BC: CANADIAN ENERGY ASSETS
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ENERGY OVERVIEW
Canada was the fifth-largest energy producer in the world in 2001, behind the United States, Russia, China, and Saudi Arabia. Over the past two decades, Canada has become a significant net energy exporter. In 2001, about 31% of Canadian energy production was exported, with the United States its main customer. In the first three quarters of 2003, the United States imported more oil (including crude oil and petroleum products) from Canada than from any other country. During the same time period, the United States also imported about 2.5 trillion cubic feet (Tcf) of Canadian natural gas, representing 87% of total U.S. natural gas imports. In 2001, about 39% of Canada's primary energy production was natural gas, followed by oil (25%), hydropower (20%), coal (11%), and nuclear power (5%). Alberta is Canada's largest producer of energy. Along with being a major energy-producer, Canada also was a significant energy consumer in 2001, ranking eighth in the world.
OIL
According to Oil & Gas Journal, as of January 2004, Canada's total proven crude oil reserves stood at 178.9 billion barrels. Canada currently trails only Saudi Arabia, which holds the most proven crude oil reserves in the world. Prior to 2002, Canada did not even rank in the top 20 of countries with the most proven crude oil reserves. The massive increase in reserves reflects the Journal's inclusion of Alberta's oil sands, which stood at 174.4 billion barrels as of January 2004, according to Alberta Energy and Utilities Board (EUB). In contrast, conventional crude oil and condensate stood at an estimated 4.5 billion barrels, as reported by Canadian Association of Petroleum Producers (CAPP). Some analysts, however, have questioned the new assessment and whether it is accurate and appropriate to include oil sands.
Exploration and Production
Canada's t otal oil production (including all liquids, bitumen and synthetic crude) averaged an estimated 3.1 million barrels per day (bbl/d) for 2003, an increase of 7% over 2002. The country's oil production has been increasing since 1999, as new oil sands projects and production off the coast of Newfoundland have come onstream. Overall, oil sands production is expected to increase significantly and to offset the decline in conventional crude oil production, becoming Canada's major source of oil supply.
Western Canada Sedimentary Basin
The Western Canada Sedimentary Basin (WCSB), underlying most of Alberta and parts of British Columbia, Saskatchewan, Manitoba and the Northwest Territories, has been the main source of Canadian oil production for the past 50 years. Alberta, however, has been the primary oil producer not only for the region but also for the entire country.
Although conventional oil production in Alberta and in the WCSB as a whole has been declining, increased output of non-upgraded bitumen and synthetic crude (crude oil which has been upgraded from raw bitumen) from oil sands has compensated for the shortfall in conventional supplies (see table). According to EUB’s Alberta’s Reserves 2002 and Supply/Demand Outlook 2003-2012, total raw bitumen production in Alberta during 2001exceeded total conventional crude oil production in the province for the first time. In 2002, production of non-upgraded bitumen and synthetic crude averaged combined 743,738 bbl/d while conventional crude oil production (light, medium and heavy grades) averaged an estimated 660,551 bbl/d. The report also forecasts that combined production from conventional and oil sands is expected to reach 2.7 million bbl/d by 2012, of which 77% will be supplied from oil sands.
Atlantic Coast
Crude oil production off the coast of Newfoundland has increased significantly in the past few years. According to preliminary estimates from Canada’s National Energy Board (NEB), oil production off the coast of Newfoundland is forecast to reach 346,000 bbl/d for 2003, an increase of 132% since 2001. Exploration and production activity on Canada's east coast is carried out in the Jeanne d'Arc Basin, offshore Newfoundland. The climate demands technologically advanced offshore oil platforms, able to withstand extremely cold temperatures, icebergs and high winds, adding to production costs.
The first project in Canada's Atlantic coast regioncame onstream in November 1997. The field, known as Hibernia, is located 197 miles east-southeast of St. John's, Newfoundland. Production has increased rapidly since Hibernia's startup. From January to October 2003, the field averaged nearly 200,000 bbl/d. An additional reservoir, Avalon, came onstream in May 2000 and has averaged 5,668 bbl/d over the same time period. The area also contains natural gas, which currently is being re-injected into the Hibernia reservoir to increase the oil recovery rate from the field. ExxonMobil Canada is the operator, with joint venture partners Chevron Canada, Petro-Canada, Canada Hibernia Holding Corporation, Murphy Oil, and Norsk Hydro.
A second project, Terra Nova, began production in January 2002. Crude oil extracted from Terra Nova's reservoir on the ocean floor is routed upward to the Terra Nova floating production storage and offloading vessel (FPSO), a storage vessel that processes the crude oil on deck. The petroleum is then transferred to shuttle tankers that take the oil to market. From January to October 2003, the field averaged 131,882 bbl/d. Petro-Canada is the operator of the field, with other partners including ExxonMobil, Norsk Hydro, Husky Oil Operations, Murphy Oil Corporation, Mosbacher Operating, and Chevron Canada Resources.
Other Developments
White Rose and Hebron/Ben-Nevis fields are two other projects that are currently under development. The White Rose field, which is operated by Husky Oil Operations, is expected to begin production in 2005 or early 2006. The field could reach an estimated 90,000 bbl/d at peak production. According to Husky Oil, the White Rose field also holds an estimated 2.5 Tcf of natural gas that also could be produced eventually if proven economically viable.
In February 2002, the Hebron/Ben-Nevis project was suspended indefinitely by ChevronTexaco (operator). The company indicated that the field was not economical viable due to significant challenges in developing scattered deposits, in addition to the high viscosity of the oil, which increases production costs. In October 2003, ChevronTexaco, along with its partners -- ExxonMobil, Norsk Hydro and Petro-Canada -- indicated that they have been reconsidering the project and eventually may develop it.
Besides the Hebron/There have been other setbacks off the east coast of Canada. In early June 2003, Petro-Canada and partners, EnCana and Norsk Hydro, abandoned exploration activities in the Flemish Pass Basin after the exploration well, Mizzen L-11, did not produce enough oil to make the well commercially viable. The partners subsequently abandoned the second prospect, Tuckamore B-27.
On December 17, 2003, the Canada-Newfoundland Offshore Petroleum Board auctioned exploration rights for eight out of 14 concessions, with ChevronTexaco, ExxonMobil and Imperial Oil purchasing rights to explore for oil in the Orphan Basin. Orphan is located in deep waters north of the Jeanne d’Arc Basin. According to a recent seismic study, there are four large reservoirs, with each potentially holding up to 1 billion barrels of oil. Exploration activities for oil are also being conducted onshore in both New Brunswick and Nova Scotia.
Pacific Coast
The British Columbia government is pushing to lift a 30-year-old ban on exploration in the Pacific Ocean in order to begin production by 2010. The area near Queen Charlotte Basin is thought to hold as much as 10 billion barrels of oil. Queen Charlotte, Tofina, Winona and Georgia basins are expected to hold an estimated 43.4 Tcf of natural gas, according to British Columbia Ministry of Energy and Mines.
Synthetic Crude Oil
Oil sands contain deposits of bitumen (a heavy, black viscous oil). To process bitumen, it first must be extracted from the ground. There are two extraction methods. Shallow oil sands deposits, which can be excavated from the surface, and deeper "in situ" (in situ means "in place," indicating that the bitumen is separated underground) deposits which require other recovery methods, such as cyclic steam stimulation and steam-assisted gravity drainage (SAGD). These methods inject steam to help separate the bitumen from sand and clay and bring it to the surface. According to the Alberta Ministry of Energy, roughly two tons of oil sands must be dug up, moved and processed to produce one barrel of oil.
The extracted bitumen is then separated from sand and water, which it surrounds. Before it is sent to a refinery to be upgraded into high-quality oil called "synthetic crude," the bitumen must be diluted with lighter hydrocarbons to make it transportable by pipelines. At the refinery, the bitumen will be treated again and upgraded into synthetic crude. The upgrading process also generates other products, such as petroleum coke, which is either used to power the facility or sold.
The Athabasca Oil Sands deposit, in northern Alberta, is one of the two largest oil sands deposits in the world. There are also oil sands deposits on Melville Island, in the Canadian Arctic and two smaller deposits in northern Alberta, Peace River and Cold Lake.
Oil Sands Production
Mining
A majority of non-upgraded crude bitumen production to date has come from three surface mining projects which averaged a combined 526,510 bbl/d in 2002. A large portion of this production is then upgraded into synthetic crude oil. EUB has forecast mined bitumen production to reach 1.56 million bbl/d by 2012
The first project, Syncrude Canada Limited (a joint venture of eight companies with Canadian Oil Sands Investments Incorporated having the largest stake), was Canada's largest producer of both non-upgraded crude bitumen and synthetic crude from oil sands in 2002, averaging around 270,547 bbl/d and 230,000 bbl/d, respectively. Synthetic crude production is expected to reach 350,000 bbl/d after Syncrude completes stage 3 of its expansion program in 2005. Other planned production expansions (stages 4 and 5) will increase production to an estimated 550,000 bbl/d by around 2015.
Suncor Energy, the first company to begin processing Alberta oil sands (in 1967), averaged 258,400 bbl/d of non-upgraded crude bitumen and about 206,000 bbl/d of synthetic crude in 2002. In 2001, Suncor completed its Project Millennium, which increased production capacity of synthetic crude to 225,000 bbl/d. The company's next project, Voyageur, aims to increase production of synthetic crude to between 500,000-550,000 bbl/d in 2010 to 2012. The project has three stages: 1) expand existing upgrader; 2) increase bitumen supply through further development of the Firebag In-situ Oil Sands Project; and 3) establish a third oil sands upgrader.
The Athabasca Oil Sands Project is a joint venture of Shell Canada Limited, Chevron Canada Limited (a wholly owned subsidiary of ChevronTexaco Corporation) and Western Oil Sands Incorporated. The project has two components: the Muskeg River Mine; and the Scotford Upgrader, which is located in Fort Saskatchewan. Diluted bitumen is shipped from the Muskeg River Mine via the Corridor pipeline to the Scotford Upgrader, where the bitumen is upgraded into synthetic crude oil. Production of non-upgraded bitumen has increased steadily since coming onstream in December 2002, averaging 115,000 bbl/d in the third quarter of 2003. Expected capacity of the project is 155,000 bbl/d. Shell Canada currently is considering a long-term expansion program of the Athabasca project, with production eventually reaching 525,000 bbl/d of non-upgraded bitumen. Potential projects include the expansion of Muskeg River Mine to 225,000 bbl/d and development of Jackpine Mine Phase 1 and 2, which combined would produce 300,000 bbl/d. Shell, however, has not committed to a timeline.
Thermal (In-situ)
In 2002, non-upgraded crude bitumen production from in-situ operations averaged 299,843 bbl/d. Most of in-situ production to date has been marketed in non-upgraded form outside of Alberta and only a small percentage is used in Alberta refineries. EUB has forecast in-situ production to reach 773,647 bbl/d by 2012.
In 2003, there were 10 in-situ bitumen projects in operation. The most productive operation was Imperial Oil's Cold Lake , which has averaged around 120,000 bbl/d over the past few years. In 2002, the company completed the Mahkeses (phases 11-13) project, which is expected to increase production to 150,000 bbl/d. Canadian Natural Resources (CNR) currently operates the second largest in-situ project in Alberta (Primrose/Wolf Lake), which produces approximately 40,000 bbl/d. CNR received regulatory approval on August 16, 2002 to expand its operations to more than 120,000 bbl/d. CNR also is developing its Horizon project, with initial production of 110,000 bbl/d, beginning in 2008.
Other Canadian in-situ projects in operation include: Japan Canada Oil Sands Limited Hangingstone Project, Petro-Canada McKay River Project; EnCana Corporation Christina Lake and Foster Creek projects; and Devon Energy Dover Project.
Developments
There are a number of oil sands projects that are being developed currently, such as ConocoPhillips' $1.1 billion Surmont oil sands project and Nexen and OptiCanada's Long Lake and Meadow Creek projects (start-up date 2006). Other companies developing oil sands projects include, Imperial, ExxonMobil, and Husky Energy.
In December 2003, Petro-Canada decided to delay plans to develop a new extraction facility at Meadow Lake, after projected costs escalated. The original plans called for production of 80,000 bbl/d, beginning in 2007. Petro-Canada instead opted to upgrade and to expand the capacity of its Edmonton refinery so that it could process bitumen-based feedstock into gasoline, diesel and other consumer end products.
Difficulties
A combination of high development costs, growing environmental concerns, and high natural gas prices have resulted in some companies delaying or downsizing projects in recent months. The extraction of bitumen, particularly underground (in-situ), requires significant amounts of natural gas and water. Natural gas is used not only to generate steam, which is injected into the ground to melt the mud away from the bitumen but also is used to generate electricity to power the massive shovels used for pit mining. Some analysts predict that if all proposed oil sand projects are realized, companies eventually will require up to 2 billion cubic feet per day of natural gas.
Future Kyoto requirements - Canada ratified the Protocol in December 2002 - could also raise costs, as companies would most likely have to invest in emission reducing technologies or acquire carbon credits to offset emissions resulting from production. Uncertainty about the potential impact of implementing the Kyoto Protocol prompted TrueNorth Energy in January 2003 to defer construction of its $3.5 billion Fort Hills Oil Sands Project. In addition, CNR initially postponed its giant Horizon project due to potential economic costs of reducing emissions. CNR decided to go ahead with the project only after the Canadian government assured oil sand companies that they would not be hindered by the associated costs of limiting emissions. The government temporarily placed a cap on the price of the credits in Canada that may have to be purchased to allow the companies to emit CO2.
Canadian Oil Exports
Canada is a major source of U.S. oil imports. From January to October 2003, the United States imported 1.9 million bbl/d of oil from Canada (1.5 million bbl/d of which was crude oil). This makes Canada the top petroleum supplier to the United States and the third-largest supplier of crude oil imports (behind Saudi Arabia and Mexico, and ahead of Venezuela). Canada has been the top supplier to the United States of refined petroleum products, including gasoline, jet fuel, distillate, etc., since 1996.
A majority of U.S.-bound Canadian oil exports go to the Midwest (PADD II). From January to October 2003, Canada exported 1.07 million bbl/d to PADD II, accounting for approximately 69% of PADD II's total oil imports. Canadian oil exports also dominate in the Rocky Mountain region (PADD IV), averaging 260,000 bbl/d during January - October 2003, and accounting for nearly 100% of the district's total oil imports. Canada also exports 569,000 bbl/d of its oil to the U.S. East Coast (PADD I) as well as, to a lesser extent, to the Gulf Coast region (PADD III) and the West Coast (PADD V).
Sector Organization
Canada's oil sector has seen significant mergers and acquisitions in recent years. In 2001, U.S. firms purchased over $35 billion in Canadian oil and natural gas assets, including Houston-based ConocoPhillip’s purchase of Gulf Canada for $8.9 billion and Devon Energy's (U.S.) acquisition of Canada's Anderson Exploration for $7.1 billion.
Canadian firms also have been busy reorganizing the country's oil patch. In April 2002, two of Canada's largest companies, Alberta Energy Company Limited and PanCanadian Energy Corporation, merged to create EnCana Corporation, country's largest non-integrated oil and natural gas producer (by market value).
However, it now appears that U.S. firms are beginning to retreat from Canada, particularly from assets held in Western Canada. Over the past year, El Paso, ChevronTexaco, Marathon Oil, ConocoPhillips, Vintage Oil, Hunt Oil, and Murphy Oil have made moves to divest conventional hydrocarbon assets (mainly natural gas). Canada's EnCana also made an announcement in November 2003 that it plans to sell (Canadian) $1 billion in assets. Analysts speculate that companies are putting their Canadian properties up for sale because many of these assets are mature or no longer economic viable. In the case of ChevronTexaco, the company reportedly is selling its assets in order to focus on higher-growth prospects in its global energy portfolio.
Pipelines
An extensive pipeline system transports western Canadian oil to eastern Canadian and U.S. markets. There are two major oil pipeline operators in Canada. The first is Enbridge Pipelines Incorporated which operates a 9,000-mile network of piping and terminals, delivering oil from Edmonton, Alberta, east to Montreal, Québec and eastern Canada, as well as to the U.S. Great Lakes region.
The other major Canadian pipeline operator is Terasen. The company operates the Trans Mountain Pipe Line (TMPL), which delivers oil mainly from Alberta west to refineries and terminals in the Vancouver, British Columbia area, as well as to the Puget Sound area of Washington State. Terasen is currently in the process of increasing TMPL 's capacity by 30,000 bbl/d. The company also runs the Express pipeline which links Hardisty, Alberta to Casper, Wyoming. From there, the Express line connects to the Platte pipeline, which has a terminus in Wood River, Illinois.
With production from Alberta’s oil sands increasing, Enbridge has been seeking to expand its U.S. export capacity through development and acquisition of pipelines. In April 2003, Enbridge completed the final stage to its Terrace Expansion Project. The first stage of the project linked Kerrobert, Saskatchewan to Clearbrook, Minnesota, adding approximately 210,000 bbl/d of capacity to the Enbridge network. The finally phase extended the line further into Minnesota, adding 140,000 bbl/d of capacity.
In September 2003, Enbridge acquired 90% stake in the Cushing to Chicago Pipeline System. The 650-mile pipeline has capacity of 300,000 bbl/d. Enbridge plans to reverse the flow of the pipeline in order to transport crude oil from Chicago to Cushing, allowing Canadian producers access to new markets in the U.S. Enbridge which plans to rename the pipeline Spearhead plans to have the reversal of the line completed in 2004.
In October 2003, Enbridge announced a proposed project to build a crude oil pipeline (Southern Access) from its existing terminal at Superior, Wisconsin, south to the Wood River hub in southern Illinois. The 630-mile pipeline is expected to have an initial capacity of 250,000 bbl/d and to interconnect with the abovementioned Spearhead pipeline. Enbridge expects to have it operational by 2007, pending regulatory approval.
Oil Sands Pipelines
Development of Alberta's massive oil sands deposits has required new pipelines to transport diluted bitumen from the mine to downstream processors and eventually to market terminals. Up to now, Canadian pipeline companies have focused on taking the Athabasca oil sands southward, to processing facilities in the Edmonton area. The first of these pipelines, the 344-mile Athabasca pipeline (Enbridge), was completed in April 1999 and connects Suncor's oil sands operations to the Enbridge network. The pipeline has potential capacity of 570,000 bbl/d. The second pipeline, Corridor (Terasen), connects the Muskeg River Mine to Shell's Scotford Refinery. Oil began to flow through the Corridor Pipeline in May 2003.
Currently both Terasen and Enbrigde are exploring possibilities of increasing their shipping capacity. Terasen recently revived its Bison Pipeline project after delaying it in May 2003. The plan calls for building a pipeline to transport diluted bitumen from mines and refineries near Fort McMurray to pipelines and processing plants in the Edmonton area. Terasen would increase the pipelines capacity over three stages: 1)172,000 bbl/d by 2006; 2) 320,000 bbl/d by 2008; and 3) 610,000 bbl/d by 2010. The final phase would include constructing a second pipeline parallel to the first. Whether the project continues to move forward is dependent upon whether Terasen can secure sufficient crude oil supplies in Fort McMurray.
Enbridge is exploring the possibility of building a new oil pipeline from the Athabasca oil sands region to the coast of British Columbia, for export to California or Asia by 2009. The project, called the Gateway Pipeline, would provide 400,000 bbl/d of capacity and would link Alberta either to Prince Rupert or to Kitimat, on the British Columbia coast, where ships would take crude oil and petroleum products to refineries in California and in Asia. |
