So why BRIK for the oil sands? The decision to collect in kind was made in October 2007 as a way for the government to use its share of bitumen strategically in order to supply potential upgraders and refiners in Alberta and to then optimize its royalty share by marketing those volumes. It is estimated that by refining BRIK, Alberta will increase the value of the bitumen by $200 to $700 million depending on marker prices. Additionally, by refining the bitumen in Alberta, there will be an estimated 10,000 jobs created, roughly $100 million in provincial and property taxes, additional enhanced oil recovery royalties (from CSS injection) and reduced CO2 emissions to the atmosphere (also through CSS projects).
The article below from The Edmonton Journal explains in greater detail some of the fiscal benefits that come with implementing the BRIK initiative.
BRIK will be a job builder, Alberta government says
Energy minister rejects criticism of royalty-in-kind program
This 3-D drawing depicts the new North West Upgrading plant, announced under the Alberta government’s BRIK program in February 2011.
Photograph by: Supplied, edmontonjournal.com
EDMONTON — Alberta’s signing of its first long-term bitumen refining contract in February could pave the way for more deals, as the province begins to collect its royalties in the actual tarry output from oilsands projects instead of cash.
At least that was Energy Minister Ron Liepert’s view, when he said “I’m optimistic as we move forward it will bring other opportunities down the road” to ensure at least 60 per cent of the oilsands output creates jobs and value-added products in Alberta.
While there has been criticism that the province is dabbling in the free market through its bitumen royalty in kind (BRIK) program, Liepert defended the move and challenged the perception of market intervention.
“This is the Crown’s share. All we are doing is entering into an agreement to have it refined locally rather than somewhere else,” Liepert said.
Ian MacGregor, chairman of North West Upgrading, said every major oil company upgrades and refines its bitumen production, either in Alberta or the U.S.
“There is only one producer who is not, and by 2025 the largest one will be the province (through its royalties). Alberta is making the same decision that every other producer is making,” he said.
“It is a good idea to get more money for your products.”
MacGregor recently confirmed the North West staff roster is growing quickly as the fledgling Calgary-based company hires dozens of staff, but “we still have a ton of engineering to finish.”
Although he had initially hoped that some field work could begin later this summer or fall, he now says that is unlikely.
“But we will be ready to go full speed in the spring, and get the underground utilities and other work completed next year.”
The large Korean-built reactor vessels, now in storage in Minnesota, must travel on frozen railbeds to the upgrader construction site.
“So that will be during the winter of 2012-2013. Those are key pieces for the upgrader,” he said.
Neil Shelly, executive director of Alberta’s Industrial Heartland, a group of local municipalities, says the BRIK program will allow the province to hedge its bets on its bitumen investment.
“If North West were open right now, the government would be banking some very good returns.”
More than half the $5 billion upgrader’s output will be diesel.
“If you look at what the price of bitumen is — about $55 to $60 a barrel — versus the price of diesel fuel of perhaps 90 cents a litre, well that works out to $154 to $160 a barrel for diesel. So the government is making an extra $100 a barrel selling into the market,” said Shelly.
Of course, the project is a huge shot in the arm for the region, with 3,000 jobs during each of the three-year construction cycles for each of the three proposed phases.
“That’s nine years of work, and we could get more companies coming in as well. But BRIK is not popular in some political circles, so if the political landscape changes anything could happen.”
Under BRIK, the province said it would make available 75,000 barrels per day of bitumen, with 37,500 bpd going to Phase 1 of the North West plant, and the balance going to Phase 2 if the first proves to be economic. Partner Canadian Natural Resources Ltd. will add 12,500 bpd to each phase.
When the diluent is added, the actual inflow will be 77,000 barrels of diluted bitumen. From this, the plant will produce 36,000 bpd of ultra-low-sulphur diesel (about 5.7 million litres per day), 18,000 bpd of naphtha and return 14,000 bpd of diluent.
The province could have a total of 400,000 bpd of BRIK bitumen available by 2030 as oilsands plants pay off construction costs and start to contribute the standard 25-per-cent royalty.
Analysts have said $5 billion for a plant to handle 50,000 bpd of bitumen works out to a rather expensive $100,000 per flowing barrel compared with standard upgraders.
But the North West project is unique, using a much cleaner gasifier process rather than traditional coking. This allows for the collection of carbon dioxide gas, giving its main product the lowest carbon footprint of any diesel fuel.
Under the 30-year deal between the province and North West/CNRL, the equity partners will be able to recoup their investment, pay operating costs and achieve a return on capital through tolls similar to those paid by pipeline users. Alberta expects to earn an extra $200 million to $700 million over the three decades by selling diesel rather than raw bitumen.
As the 75-per-cent supplier of bitumen, the province will pay three-quarters of the operating costs and receive three-quarters of the benefits, officials have said.
While Alberta has been criticized for its growing carbon dioxide emissions, the North West project will be the only one in the world to combine gasification technology with CO2 management, capturing 1.2 million tonnes of CO2 per phase, which will be sold to Enhance Energy Inc.’s Alberta Carbon Trunk Line for use in enhanced oil recovery in central Alberta.
Enhance will start with CO2 from the Agrium fertilizer plant adjacent to North West near Redwater, and add the upgrader’s gas by mid to late 2014. Enhance hopes other suppliers will eventually tap in.
North West’s contribution of CO2 was enough to get the pipeline project underway.
President Susan Cole noted her firm’s pipeline route travels east of Elk Island Park, but then swings westward, with an eye to the potential CO2 sources in the Wabamun area’s power plants.
“We’d certainly like Keephills 3,” she said, referring to the new coal-fired Capital Power/TransAlta plant that is part of the Project Pioneer’s carbon capture plan.
North West, a private company, has already spent $400 million on the site, equipment and engineering. Joint partner Canadian Natural will contribute $400 million, and the rest is being raised from investors. The balance of the capital cost — about $4 billion — will be bank-financed debt.
dcooper@edmontonjournal.com
At least that was Energy Minister Ron Liepert’s view, when he said “I’m optimistic as we move forward it will bring other opportunities down the road” to ensure at least 60 per cent of the oilsands output creates jobs and value-added products in Alberta.
While there has been criticism that the province is dabbling in the free market through its bitumen royalty in kind (BRIK) program, Liepert defended the move and challenged the perception of market intervention.
“This is the Crown’s share. All we are doing is entering into an agreement to have it refined locally rather than somewhere else,” Liepert said.
Ian MacGregor, chairman of North West Upgrading, said every major oil company upgrades and refines its bitumen production, either in Alberta or the U.S.
“There is only one producer who is not, and by 2025 the largest one will be the province (through its royalties). Alberta is making the same decision that every other producer is making,” he said.
“It is a good idea to get more money for your products.”
MacGregor recently confirmed the North West staff roster is growing quickly as the fledgling Calgary-based company hires dozens of staff, but “we still have a ton of engineering to finish.”
Although he had initially hoped that some field work could begin later this summer or fall, he now says that is unlikely.
“But we will be ready to go full speed in the spring, and get the underground utilities and other work completed next year.”
The large Korean-built reactor vessels, now in storage in Minnesota, must travel on frozen railbeds to the upgrader construction site.
“So that will be during the winter of 2012-2013. Those are key pieces for the upgrader,” he said.
Neil Shelly, executive director of Alberta’s Industrial Heartland, a group of local municipalities, says the BRIK program will allow the province to hedge its bets on its bitumen investment.
“If North West were open right now, the government would be banking some very good returns.”
More than half the $5 billion upgrader’s output will be diesel.
“If you look at what the price of bitumen is — about $55 to $60 a barrel — versus the price of diesel fuel of perhaps 90 cents a litre, well that works out to $154 to $160 a barrel for diesel. So the government is making an extra $100 a barrel selling into the market,” said Shelly.
Of course, the project is a huge shot in the arm for the region, with 3,000 jobs during each of the three-year construction cycles for each of the three proposed phases.
“That’s nine years of work, and we could get more companies coming in as well. But BRIK is not popular in some political circles, so if the political landscape changes anything could happen.”
Under BRIK, the province said it would make available 75,000 barrels per day of bitumen, with 37,500 bpd going to Phase 1 of the North West plant, and the balance going to Phase 2 if the first proves to be economic. Partner Canadian Natural Resources Ltd. will add 12,500 bpd to each phase.
When the diluent is added, the actual inflow will be 77,000 barrels of diluted bitumen. From this, the plant will produce 36,000 bpd of ultra-low-sulphur diesel (about 5.7 million litres per day), 18,000 bpd of naphtha and return 14,000 bpd of diluent.
The province could have a total of 400,000 bpd of BRIK bitumen available by 2030 as oilsands plants pay off construction costs and start to contribute the standard 25-per-cent royalty.
Analysts have said $5 billion for a plant to handle 50,000 bpd of bitumen works out to a rather expensive $100,000 per flowing barrel compared with standard upgraders.
But the North West project is unique, using a much cleaner gasifier process rather than traditional coking. This allows for the collection of carbon dioxide gas, giving its main product the lowest carbon footprint of any diesel fuel.
Under the 30-year deal between the province and North West/CNRL, the equity partners will be able to recoup their investment, pay operating costs and achieve a return on capital through tolls similar to those paid by pipeline users. Alberta expects to earn an extra $200 million to $700 million over the three decades by selling diesel rather than raw bitumen.
As the 75-per-cent supplier of bitumen, the province will pay three-quarters of the operating costs and receive three-quarters of the benefits, officials have said.
While Alberta has been criticized for its growing carbon dioxide emissions, the North West project will be the only one in the world to combine gasification technology with CO2 management, capturing 1.2 million tonnes of CO2 per phase, which will be sold to Enhance Energy Inc.’s Alberta Carbon Trunk Line for use in enhanced oil recovery in central Alberta.
Enhance will start with CO2 from the Agrium fertilizer plant adjacent to North West near Redwater, and add the upgrader’s gas by mid to late 2014. Enhance hopes other suppliers will eventually tap in.
North West’s contribution of CO2 was enough to get the pipeline project underway.
President Susan Cole noted her firm’s pipeline route travels east of Elk Island Park, but then swings westward, with an eye to the potential CO2 sources in the Wabamun area’s power plants.
“We’d certainly like Keephills 3,” she said, referring to the new coal-fired Capital Power/TransAlta plant that is part of the Project Pioneer’s carbon capture plan.
North West, a private company, has already spent $400 million on the site, equipment and engineering. Joint partner Canadian Natural will contribute $400 million, and the rest is being raised from investors. The balance of the capital cost — about $4 billion — will be bank-financed debt.
dcooper@edmontonjournal.com
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