Suchergebnisse

Approximately 60 per cent of Alberta's oil sands production is non-upgraded bitumen which, after being mixed with a diluting agent (diluent) to allow transport, is exported. A popular view within Alberta — and particularly among Albertan politicians — is that a much larger share of oil sands bitumen should be upgraded in the province. However, without public subsidies or government underwriting, it is uneconomic to build and operate new facilities in Alberta to fully upgrade the bitumen into synthetic crude oil. But there are new partial upgrading technologies being developed that, subject to successful testing at a larger (commercial) pilot scale, can prove to be not only economic in Alberta, but also generate large social and economic benefits for the province. The advantages include a much smaller capital investment, a significant increase in the value of the product and market for the product and, even more importantly, a dramatic reduction in the need for large amounts of expensive diluent to transport the product to market. Indeed, the only diluent required will be that to move the bitumen from the production site to the partial upgrader and this can be continually recycled. The market for the synthetic crude oil produced by full upgrading is only getting tougher. Any Alberta bitumen fully upgraded here would compete closely with the rapidly expanding supply of light U.S. unconventional oil. Partial upgrading does not upgrade bitumen to a light crude, but to something resembling more of a medium or heavy crude, and at a lower cost per barrel than full upgrading. Unlike in the increasingly crowded light-crude market, the Alberta Royalty Review Advisory Panel recognized that currently there are gaps in several North American refineries that could be filled by this partially upgraded Alberta oil. A partial upgrader serving that less-competitive market not only appears to hold the potential for investors to make attractive returns in the long term, it would also provide important benefits to Alberta from a social perspective. Since partially upgraded crude can be shipped via pipeline without diluent (as bitumen requires), producing it in Alberta would free up pipeline capacity otherwise tied up by current volumes of diluted bitumen or dilbit (diluent typically represents about one-third of each barrel of dilbit). It also reduces the cost to shippers of paying tolls for diluent exported in the dilbit and recovering diluent at the U.S. pipeline terminal, where it is less valuable than if it were recovered in Alberta at the partial upgrader. The value of each barrel produced would also be higher, benefitting oil sands producers. Partial upgrading also seems to promise a lower emissions-intensity profile compared to other bitumen-processing technologies. Based on the model of a single 100,000-barrel-a-day partial upgrader, the value uplift could be $10 to $15 per bitumen barrel. Meanwhile, there could be an average annual increase to Alberta's GDP of $505 million, and as many as 179,000 person-years of employment created (assuming a 40.5-year operating period). The increase in taxable earnings would increase provincial revenues by an average of $60 million a year, not including additional federal tax revenues. If successful, there would be many such partial upgraders with corresponding multiplication of these benefits. But there remains the critical task of proving partial upgrading technology at a higher scale than current testing. This might also depend on the province helping sustain investors through the "death-valley" between successful research and initial testing and demonstration of full commercial viability. The province has stepped into help technologies cross that "death valley" before. The promise of partial upgrading may well justify, as manager and steward of Alberta's resources, helping bridge that valley again.

Approximately 60 per cent of Alberta's oil sands production is non-upgraded bitumen which, after being mixed with a diluting agent (diluent) to allow transport, is exported. A popular view within Alberta — and particularly among Albertan politicians — is that a much larger share of oil sands bitumen should be upgraded in the province. However, without public subsidies or government underwriting, it is uneconomic to build and operate new facilities in Alberta to fully upgrade the bitumen into synthetic crude oil. But there are new partial upgrading technologies being developed that, subject to successful testing at a larger (commercial) pilot scale, can prove to be not only economic in Alberta, but also generate large social and economic benefits for the province. The advantages include a much smaller capital investment, a significant increase in the value of the product and market for the product and, even more importantly, a dramatic reduction in the need for large amounts of expensive diluent to transport the product to market. Indeed, the only diluent required will be that to move the bitumen from the production site to the partial upgrader and this can be continually recycled. The market for the synthetic crude oil produced by full upgrading is only getting tougher. Any Alberta bitumen fully upgraded here would compete closely with the rapidly expanding supply of light U.S. unconventional oil. Partial upgrading does not upgrade bitumen to a light crude, but to something resembling more of a medium or heavy crude, and at a lower cost per barrel than full upgrading. Unlike in the increasingly crowded light-crude market, the Alberta Royalty Review Advisory Panel recognized that currently there are gaps in several North American refineries that could be filled by this partially upgraded Alberta oil. A partial upgrader serving that less-competitive market not only appears to hold the potential for investors to make attractive returns in the long term, it would also provide important benefits to Alberta from a social perspective. Since partially upgraded crude can be shipped via pipeline without diluent (as bitumen requires), producing it in Alberta would free up pipeline capacity otherwise tied up by current volumes of diluted bitumen or dilbit (diluent typically represents about one-third of each barrel of dilbit). It also reduces the cost to shippers of paying tolls for diluent exported in the dilbit and recovering diluent at the U.S. pipeline terminal, where it is less valuable than if it were recovered in Alberta at the partial upgrader. The value of each barrel produced would also be higher, benefitting oil sands producers. Partial upgrading also seems to promise a lower emissions-intensity profile compared to other bitumen-processing technologies. Based on the model of a single 100,000-barrel-a-day partial upgrader, the value uplift could be $10 to $15 per bitumen barrel. Meanwhile, there could be an average annual increase to Alberta's GDP of $505 million, and as many as 179,000 person-years of employment created (assuming a 40.5-year operating period). The increase in taxable earnings would increase provincial revenues by an average of $60 million a year, not including additional federal tax revenues. If successful, there would be many such partial upgraders with corresponding multiplication of these benefits. But there remains the critical task of proving partial upgrading technology at a higher scale than current testing. This might also depend on the province helping sustain investors through the "death-valley" between successful research and initial testing and demonstration of full commercial viability. The province has stepped into help technologies cross that "death valley" before. The promise of partial upgrading may well justify, as manager and steward of Alberta's resources, helping bridge that valley again.

Life cycle assessment (LCA) of greenhouse gas (GHG) emissions has been promoted as a tool to inform numerous decisions related to Canadian oilsands development, including low-carbon fuel standards, the proposed TransCanada Keystone XL pipeline, and the development of the European Fuel Quality Directive. While life cycle assessments of transportation fuels have been performed for over two decades, not until recently has LCA been used as a basis for fuel policies such as low-carbon fuel standards and renewable fuel standards

Since 2006, the government of Alberta has tried to increase the volume of raw bitumen upgraded and refined in the province. More specifically, the Alberta Petroleum Marketing Commission (APMC) and Canadian Natural Resources Ltd. (CNRL) have entered into agreements with a facility northeast of Edmonton called the North West Redwater (NWR) Sturgeon Refinery. The NWR Sturgeon Refinery is designed to process 79,000 barrels per day (bpd) of feedstock, consisting of 50,000 bpd of bitumen and 29,000 bpd of diluent (referred to as dilbit). The refinery will produce petroleum products consisting of approximately 40,000 bpd of low sulphur diesel, 28,000 bpd of diluent and 13,000 bpd of other lighter petroleum products. It will also be able to capture 1.2 million tonnes per year of carbon dioxide emitted from the refinery's operations. This captured carbon dioxide will be compressed, put into a pipeline and then injected into an existing oil field in order to achieve increased production of crude oil (referred to as enhanced oil recovery or EOR). It is the first refinery built in Canada since 1984, and the first one in Canada to refine bitumen into petroleum products such as diesel fuel. It differs from the upgrader built in Lloydminster which only upgrades bitumen into synthetic crude oil that requires further refining at a conventional refinery in order to produce petroleum products. This paper gives a description of the structure of this support by APMC and CNRL using a mechanism whereby those two parties agree to enter into tolling agreements to process the diluted bitumen feedstock into refined petroleum products for sale. Under the tolling agreement, APMC and CNRL retain ownership of the diluted bitumen as it is refined into petroleum products. APMC and CNRL then sell such petroleum products, and pay a tolling fee to the NWR Sturgeon Refinery for the refining service provided. The paper also uses an economic model in Excel to give a projection of the economics of this facility for the first full year of operation. The objective is to put numbers to a project that has been the subject of much qualitative discussion. The Excel economic model contains base case assumptions for a number of variables such as the capital cost of the refinery, the financing costs associated with such capital costs, the operating costs of the refinery, the cost of the diluted bitumen feedstock and the price of the petroleum products produced by and sold from the refinery. Based on these base case assumptions, the Excel economic model shows that in the first full year of operation of the NWR Sturgeon Refinery in 2019, the two toll-paying entities, APMC and CNRL, are projected to lose a cash amount of about $24 million (about $1 per barrel of diluted bitumen supplied). This loss is based on a comparison to the toll payers' alternative of just selling the diluted bitumen feedstock at market prices. The paper then uses the economic model to do a sensitivity analysis to show the effect of a lower or higher price of diluted bitumen feedstock, as well as the effect of a lower or higher price of the produced petroleum products. If the cost of the diluted bitumen feedstock were lower, or the price of the petroleum products were higher, then APMC and CNRL would earn a profit. If the converse occurred (feedstock costs higher or petroleum product price lower), then the loss to APMC and CNRL would be greater than $24 million. Finally, the paper attempts to create a template for governments to use when they consider whether or not to provide financial assistance to various projects.

Since 2006, the government of Alberta has tried to increase the volume of raw bitumen upgraded and refined in the province. More specifically, the Alberta Petroleum Marketing Commission (APMC) and Canadian Natural Resources Ltd. (CNRL) have entered into agreements with a facility northeast of Edmonton called the North West Redwater (NWR) Sturgeon Refinery. The NWR Sturgeon Refinery is designed to process 79,000 barrels per day (bpd) of feedstock, consisting of 50,000 bpd of bitumen and 29,000 bpd of diluent (referred to as dilbit). The refinery will produce petroleum products consisting of approximately 40,000 bpd of low sulphur diesel, 28,000 bpd of diluent and 13,000 bpd of other lighter petroleum products. It will also be able to capture 1.2 million tonnes per year of carbon dioxide emitted from the refinery's operations. This captured carbon dioxide will be compressed, put into a pipeline and then injected into an existing oil field in order to achieve increased production of crude oil (referred to as enhanced oil recovery or EOR). It is the first refinery built in Canada since 1984, and the first one in Canada to refine bitumen into petroleum products such as diesel fuel. It differs from the upgrader built in Lloydminster which only upgrades bitumen into synthetic crude oil that requires further refining at a conventional refinery in order to produce petroleum products. This paper gives a description of the structure of this support by APMC and CNRL using a mechanism whereby those two parties agree to enter into tolling agreements to process the diluted bitumen feedstock into refined petroleum products for sale. Under the tolling agreement, APMC and CNRL retain ownership of the diluted bitumen as it is refined into petroleum products. APMC and CNRL then sell such petroleum products, and pay a tolling fee to the NWR Sturgeon Refinery for the refining service provided. The paper also uses an economic model in Excel to give a projection of the economics of this facility for the first full year of operation. The objective is to put numbers to a project that has been the subject of much qualitative discussion. The Excel economic model contains base case assumptions for a number of variables such as the capital cost of the refinery, the financing costs associated with such capital costs, the operating costs of the refinery, the cost of the diluted bitumen feedstock and the price of the petroleum products produced by and sold from the refinery. Based on these base case assumptions, the Excel economic model shows that in the first full year of operation of the NWR Sturgeon Refinery in 2019, the two toll-paying entities, APMC and CNRL, are projected to lose a cash amount of about $24 million (about $1 per barrel of diluted bitumen supplied). This loss is based on a comparison to the toll payers' alternative of just selling the diluted bitumen feedstock at market prices. The paper then uses the economic model to do a sensitivity analysis to show the effect of a lower or higher price of diluted bitumen feedstock, as well as the effect of a lower or higher price of the produced petroleum products. If the cost of the diluted bitumen feedstock were lower, or the price of the petroleum products were higher, then APMC and CNRL would earn a profit. If the converse occurred (feedstock costs higher or petroleum product price lower), then the loss to APMC and CNRL would be greater than $24 million. Finally, the paper attempts to create a template for governments to use when they consider whether or not to provide financial assistance to various projects.