materially from those anticipated in such statements. Such factors include fluctuations in the acceptance rates of Wavefront's Powerwave and Primawave Processes, demand for products and services, fluctuations in the market for oil and gas related products and services, the ability of Wavefront to attract and maintain key personnel, technology changes, global political and economic conditions, and other factors that were described in further detail in Wavefront's continuous disclosure filings, available on SEDAR at www.sedar.com. Wavefront expressly disclaims any obligation to up-date any "forward-looking statements", other than as required by law.

THE TSX VENTURE EXCHANGE NEITHER APPROVES NOR DISAPPROVES THE CONTENTS OF THIS RELEASE WHICH WAS PREPARED SOLELY AT THE DISCRETION OF MANAGEMENT

Source: Wavefront Energy and Environmental Services Inc. (TSX-V: WEE) (Pink Sheets: WEESF) http://www.onthewavefront.com
Maximum News Dissemination by Filing Services Canada Inc.
Ph: (403) 717-3898 Fx: (403) 717-3896 www.usetdas.com

© Filing Services Canada

Land sales continue at red-hot pace

Tom McMillan
The Leader-Post

Friday, August 17, 2007

With Saskatchewan's oil and gas sector in full boom, Crown land sales are moving at a record pace.

In August, the province's sale of petroleum and natural gas rights continued its torrid pace, generating $38.2 million in revenue, Saskatchewan Industry and Resources said Thursday. The demand is being attributed to high oil prices and the first-ever public offering of oilsands rights.

"These results are the latest indicator that the oil and gas industry's confidence in Saskatchewan is growing," Government Relations Minister Harry Van Mulligen said on behalf of Industry and Resources Minister Maynard Sonntag. "This could be the beginning of substantial oilsands development."

Oil companies purchase the Crown land for the right to explore and capitalize on reserves located underneath. To date, more than $151 million in revenue has been generated in 2007, making it already the fourth-best year on record. There are two more offerings still to go this year.

The sales also continue the torrid pace set in 2006, when the province generated $176.5 million in bonus-bid revenues -- the second-highest total in Saskatchewan history.

August's sale included 12 exploration licenses sold for $14.5 million and 257 lease parcels that brought in $20.4 million. The highest price paid for a single parcel was $5.1 million by McCrank Steward Johnson, which purchased a 36-section exploration license 58 kilometres south of Weyburn.

"These sales are an excellent indication that oil companies are considering our province a good place to invest," Van Mulligen said.

This interest is being fuelled by the continued pursuit of new oil reserves and the increasing viability of targeting Saskatchewan oil.

The province's oil and gas reserves are often deeper than Alberta's, but oil prices well over $70 a barrel now make the extraction costs acceptable.

"The oil is now more financially viable for these companies to target and that seems to be spurring most of the growth," Mulligen said.

The Weyburn-Estevan area saw the most activity, with $27.7 million in bonus bids suggesting continued interest in deeper-oil targets. High interest in oilsands produced $5.3 million in the Lloydminster area, followed by the Swift Current area at $3.8 million.

Saskatchewan's oilsands have traditionally been slow to develop because the reserves are located roughly 300 feet below the surface, compared with 30 feet in Alberta.

Sales of the new oilsands dispositions included six exploration licenses that attracted $3.3 million in bonus bids.

"As supplies of oil dwindle, there will be increasing interest in this," Van Mulligen said.

"The technology is being worked on to utilize these reserves."

The most unusual aspect of the August land sale was the first public offering of oil shale exploration permits in the Hudson Bay area.

One permit went to Noble Hydrocarbons Alta Ltd., which committed to spend over $1 million, and Cavalier Land Ltd., which committed to spend $300,000 exploring the area.

The next sale of Crown petroleum and natural gas rights is Oct. 1.
© The Leader-Post (Regina) 2007

Troubled markets may impact oilsands financing
Borrowing costs create roadblock

Shaun Polczer
Calgary Herald with files from Reuters

Saturday, August 11, 2007

Troubled global financial markets threw up additional roadblocks to financing more than $100 billion worth of oilsands projects this week in the form of potentially higher borrowing costs.

Toronto's main index fell nearly 300 points in early trading Friday before recovering to finish 12 points lower at 13,466.28.

Fuelling the volatility were concerns over U.S. subprime mortgages and the spillover effect a meltdown could have on other sectors of the lending market.

According to Mark Freisen, an oilsands analyst at Calgary-based FirstEnergy Capital Corp., borrowing typically makes up more than half of the capital requirements needed to build massive new oilsands projects. "They all use significant amounts of debt," he said. "It's often a big component of the financing for these kinds of projects."

Although the full impact of the subprime woes has yet to be felt, higher interest charges could potentially add another layer of inflation to a sector of the oil industry already reeling from large capital cost overruns.

But Freisen said the reverse could also be true, where oilsands projects are seen as less risky compared to other capital-intensive investments.

"It could make the credit market more difficult," he explained. "But to put a silver lining on it, a good quality long-term asset like the oilsands might be seen as a safer place to be."

Rob Pearce, president and CEO of Northwest Upgrading Inc., plans to raise more than $1 billion to finance the construction of a new heavy oil upgrader near Edmonton.

Pearce acknowledged a potential "spillover effect," but remained confident his company will be able to find the cash it needs to bring the upgrader on stream by 2010.

"We have a large need for capital . . . and our financing plans have a significant debt component," he said. "But it's still a good borrowing environment and it still makes sense for these types of projects. These are very long-term assets and I think (the lenders will) take comfort in that."

Likewise, Marshall McRae, CCS Income Trust's chief financial officer, said the sub-prime woes would not jeopardize the company's $3.5-billion privatization announced at the end of June. That's because the $1.9-billion debt portion was firmly committed before the deal was made public.

However, McRae admitted that the plan might not have gone ahead if it were announced today.

"My understanding is that it's become difficult to put this type of transaction together because of the troubles in the debt market," he said.

Meanwhile, the contagion caused by the growing number of defaults on high-risk mortgages rippled through oil markets as governments from Europe to Japan raced to inject liquidity into the global financial system.

Central banks worldwide have injected at least $323 billion over the last 48 hours into capital markets rocked by problems at banks and funds exposed to bad loans in the U.S. mortgage sector.

The subprime crisis weighed on oil prices Friday, but declines were limited as market fundamentals overcame early losses.

New York crude fell to

$70.10 US, before rebounding to $71.47, about 10 per cent off last week's record high of $78.77. London Brent crude was down 49 cents at $69.72, off lows of $68.95.

"I suspect the speculative interests are moving to the sidelines, raising cash and attempting to avoid risk," said Mike Fitzpatrick, vice-president at MF Global.

Selling in oil has been orderly in contrast to the volatile swings in other markets and futures positions have not been cut dramatically.

"At this stage, the recent drop is viewed by some as a classic correction in a bull market," said Addison Armstrong, analyst at TFS Energy in Stamford, Conn.

Expectations that oil demand would remain robust have helped to put a floor under oil prices. The International Energy Agency said Friday world oil demand will grow at a faster pace in 2008 than this year and repeated its call for more OPEC oil.

China's imports surged 39 per cent in July versus the year-ago period, according to customs data, the fastest pace since January 2006.

OPEC has rejected calls from the IEA and oil importing nations to increase production, noting that oil inventories in consuming nations remain high.

spolczer@theherald.canwest.com
© The Calgary Herald 2007

Fort McMurray house prices hit $605,000

Calgary Herald

Saturday, August 11, 2007

So you think the average price of a single-family home in Calgary is crazy these days?

In the oil boom city of Fort McMurray, craziness has reached new heights.

The local real estate board says the average price of a single-family home has cracked the $600,000 mark for the first time.

In July, the average price rose to a staggering $605,495 -- a 29 per cent year-over-year gain.

Last year at this time, the average price of a single family-home in Fort McMurray was $469,877.

By comparison, the Calgary Real Estate Board website was reporting Friday the average price of a single-family home in Calgary in the past 30 days was $507,108.
© The Calgary Herald 2007

August 10, 2007
Oil fight brews
Marie Lake residents outraged by seismic tests
By RENATO GANDIA, SUN MEDIA

Tory MLA Denis Ducharme is slamming Sustainable Resource Development Minister Ted Morton's decision to allow seismic tests by a Calgary-based company on Marie Lake, one of Alberta's remaining pristine bodies of water.

He's also "very disappointed" that he found out about the decision through the media.

"I found that his lack of professional courtesy to me was unacceptable," Ducharme, of the Bonnyville-Cold Lake constituency, told Sun Media. "I'm certainly going to be having a discussion with the premier regarding this decision."

Ducharme suggested Morton's hands may be tied by the province's oil development policy.

"Maybe there are some changes that have to be done," he said. "Unfortunately, Mr. Morton did not show leadership."

Sustainable Resource Development approved Oilsands Underground Mining (OSUM) Corporation's seismic testing Tuesday in Marie Lake, which residents say will damage the ecosystem.

Peter Putnam, CEO and president, did not immediately return a call from Sun Media.

The company will use a so-called underground mine-based in situ process - inserting pipes under the lake to recover the oil.

Though the department approved the tests, spokesman Dave Ealey said, there are conditions the company has to meet before it can proceed.

The company has modified its test plans due to concerns expressed by nearby residents in the Cold Lake area, about 300 km northeast of Edmonton.

Marie Lake resident Hal Bekolay plans to greet seismic crews in his boat drinking coffee. "They're not going to get me off the lake unless they arrest me," Bekolay said. "It's my lake more than it's theirs."

Bekolay said residents were disgusted with the government for letting the tests go through.

"We are going to protest. If they have to lock us up, big deal. We're not taking it sitting down. They're going to have to do something drastic to get rid of me."

Edmontonian Doug Goss, who owns property by the lake, said the premier has broken his promise.

"The premier himself said that there's no seismic activity to be done on the lake until all the questions raised in the House are answered and they haven't done that."

The company plans to use instruments that will produce sound at 220 decibels, Goss said. This will affect the fish and other aquatic life in the lake, he said. Tests may also be conducted 24-7.

"Is everything for sale in Alberta?" asked Liberal MLA Bill Bonko, adding all Albertans should be concerned about the environmental hazards and quality of life issues the tests will produce.

NDP MLA Dave Eggen said it's disturbing that the government would sell leases under a lake when there are many other leases available elsewhere in the province.

Morton couldn't be reached for comment.

BQI Schart TA signal strong bull wave -



BQI TA LT #1 bull wave done -
BQI TA LT #1 correction wave done -



BQI TA LT #2 bull wave started -

Elliott pattern the 5-wave cycle -
its 4 more bull waves to GO -

More N/R upon the company’s September-October -
update -

BQI’s stock will be propelled upwards towards -
$22 per share as the 2nd LT bull wave breaking out? -

and some investors speculate on the potential -
economics of a joint venture with a Big Oil company? -

BQI LT will be the largest oil tar sand res. -

http://investorshub.advfn.com/boards/board.asp?board_id=6668




http://investorshub.advfn.com/boards/board.asp?board_id=5409

Ps.
I’m think many of today’s current shorters666 are
cognizant of BQI’s potential upside and are not well aware
of the timing of the September-October update -
(banksterz666 who gained trust from rich widows etc.
try to follow the 911banksterz destructionz habitz?) -
the 666shorterz use 888fiatz who got fooled to trust
the 666? -
and it will make the potential repercussions of a very
bullish BQI Potential Short Squeeze -
when more beaware -
of BQI large oil res. with new updates -
the oil investors will get the info! -

That, coupled with the fact that -
the current 666 short position is large -
( 12.4mm shares and 8% of the float)
and likely predicated on huge 666 loss? -

The great fundamental issues with Oilsands Quest -
should prompt much more 666short squeezes over the next -
couple months (in any fair market with less 666) -
before the September-October update.

And that is my take of the anatomy of a BQI -
short squeeze -
(it would be huge in any fair market) -
Imo. Tia.
http://www.888c.com/
God Bless

http://investorshub.advfn.com/boards/board.asp?board_id=6668

Oilsands work just getting started
Companies have global-level growth plans for Alberta's rich-making resource

Gordon Jaremko
The Edmonton Journal

Monday, August 06, 2007

Edmonton / A year after former Shell Canada president Clive Mather gave out a hint, the scale of development on Alberta's horizon is coming into sharper focus.

"What we're saying is this is only the beginning," Mather said as he escorted U.S. Energy Secretary Samuel Bodman on an oilsands tour north of Fort McMurray.

"There's an awful lot more to come," Mather said. Syncrude Canada chief executive Charles Ruigrok echoed his Shell peer, saying the province's 141,000-square-kilometre bitumen belt is catching and holding the attention of global industry and finance.

Bodman asked the question also on Albertans' minds when he finished his state tour at a gala lunch with business and government leaders in Calgary. How big will the oilsands industry grow?

In January and last week, the Athabasca Oil Sands Project gave some answers in applications for regulatory approvals of its growth plans.

The Athabasca group alone -- led by 60-per-cent owner Shell and backed by Chevron Canada and Western Oil Sands with 20 per cent each -- has set its sights on achieving production of 770,000 barrels per day from its 1,200 square kilometres of Fort McMurray bitumen leases by about 2020.

It took the entire industry 67 years and 56,772 wells to build up Alberta output of conventional liquid oil into the 800,000-barrels-a-day range, from the first discovery at Waterton in 1902 until 1969, show records of the Canadian Association of Petroleum Producers.

The oilsands are "world class," Texas giant Marathon Oil Corp. added in announcing its $6.5-billion takeover of Western.

Shell emphasized that all its majority share of the Athabasca reserves will be processed in Alberta, yielding maximum value to the firm's Canadian operations and the provincial economy.

Marathon, a 120-year-old American industry mainstay with few Canadian assets, will eventually export most of its minority of the Athabasca bitumen to its seven U.S. refineries and 5,700 service stations.

Chevron has yet to make known plans for all its share of Athabasca reserves, or for an estimated 7.5 billion barrels of bitumen in 730 square kilometres of leases known as Ells River that the firm bought west of Fort McMurray 16 months ago. But the Shell program alone spells more than a decade of heavy industrial work in the Fort Saskatchewan area east of Edmonton. Forecast expenditures of $22 billion to $27 billion include nearly $8 billion in wages for local workers.

The Scotford mega-upgrader will be built as four 100,000-barrels-a-day plants. It will be a continuous construction project lasting about 13 years provided oil markets, government policies and economic conditions stay favourable.

Shell wrote an invitation to industrial housing builders into its construction applications to the Alberta Energy and Utilities Board and Alberta Environment.

The region could use the sprawling, hotel-like worker complexes known as "open camps" that have sprouted in the Fort McMurray region, the documents predict.

It would be a good idea "if one or more third parties were to construct and operate open accommodation camps in the region," the applications suggest.

"Shell would consider working with camp providers to house out-of-region workers and transport workers by bus between the camp and the project," the applications promise.

Building each of the four upgrader plants will require 3,000 to 4,000 trades personnel at construction activity peaks.

But the mega-upgrader is just the biggest of many large projects in the 310-square-kilometre Alberta Industrial Heartland district northeast of Edmonton.

Counting all currently known developments "the cumulative construction workforce is expected to remain high, at more than 8,000 workers, from mid-2008 to early 2013, with a peak of about 13,300 workers in late 2011," Shell forecasts.

"Based on an estimated 7,500 local trades people available, additional workers from outside the region or province will be needed."

In highly skilled occupations needed by industrial projects, Edmonton oilsands jobs will be more like careers than the traditional feast-or-famine pattern of construction contracting.

Shell vowed "to use the project's lengthy construction schedule to offer the opportunity of long-term, stable employment as a means of attracting and retaining industrial workers and potentially attracting out-of-region workers."

When finished, the chain of four upgrader plants is expected to create 1,438 permanent jobs including 1,138 full-time staff and 300 contractor positions.

Since the Edmonton area already has a population of more than a million, Shell predicts it will absorb the upgrader people without repeating the notorious boomtown trauma of Fort McMurray.

Environmental effects on local air, water, vegetation and wildlife are also forecast to be modest compared to total accumulated results of decades of Edmonton development.

But road planners and motorists will have to adjust.

"The long construction period will result in the local road network having to support not only construction-related traffic, but also overlapping increasing volumes of operations-related traffic," the upgrader construction applications say.

Shell is volunteering to work with regional authorities on road improvements recommended by a recent Strathcona County engineering study.

gjaremko@thejournal.canwest.com
© The Edmonton Journal 2007

ya looks like somethings driving it

$33

This is pretty well the lone bright spot today

PBG ath again - yawn

PBG ath

Canadian Natural reviews second quarter progress

2007-08-01 03:15 ET - News Release

Mr. Allan Markin reports

RE-RELEASE: CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES SECOND QUARTER 2007 UPDATE ON THE PROGRESS OF THE HORIZON OIL SANDS PROJECT

Canadian Natural Resources Ltd. has provided a regular quarterly overview on the Horizon oil sands project.

"Canadian Natural achieved a major milestone on our Horizon project during the second quarter of 2007, with overall work progress at the end of the quarter reaching 75 per cent complete and field construction approaching two-thirds complete. All major vessels have either been erected or are currently on site. Work scheduled for the coming months will focus on mechanical construction, which is scheduled to be completed through a combination of lump-sum and reimbursable contracts. We continue to effectively execute our well-defined strategies," commented Real Doucet, senior vice-president, oil sands.

"The project remains on track for targeted start-up in the third quarter of 2008. Project progress slowed slightly during the quarter due in part to labour productivity, the temporary work shutdown on the tank farm and delays associated with a realignment of certain contract packages to match scope to the marketplace contractor supply to better manage costs.

"Despite the challenges of a construction market in Alberta operating at high capacity, we have been able to build our on-site manpower to over 7,000 personnel. With the success of our fly-in/fly-out program and managed open-site policy, we have been able to add workers as required.

"Management of costs continues to be a focus for the project team and we currently remain within our forecast estimate of 5 per cent to 12 per cent above our original $6.8-billion board authorization for construction capital spending.

"We are also well into our planning for commissioning and start-up. Our commissioning plans are established to identify the priority systems that will be required later this year and early in 2008. We are currently hiring and training operating personnel, setting up procedures and systems, and continue to develop our start-up strategies to ensure we stay on track for first oil."

HORIZON PROJECT STATUS SUMMARY

Mar 31, 2007 June 30, 2007 Sept 30, 2007
Actual Actual Plan Plan
Phase 1 -- work progress
(cumulative) 66% 75% 77% 88%
Phase 1 -- construction
capital spending(1)
(cumulative) 69% 79% 77% 85%

(1) Relative to overall phase 1 project construction capital
of $6.8-billion

Accomplished during the second quarter of 2007

Detailed engineering:

* Overall detailed engineering 97 per cent complete and substantially completed in most areas.

Procurement:

* Overall procurement progress is 95 per cent complete;
* Have awarded over $5.4-billion in purchase orders and contracts to date;
* Delivered to site over 30,000 standard loads;
* Operations and maintenance service and supply agreements are in negotiation.

Modularization:

* Delivered an additional 172 oversized loads to site during the quarter for a total of 1,424 loads, which represents approximately 86 per cent of the total requirement.

Construction:

* Overall construction progress is 63 per cent complete;
* Mine overburden removal has moved over 37 million bank cubic metres, which represents approximately 54 per cent of the total to be moved and is 1 per cent ahead of schedule;
* Construction of cofferdam for the tar river diversion completed in mining;
* Fabrication of crushing plants, surge facility and conveyor structure is 100 per cent complete in the ore preparation plant;
* Started erection of conveyors in ore preparation;
* Completed hot water tank in extraction;
* Hydrotested primary separation cells and hot water tank;
* Completed construction and hydrotesting of inclined plate settlers in froth treatment;
* Flare stacks installed in upgrading;
* Mechanically completed cooling tower piping;
* Mechanically completed inhibited water and cooling water pump-house buildings;
* 42-inch water pipeline completed;
* Wet gas compressor received and installed;
* Completed installation of coker and diluent recovery-unit process structures;
* Completed interconnecting welding of primary upgrading's piperacks;
* Energize main electrical substations R1/R2.

Milestones for the third quarter of 2007:

* Complete construction of Raw Water Pond;
* Extraction plant hydrotesting;
* Start of precommissioning activities in all bitumen production areas;
* Permanent power energized in R1/R2 corridors pump houses.
* Electrically energize main electrical substation;
* Start commissioning of Recycle Water Pond.

The company's results for the second quarter of 2007 will be released on Aug. 2, 2007. A conference call will be held on that day at 9 a.m. MT, 11 a.m. ET.

We seek Safe Harbor.

Nice timing.
$78 oil
WTO buyout offer
Should be a good one in August

Alberta Oilsands expands drilling program

2007-08-01 00:40 MT - News Release

Mr. Shabir Premji reports

OPERATIONS UPDATE: ALBERTA OILSANDS INC. EXPANDS DRILLING PROGRAM AND INCREASES OIL SANDS LANDS TO 85 SECTIONS (54,400 ACRES)

Alberta Oilsands Inc. has added an additional drilling program to commence in late fourth quarter 2007. The company is now planning two drilling programs of up to 40 wells over two large oil sands land blocks.

AOS has acquired an additional 62 sections of oil sands leases since it announced the initial acquisition of 23-section oil sands land on March 26, 2007. The additional oil sands leases increases AOS's land base to a total of 85 sections (54,400 acres), all at 100-per-cent working interest. All of the sections are located in the regional Hangingstone area. The sections were acquired over the past four months at Crown land sales.

The first drilling program will be on the 23-section "AOS Hangingstone prospect" parcel with up to 30 wells, at a minimum drill density of one well per section. Ryder Scott Petroleum Consultants, an independent petroleum consulting firm, has confirmed undiscovered resource of 1.15 billion barrels of bitumen in place (May 17, 2007, news in Stockwatch). This block is located approximately 22 kilometres southwest of Fort McMurray. The parcel is within three kilometres of the highway which provides good access to the lands. This land block is surrounded by a number of SAGD (steam-assisted gravity drainage) projects, which are in various stages of development, all within a three-to-10-kilometre radius. These SAGD projects include: Petro-Canada's Hangingstone Meadow Creek projects, Japan Canada Oilsands Company Ltd. (JACOS) Hangingstone project and Value Creation Inc.'s (VCI) Halfway Creek project. In addition to the drilling program, an 80-kilometre 2-D seismic data acquisition program is being permitted.

The second drilling program will begin to delineate the other prospect covering 47 sections. A 2-D seismic acquisition program is being planned by the company for this area. The company has secured services to ensure that delineation activities will start in the fourth quarter of 2007. AOS has engaged Ryder Scott Petroleum Consultants to evaluate the possible bitumen resources attributable to the recently acquired sections. The results will be announced as they become available.

UPDATE 1-Marathon to buy Western Oil Sands for $5.56 bln

(Recasts with acquisition, adds details)

NEW YORK, July 31 (Reuters) - Marathon Oil Corp <MRO.N>
said on Tuesday it agreed to buy Canada's Western Oil Sands
Inc.<WTO.TO> for about $5.56 billion, giving the U.S. oil
company a foothold in one of the world's most promising streams
of new crude oil.

Marathon said it will pay about $3.6 billion in cash plus
34.3 million shares or securities exchangeable for shares. It
will also assume about $650 million of debt.

The company also said its second-quarter profit fell on a
decline in oil and gas output and the absence of a year-ago
gain from the sale of Russian operations.

Houston-based Marathon has long been looking for a partner
in the Canadian oil sands. Still, it is expensive and requires
special equipment to turn the tar-like sludge that comes from
the region -- called bitumen -- into usable fuel.

The company plans to link the Canadian fields with its
refining operations in the United States.

The deal also requires Western to spin-off its subsidiary
with interests in Kurdistan -- WesternZagros -- before the deal
closes, Marathon said.

Marathon said it would get access to proved mining reserves
of 436 million barrels of bitumen through the deal and a total
net resource of 2.6 billion barrels of bitumen that can be
recovered through mining or "in situ" processing, which uses
heat or solvents to remove the bitumen.

Marathon's net income slipped to $1.55 billion, or $2.25 a
share, from $1.75 billion, or $2.08 a share, last year.

Excluding one-time items, the company said it earned $2.25
a share. On that basis, the average forecast of Wall Street
analysts was $2.13 a share, according to Reuters Estimates.

The second quarter was a mixed bag for the integrated oil
sector as soaring refining margins were offset by lower
commodity prices and output at some large oil companies.

(Reporting by Michael Erman)

Shell upgrader doesn't come cheap
Company says building costs will be spread over two decades

The Edmonton Journal

Tuesday, July 31, 2007

EDMONTON - Shell Canada predicted Monday its bitumen mega-upgrader project east of Edmonton will eventually cost $22 billion to $27 billion, but said the spending will be spread over 15 to 20 years.

Construction applications to the Alberta Energy and Utilities Board and Alberta Environment call for the 400,000-barrels-daily complex to be built as four plants beside Shell's current Scotford upgrader near Fort Saskatchewan.

The cost prediction is "an early assessment" required for regulatory review of the previously announced project's likely economic effects, said Shell oilsands communications manager Janet Annesley.

Estimates that will guide construction decisions on each 100,000-barrels-daily stage in the development will come later, Annesley said.

Building each plant will require 3,000 to 4,000 trades personnel at construction activity peaks. Each plant will employ about 300 permanent operating staff.

Shell's plan calls for regulatory approval of the entire mega-upgrader complex and possibly a start on building the first plant in 2009, with production beginning in 2012. "The timeline for the remaining three phases will depend on various regulatory, project and market factors," the construction application says.

Advance approval for all four plants will "enable the pace of project development to be well planned and executed. This will help to reduce and level impacts of intense construction of these large facilities in the Scotford area," the application says.

More applications will be made by the end of this year for matching additions to Shell's Athabasca oilsands mine north of Fort McMurray, Annesley said.
© The Edmonton Journal 2007

Canada to face oil pipeline shortage: regulator

Fri Jul 27, 5:32 PM

CALGARY, Alberta (Reuters) - Canada's crude-oil pipelines may have to ration space as early as this autumn because of a surge of new oil production from the Alberta oil sands, the country's energy regulator said on Friday.

The National Energy Board said the pipeline industry may face a capacity crunch as oil output this year rises to 2.9 million barrels a day, 9 percent more than in 2006.

Almost all new Canadian oil supply comes from the oil sands region of northern Alberta, where more than C$100 billion worth of projects to exploit reserves second only to Saudi Arabia are planned or under way.

Most of the that production is destined for the huge U.S. market and a number of new pipelines are on the drawing boards to handle the expected flood of oil.

However none of those new lines, which include projects planned by Enbridge Inc. and TransCanada Corp. , is expected be completed before 2009.

Without that new capacity, pipeline firms may have to periodically resort to apportionment -- rationing available space -- as soon as the fourth quarter, with restrictions remaining in place for 18 months until new lines are built, the regulator said.

The NEB's assessment contrasts with a study released by the Canadian Association of Petroleum Producers last month.

CAPP, the oil industry's main lobby group, said it believes there is enough oil transport capacity in place or being built to handle rising output through 2012.

But CAPP said developers must now concentrate on a new round of expansion beyond that period, given how long regulatory and construction phases take.

It predicted Canadian crude oil output could hit 5.3 million barrels a day by 2020, double the current amount.

In the 1990s, pipeline apportionment was a big issue as capacity lagged demand for crude movement on Enbridge's major artery to the U.S. Midwest.

Shippers over-nominated for space in efforts to reserve as much capacity as possible, creating what the industry termed as "air barrels."

Since then, Enbridge and other operators have added capacity as production, especially from the Alberta oil sands, has climbed. Numerous expansions to U.S. and West Coast markets are on the drawing board or under way.

Ditto PBG

COS.UN channel trade

Monday » July 23 » 2007

Potential greenhouse breakthrough is years away from being adopted
By burning bitumen as fuel and capturing the carbon dioxide, natural gas is conserved and total emissions are lower

Gordon Jaremko
The Edmonton Journal

Monday, July 23, 2007

On paper, Quadrise Fuel Systems, Paramount Resources and Colt Engineering own a technology that will cure big oilsands woes.

The approach promises to cut costs and conserve energy by replacing natural gas with a new fuel for thermal processes of "in-situ" underground bitumen extraction.

Greenhouse gas emissions would be cut because the method would harness carbon dioxide made by burning the new fuel as an industry production tool.

The exhaust would be injected into geological reservoirs, where it would stay permanently after enhancing natural gas and bitumen production.

As a bonus, the carbon-dioxide injections would restore access to natural gas in the bitumen belt. The method promises to help firms including Paramount which had to shut in wells and abandon reserves after the Alberta Energy and Utilities Board found gas production threatened to stunt oilsands development by lowering underground pressures.

As a second bonus, users of the new approach stand to gain emissions-reduction credits for sale on the carbon-trading market that climate-change policy is supposed to create eventually.

Enter MCAST, short for MSAR carbon sequestration technology. MSAR stands for multiphase superfine atomized residue. MSAR is a patented new fuel made from raw bitumen or low-grade heavy oil that resembles paint and burns with exceptional efficiency when sprayed as a fine mist and ignited in industrial boilers.

The Canadian invention is being introduced to big energy users from power plants to refineries by an international marketing network.

The bitumen production method devised by Quadrise, Paramount and Colt adds carbon capture and storage technology, a specialty pioneered by the Alberta Research Council, to the MSAR fuel system.

"We'd love to have seen it being used commercially yesterday," Quadrise business development vice-president Rodger Bernar said in an interview. But in practice the system will likely take until about 2012 to mature into a candidate for adoption by oilsands operations, he predicted.

Industry has to be convinced new methods work reliably over a prolonged period, Bernar said. That takes field tests big enough to demonstrate economic as well as technical advantages, he added.

Quadrise, Paramount and Colt expect to spend the rest of this year organizing an MCAST field test in the Surmont oilsands district south of Fort McMurray.

Then it will take another year to 18 months to build a pilot plant and put it into proper running order. And then two to three years of operating the system in all conditions will be needed to convince industry engineers that the new approach works.

No firm schedules are set yet for either the field trials or adoption of the system on a commercial production scale. The federal and provincial governments are unpredictable factors in the technology development process.

MCAST looks tailor-made to qualify for help from federal funds earmarked for greenhouse gas reduction projects, and for help from a similar program promised by the Alberta government.

The oilsands technology trio has applied to Natural Resources Canada for about $1 million and intends to seek similar help from Alberta when the province clarifies its intentions, Bernar said.

The companies are only asking the governments to cover about one-tenth to one-fifth of the project's total costs.

But the authorities refuse to be rushed.

Just to qualify as a candidate for help from Ottawa's greenhouse gas reduction program, the plan by Quadrise, Paramount and Colt has to clear an environmental counterpart to a tax audit.

The proposed pilot plant is going through a review by the Canadian Environmental Assessment Agency. Formal "screening" of the industrial research plan started July 9 as a thorough check into potential effects on land, air water and wildlife.

Government policy will also play a critical role in determining the fate of the new technology if the field trials are successful, Bernar indicated.

MSAR has already been proven to work in prolonged tests. The new fuel system performed well in a pilot plant for the Joslyn oilsands mega-project north of Fort McMurray.

But the Joslyn trials vented carbon-dioxide exhaust into the atmosphere. Even if the larger MCAST bitumen and natural gas production system turns out to be a technical breakthrough, governments will have to contribute an economic reason for industry to make it a business winner, Bernar said.

Carbon-dioxide capture and storage is expensive. Forecast costs of a collection, pipeline and underground disposal system currently proposed by a consortium of other Alberta industry branches run into billions of dollars. Government help sought by the group is also measured in billions of dollars.

Climate-change policy will only generate significant industrial action by creating seriously expensive penalties for carbon emissions and genuine rewards for reducing them, Bernar predicted.

Projects on the scale of oilsands plants do not lightly switch production methods. "There have to be sufficient economic drivers for someone to proceed," the technology pioneer said.

gjaremko@thejournal.canwest.com

Conoco Has Big Plans for Alberta Oilsands, CEO Says

http://www.resourceinvestor.com/pebble.asp?relid=34055