- All Syncrude leases will be treated as a single project. This means that whenever expansion or construction on the site is taking place, Syncrude can revert to pre-payout terms. This is a huge score for Syncrude since the royalty/taxation arrangement for tar sands oil is based on revenue and expenditures for each project, and the claim of the owners of equity on realized added-value. Costs of production, especially fixed construction costs, can be amortized at a rate that keeps the royalty/tax on equity profit at 1 percent until "payout." Even this pittance of one percent is only payable once the declared equity profit in the particular project compared with the total investment, which is its rate of equity profit, exceeds the current long-term Canada bond rate. - Other terms agreed to include an agreement on a bitumen valuation methodology, that Alberta will not elect to take royalties in kind before 2012 and only if the same terms apply to the rest of the industry. Upgrading of royalty in kind barrels through 2015 will only be on terms commercially acceptable to the Syncrude owners, and Syncrude retains the ability to substitute bitumen from alternative sources. Canadian Oil Sands Ltd. has estimated that the agreement means that the added value retained by the monopoly increases by about 12 percent while the added value going to government decreases by the same amount. This is what the monopoly media has described as Syncrude agreeing to pay more! In 2007, the Stelmach government conducted a royalty review, accompanied by all kinds of hype that the owners of the resource, the people of Alberta should receive a "fair" value for the resources. At that time, TML pointed out: "The anti-social concept of turning public control of natural resources over to private interests uses royalty payments as a neo-liberal buffer to deflect public outrage and opposition to the sell-out of a public natural resource. Royalties per barrel of oil or stumpage fees per trees cut create an illusion that the public is gaining something from their natural resource and that private interests are paying a form of economic rent. This plays on the Canadian liberal conscience of fairness to sell-out the people's natural resources, which are often located on unceded Aboriginal First Nations' land. Without challenging and rendering accounts with our liberal conscience, Canadians are reduced to arguing about the amount of the royalty but not the basic principle that natural resources belong in their entirety to the people and must serve the public good. It is a matter of affirming public right not bargaining right away in the name of fairness and the reasonable accommodation of contending interests. "The human-centred concept of natural resources has never held importance in official Canada. Such a concept upholds as principle that natural resources are public and must remain public under all circumstances and that all benefits from transforming natural resources into usable products must flow to the public. Under such a principle, private interests could only be involved as paid contractors for actual work performed or as investors at a set return. Private interests should never control the social product itself such as oil, timber, natural gas, nickel, gold, uranium etc. much less their wholesale distribution and price. Natural resources are part of the foundation of modern life and society, the other being the human factor. The human factor has mostly been freed from direct private ownership but the other pillar of life and society, our natural resources, languishes under private monopoly right and ownership. The human factor cannot blossom, move society forward and fully humanize the social and natural environments unless it becomes one seamless whole with the natural resources of Mother Earth free from the narrow interests of private monopoly right and ownership." Alberta's Carbon Capture and Storage PlansOn July 8, 2008, the Alberta Government announced a $2 billion kick-start to reduce carbon dioxide emissions through new Carbon Capture and Storage (CCS) projects. CCS is a process that captures and stores carbon dioxide emissions before they are emitted into the air, for example, by a coal-fired power plant or a refinery. The carbon dioxide is separated from other emissions, dehydrated, compressed, and transported by pipeline or other means. It is then either injected into geological formations to help increase production from oil and gas reservoirs or coal beds, or else injected one to two kilometers deep into porous rock formations where it is sealed and monitored. Alberta's energy industry has been injecting carbon dioxide into depleted oil fields to enhance oil recovery (EOR) for more than 20 years. Previously, on April 24, 2008, the Alberta Government had announced the formation of the new Alberta Carbon Capture and Storage Development Council, to develop Alberta's plan to move ahead with carbon capture and storage projects. Council members were selected from the fossil fuel energy industry (9), academia (one economist and one engineer/economist), and the provincial and federal governments (5). The chairperson is Jim Carter, former president of oilsands giant Syncrude. Other energy industry representatives are from Epcor, Nexen, Suncor, PennWest Energy, Shell, Petro-Canada, Enbridge, and Encana. Only one of the academics has research experience in CCS. Many governments and corporations around the world are now touting CCS, an idea first introduced on the 1970s, as the best strategy to lower levels of carbon dioxide emissions. A few major projects have been developed, generally with very large-scale government funding, such as Norway's Sleipner Oilfield Project initiated in 1996. Most major energy corporations are proceeding cautiously or have already mothballed their projects on "economic grounds," stating that developing and testing CCS technology requires "significant" government financial support such as direct grants, interest-free loans and tax concessions. Further, many corporations refuse to proceed with CCS without protection from liability for any negative effects from permanently stored carbon dioxide. Carbon capture and storage is being presented as the major way to reduce carbon emissions in Alberta. In its Interim Report, the Council stated that some 70 percent of Alberta's potential reductions are expected to arise from CCS. For decades, the energy monopolies have made huge profits through their plunder of Alberta's resources while at the same time releasing huge quantities of carbon dioxide into the air, an identified cause of global warming. Now the rich will be paid once again to implement carbon capture and storage technology. This is not surprising since the province-appointed decision-making body on CCS is controlled by the energy monopolies. The people of Alberta have not been consulted, yet the Alberta government has already decided to hand over $2 billion to the monopolies. As the government of Alberta often states, the resources belong to the people. This means that the people must decide. There is a need for widespread public discussion on CCS to evaluate its worth. Scientific research into CCS is still at an early stage and there is a lack of reliable testing on a large scale, particularly the viability of permanent storage. Important issues need to be investigated such as potential leakage of stored carbon dioxide, effects of carbon dioxide rising to the shallow subsurface, danger of asphyxiation through rapid release, and potential contamination of drinking water through leaching of toxic chemicals from rocks into water. Only if the people have their say can we develop a direction for the energy industry that is based on serving the needs of the people, including their need for a healthy natural environment. For Your Information Upgrader Alley Projects Toppling like Dominoes: Oil Tanks Rust as Sites Sit Idle, Construction Plans HaltedThe fate of the abandoned Heritage oilsands processing site has become a metaphor for the fortunes of Edmonton's Upgrader Alley. Alberta's industrial heartland, a swath of refineries and petrochemical plants scattered among thousands of hectares of farmland north of Fort Saskatchewan, was set to become the largest oil processing and refining centre outside the Gulf Coast. This would be the place where energy companies would add value to Alberta's massive raw bitumen resource. But at BA Energy's construction site, giant vessels now lay strewn about a windswept field like toppled dominoes, half-buried in snow. Costing more than half-a-billion dollars to build, the specially designed technological marvels were transported from far-off places such as South Korea and left here to rust. All activity at the once-bustling site has stopped, except for a lone security guard making the rounds. Apart from the shrill call of a raven, the single deafening sound is the wind blowing through thickets of trees. The only completed portion of the project, a 10-storey process stack, towers over everything around. Neil Shelly, executive director of the Alberta's Industrial Heartland Association, calls it the Alberta economic bungee jump: take a big leap of faith and hope your lifeline snaps back at the last possible second before it all comes crashing to the ground. "We're the canary in the coal mine," he says. "Starting about the spring of 2008, work started to slow down around here. The site was pretty much a victim of the cost escalation that was happening in Alberta." Just two years ago, hopes were high for $100-billion worth of new facilities to upgrade Alberta's growing oilsands production, part of what the provincial government touted as an "integrated," value-added strategy. Shelly calls the period between 2005-06 "the Gold Rush days." In the heady days of $140 oil, everything seemed possible -- carbon capture, gasification, transferring the waste products from facilities to use as feedstock -- in what was to be one of the most modern oil refining "clusters" in the world. The $4-billion Heritage plant was supposed to be the hub of that new vision, a marvel of technology and innovation ushering in a brave new value-added world. "Some reality happened in 2008," Shelly says. The financial crisis preceded a recession few observers saw coming or could have imagined 18 months ago. In December, BA filed for bankruptcy protection and, earlier this week, reached a deal with its lenders that gives the company until April 29 to restructure. Value Creation, BA's parent company, didn't return requests for comment, but Shelly says "the writing was on the wall" more than a year ago. Even before oil prices fell from record highs, skyrocketing costs set off a domino effect, forcing companies such as Petro-Canada to mothball projects such as the proposed Sturgeon County upgrader. Others followed. Norway's StatoilHydro scrapped plans for an upgrader and French stalwart Total pushed the startup of its proposed upgrader back as much as two years. In August, Total bought troubled Synenco, which was proposing an upgrader as part of its Northern Light oilsands mine -- now on permanent hold. Of eight proposed projects, only one remains on the books: Shell Canada's current Scotford expansion, which was too far in the construction phase to be halted. But Shell too, has placed future expansion phases on hold until markets improve. North West Upgrading is also in limbo while it awaits financing to build an upgrader of its own. A victim of the financial crunch, North West found it difficult to raise capital for its merchant upgrading facility after credit markets froze. Unlike integrated upgraders, which are tied to a specific project or mine, North West's plant would take the bitumen from third parties and process it into higher value products, including diesel fuel. Rob Pearce, North West's senior vice-president and chief financial officer, said the company is ready to start digging as soon as it gets the cash. It is also hoping to gain commercial agreements that will, in turn, allow the company to raise the money needed to begin work. Pearce confirmed North West answered a government request for expressions of interest to process the province's share of bitumen it will take in lieu of petroleum producers paying royalties. A formal request for proposals is expected to be issued later this spring. "I think we can add a lot of value to the government's barrels," he says. Assuming oil prices improve within the next 12 months, most of the plans could be reinstated by 2012, amounting to a four-year delay, he reckons. That's the best case scenario. In the worst case, upgrading in the province never really recovers and a far greater proportion of Alberta's oilsands production is exported as raw bitumen to the United States. Dave Collyer, who heads the Canadian Association of Petroleum Producers, agrees homegrown upgrading may be the first casualty of the downturn. Currently, three-quarters of Alberta's bitumen is upgraded in the province. Although the absolute amount will increase as production rises, the overall percentage of upgraded production is expected to fall as processing plants are shelved. Some estimates have suggested as much as 60 per cent of Alberta's future supplies could be sent to refineries in the U. S., taking jobs and revenue along with it. In the run-up to gaining the Progressive Conservative leadership, Premier Ed Stelmach likened the notion of pumping raw bitumen down the pipeline to stripping the topsoil from a farm and trucking it away. Nonetheless, Collyer says the economics of upgrading at home have always been "difficult." "I would probably say more (raw bitumen) is likely to be exported in the future," he concurs. But the CAPP boss is unapologetic, given Alberta's higher cost structure, its distance from major consuming markets and looming environmental constraints. In most cases, it's cheaper to re-configure existing facilities in the U. S. than to build "green field" projects here at home. "That's a challenge Alberta has always faced," he continues. "The market should generally decide where these upgraders should be built." Already, the cancellations have had a ripple effect that has put a big dent in the province's value-added vision. Immediately across the road from the abandoned BA site, an Enbridge-built tank farm meant to supply bitumen to the boilers sits idle. Half a kilometre away, a specially designed plant built by Aux Sable to capture flue gas from the Heritage stack -- and strip it of potentially valuable products like carbon dioxide and ethane -- also sits idle. In May 2007, Canadian Pacific took steps to build a special rail yard to move construction materials into Upgrader Alley in anticipation of a construction boom that never materialized. It too sits empty. The magnitude of the turnaround isn't lost on government officials. In December, the province outlined an energy strategy that relies heavily on the synergies created by clusters of refineries and upgraders. As part of the royalty changes announced last year, the province has committed to taking its share of bitumen royalties in kind, which could amount to more than one million barrels a day in the next decade -- enough to feed a dozen 100,000-barrel-a-day upgraders and refineries. The government has indicated a desire to upgrade its share in Alberta and will issue a request for proposals later this year, says Alberta Energy spokesman Jason Chance. While acknowledging the setback posed by the delays, Chance says the province still believes in the integrated value strategy. "We're moving forward on a policy basis, but it's dependent on factors outside our control, related to credit markets and commodity prices. "We're very much affected by the downturn," he adds. "But we remain committed to it (the value-added strategy) and confident the activity will return." Hanging in the balance is the fate of some two-dozen communities surrounding the capital region. Redwater Mayor Mel Smith said his town has created two new subdivisions, with plans for two more, in anticipation of a population boom. Planners expected the town of 2,300 to swell to more than 3,000 residents, the first new growth since oil was discovered after the Second World War. Smith acknowledges many people are comparing the current situation to the bust of the 1980s. He worked in the oilpatch during those years and owned an oilfield-service company prior to becoming mayor. He understands the comparisons, but thinks it's different this time. "There are a lot of folks saying, 'We've seen this before,' just like it was in '82," Smith says, adding he remains hopeful, but cautious. "I don't want to call it naive, but I'm optimistic." Likewise, the Heartland Association's Shelly has little doubt the region will bounce back when oil prices improve. In his mind, it's a question of "when," not "if." "The fundamentals are there. If you think oil is going to be under $100 a barrel in five years time, you are fooling yourself," he says. "The world will come back to Alberta." Industrial Heartland: Project statusBA Energy (Value Creation) Fort Hills (Petro-Canada) North West Upgrading Shell Canada, Phase 1 expansion Shell Canada, Phase 2 to 4 expansion Statoil Hydro Total E&P (Source:
Alberta's
Industrial Heartland Association, January 6, 2009)
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