Canada is endowed with extensive energy resources, and is a large producer and net exporter of natural gas, coal, hydropower, and uranium. Canada is a major supplier of electric power to Northeastern U.S. markets. It also exports a significant amount of natural gas to the United States, with plans for much more in coming years.

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GENERAL BACKGROUND
After experiencing only slow growth throughout the 1990s, Canada's economy accelerated rapidly in 1997, reaching an annual 3.6% real GDP growth rate. Unemployment, which had stubbornly remained near or above 10% between 1990 and 1996, fell below 9% (to 8.9%) in October 1997, with inflation remaining under 2%. Interest rates also remain low, having fallen sharply since 1995. In addition, retail sales have expanded strongly in 1997 (at least through October), with manufacturers operating at over 86% of capacity in the first quarter of the year. Meanwhile, the country's current account has shifted from surplus into deficit as strong domestic consumer demand has caused imports to jump. Finally, the strong economy, combined with lower interest rates and Prime Minister Jean Chretien's deficit-cutting policies, has resulted in sharp drops in the federal deficit (to 1.1% of GDP), and in forecasts of a balanced budget in the near future. Canada's budget has been in deficit for the past 27 years.

On June 2, 1997, Canadians voted in early elections called by Prime Minister Chretien. The result of these elections was that Chretien's Liberal party won a narrow majority (155-146) in the House of Commons, despite losing 20 seats. In October 1995, the separatist opposition party Bloc Qubecois led a referendum on sovereignty for the predominantly French-speaking Canadian province of Quebec. In an extremely narrow vote that revealed deep cultural and political divisions within the country, Quebec citizens opted -- by only 1.2% -- to keep their province a part of Canada. Quebec's Premier Lucien Bouchard has promised another referendum on this issue following a provincial election in 1998. The Bloc Quebecois, although losing five seats in the June nationwide elections, remains a significant opposition party (along with the Reform party).

ENERGY OVERVIEW
Canada is the world's fifth largest energy producer, after the United States, Russia, China, and Saudi Arabia. As of 1996, natural gas accounted for 36.8% of Canada's energy production, followed by petroleum (32.8%), electricity (14.8%), coal (11.7%), and other (3.9%). Nearly two-thirds (65%) of Canada's energy was produced by Alberta province, with British Columbia (13%), Saskatchewan (8%), Quebec (5%), and Ontario (4%) following far behind. Energy production contributed 7.6% of Canada's GDP in 1996, while energy exports made up 10% of total merchandise exports. The United States is Canada's major trade market for energy products, accounting for 91% of all Canadian energy exports (including nearly all of Canada's oil, natural gas, and electricity exports). Coal is exported mainly to the Far East.

OIL
With the onset of lower oil prices in 1986, Canada's oil industry shrunk. Beginning in the early 1990's, however, the industry experienced a strong recovery. Canadian crude oil output has defied pessimistic predictions and has increased sharply since the mid-1980s, from 1.4 million barrels per day (bbl/d) in 1984 to an estimated 1.85 million bbl/d in the first half of 1997 (1H97). In 1H97, total Canadian oil production (including conventional light crude oil, natural gas liquids, heavy crude oil, and synthetic oil from tar sands and bitumen) surpassed 2.5 million bbl/d. Meanwhile, merger and acquisition activity proceeded at a record pace in 1H97, with the total value of such deals reaching $5.4 billion.

The future of Canadian oil production appears bright as well. Canada's National Energy Board expects further oil production increases of 600,000-700,000 bbl/d over the next 5-10 years. This oil will come mainly from several projects in Eastern Canada which promise large volumes of oil. These projects include Newfoundland's Hibernia and nearby Terra Nova fields, as well as West Bonne Bay, Whiterose, and many more potential fields in the Grand Banks region. Besides Eastern Canada, increased Canadian oil production over the next 5-10 years will likely come from heavy oil and synthetic crude development in western Canada.

Besides successes in cost-cutting and downsizing, the recovery in Canada's oil industry has resulted largely from improvements in exploration (i.e., seismic techniques), drilling (particularly horizontal drilling), and production technology (including drill bits, drill rigs, production equipment, and recovery technologies). Increased Canadian oil output during the 1990s so far has consisted largely of conventional heavy oil and synthetic oil. Conventional heavy crude oil (with gravities roughly in the mid-20os API or less) is produced entirely in western Canada, with 60% coming from Alberta and 40% from Saskatchewan. Production of this oil has increased sharply since the early 1980's, primarily as a result of improved technology and increased demand from U.S. refiners. In 1996, production of conventional heavy crude oil reached 518,000 bbl/d, a jump of 50% in only five years. Canada's National Energy Board anticipates further strong increases in 1997 and 1998.

Canada produces a significant amount -- about 474,000 bbl/d -- of synthetic oil from bitumen. To date, over 1 billion barrels of synthetic crude oil has been recovered from western Canadian oil tar sands (out of potentially up to 300 billion barrels in economically recoverable reserves). Production from tar sands now accounts for about 19% of Canada's crude oil supply, and investment in 1996 was over $3 billion. Over the next 25 years, Western Canada's oil industry hopes to increase synthetic crude oil production sharply, to 1.2 million bbl/d (at a cost of up to $20 billion). The industry is currently concentrated in the Fort McMurray areas of northern Alberta, where Syncrude Canada and Suncor, the country's two big oil sands producers, are located. Large amounts (about 185,000 bbl/d) of synthetic crude also is produced by bitumen miners -- led by Imperial Oil (70% owned by Exxon) -- from Alberta's oil sands.

Plant modifications and improved technology have combined to lower operating costs at the Suncor oil sands plant in Alberta. The company hopes to get its cost-per-barrel down from its current average of $14 to $12 by the year 2000. Currently, Suncor's output stands at about 85,000 barrels per day. Suncor aims to increase this -- through investments of $1.5 billion in "Project Millennium" -- to 105,000 bbl/d by the year 1999, and 210,000 bbl/d by 2002. Suncor also is involved in oil sands projects at Burnt Lake in Alberta, as well as the Stuart Oil Shale project in Australia. Meanwhile, Syncrude announced in October 1997 plans for a $1.05 billion mine project at Aurora, near Fort McMurray.

In addition to Syncrude and Suncor, several other companies are involved in developing Canada's oil sands. Mobil Oil Canada and Shell Canada each have $1 billion plans to open two, 100,000 bbl/d oilsands mines in 2002-3 near Fort McMurray. In December 1995, New Mexico-based Solv-Ex Corp. received approval from the Alberta Energy and Utilities Board to proceed with a $100 million oilsands plant near Fort McMurray. Bitumount, one of the sites which Solv-Ex plans to develop, is expected to produce 14,000 bbl/d of oil. Bitumount is part of the Athabasca oil sands, which contains total in-place oil resources of 1.7 trillion barrels, including more than 100 billion barrels estimated as recoverable through surface mining.

Improved technology also has opened up offshore oil areas in eastern Canada, previously considered uneconomical, to development. These areas are important because they are located near potentially large markets in the northeastern United States, and also because they will create jobs in a relatively poor region hit hard in recent years by a decline in the area's traditional industry -- fishing.

One major offshore project, the huge Hibernia Field (located on the Grand Banks of Newfoundland, 195 miles east southeast of St. Johns in waters up to 3 miles deep), contains 3 billion barrels of light, low-sulfur oil (similar in quality to North Sea Brent), of which between 750 million and 1 billion barrels currently is considered recoverable. The field is being developed in a $5.8 billion project by a consortium of four companies: Mobil Oil Canada (33% ownership), Chevron Canada Resources (27%), Petro-Canada (20%), Canada Hibernia Holding Corp. (8.5%), Murphy Atlantic Offshore Oil Co. (6.5%), Norsk Hydro (5%) plus large subsidies from the Canadian government. Hibernia began producing oil on November 17, 1997, a month ahead of its original December 15, 1997 target date. Production, which quickly reached 20,000 bbl/d, is expected to reach 40,000 bbl/d by the end of 1997, and to plateau at 135,000 bbl/d in early 1999, with a potential future increase to 180,000 bbl/d given additional investment. This is 33% more than the consortium previously had thought, largely due to technological advances such as extended-reach and horizontal drilling.

About 22 miles east of Hibernia, Petro-Canada and several partners (including Mobil oil Canada, Husky Oil, Murphy Oil, and Mosbacher Operating Ltd.) are planning another Grand Banks offshore development -- the Terra Nova field. Development of Terra Nova, which is estimated to contain 300-400 million barrels of recoverable oil reserves, is expected to begin in 1998, with production of 100,000 bbl/d of low sulfur, 33oAPI gravity crude oil, and 75 million cubic feet per day (Mmcf/d) of gas beginning in 2001. Total development costs over the lifetime of the project could total $4 billion, excluding tanker costs.

In July 1996, Norsk Hydro, a Norwegian company with extensive offshore experience in the North Sea, was recruited by Petro-Canada to assist in developing both Hibernia and Terra Nova. In exchange, Norsk Hydro will receive percentages of profits from these developments, as well as any future developments in the Jeanne d'Arc Basin off St. John's, Newfoundland. Anne McLellan, Canada's former Natural Resources Minister, welcomed the deal and was seeking further foreign investment in Canada's offshore oil and gas regions.

Another oil and gas development in the Grand Banks region is Whiterose, located about 10 miles east of Terra Nova -- Husky, along with Petro-Canada, Talisman, Gulf Canada, and Parex, plans to drill up to 4 delineation wells beginning in 1998. Production at Whiterose, which contains estimated reserves of 250 million barrels, is expected to produce 75,000-80,000 bbl/d, possibly beginning in 2001.

Although nearly all Canadian oil is produced in western Canada (primarily Alberta), the oil is consumed primarily in central and eastern Canada, as well as in the United States. In fact, Alberta accounts for three quarters of total Canadian crude oil exports to the United States. This situation necessitates an extensive system of pipelines connecting oil producing and consuming areas. This system is dominated by two major pipeline networks: 1) the Interprovincial Pipe Line (IPL) system, which delivers oil from Edmonton east to Montreal, Quebec, and the U.S. Great Lakes region; and 2) the Trans Mountain Pipe Line (TMPL), which delivers oil mainly from Alberta west to refineries and terminals in the Vancouver area, as well as to the Puget Sound area of Washington state. In June 1997, Gulf Canada merged with IPL Energy (the country's major oil pipeline carrier) to form Canada's largest oil and liquids marketer. IPL recently finished a 120,000 bbl/d expansion in pipeline capacity, and expects another 170,000 bbl/d in late 1998 with plans for 520,000 bbl/d more by 2005. Another company, Express Pipeline, recently completed a 175,000 bbl/d export pipeline from Hardisty, Alberta to Casper, Wyoming. Express, which is owned 50-50 by TransCanada and Alberta Energy Company, plans a second leg to carry 100,000 bbl/d or more from Casper to Wood River, Illinois.

In addition to traditional oil-producing areas in Alberta, Canada's far northern territories are also expected to contain significant oil reserves. To date, however, these areas have not been well explored or developed due to aboriginal land claims and economic factors. As a result, only about 1,100 wells have been drilled in Canada's far North, compared to around 160,000 wells in Alberta alone. At present, only one oil pipeline exists in the far North -- the 35,000 bbl/d Norman Wells line to Zama, Alberta, completed in 1985.

REFINING
Canadian refineries are able to process 1.9 million barrels per day of crude oil. Nearly two-thirds of this capacity is concentrated in three provinces - Ontario (543,300 bbl/d), Alberta (397,600 bbl/d), Quebec (364,800 bbl/d) - with the remainder distributed across Canada's other six provinces. Recent Canadian National Energy Board data showed demand for principal petroleum products in Canada averaged about 1.4 million bbl/d in 1994, up 2% from the previous year. Refinery production increased 3% over the same period.

In June 1996, Nova Chemicals of Calgary and Union Carbide of Danbury, Connecticut announced that they had awarded a $37.5 million contract to Stone and Webster Engineering to design a $600 million ethylene plant, as well as two polyethylene plants, near Red Deer, Alberta. Construction on the 2-billion-pound-a-year plant was scheduled to begin in September 1997, and to be completed by 2000. The plant is to be jointly owned by Nova Chemicals and Union Carbide.

Canadian refiners anticipate making large investments over the next few years because of federal and provincial mandates for cleaner fuels. Estimates are that refiners will pay $1-$3 billion (Canadian) to meet the mandates. Canadian refiners also are faced with increasing U.S. competition in the Canadian market.

NATURAL GAS
Canada contains 68 trillion cubic feet (Tcf) of proven natural gas reserves, mainly located in energy-rich Alberta province. An additional 50 Tcf of potential gas reserves is thought to lie off the coast of eastern Canada between Newfoundland and Nova Scotia, and as much as 574 Tcf is suspected to exist in both conventional and unconventional reservoirs. Canada currently produces nearly 5.9 Tcf of natural gas per year, ranking it as the world's third largest gas producer (after the United States and Russia), and second largest gas exporter (after Russia). The country's single most important natural gas source is the Western Canada Sedimentary Basin (WCSB), which extends over most of Alberta, Saskatchewan, British Columbia, and the Northwest Territories. In addition to supplying almost 100% of Canada's natural gas demand, the WCSB supplies gas to the United States. In August 1997, Dynamic Oil Ltd. announced that it had tested what it believes to be the largest gas well ever drilled in western Canada. The well, located just west of Edmonton, Alberta, tested at a maximum open flow of 118 Mmcf/d, with potential of up to 296 Mmcf/d.

Like the oil sector, Canada's natural gas industry is enjoying robust growth. Reserves are ample and an extensive pipeline system exists to deliver gas to domestic and export markets. Healthy U.S. demand led to record Canadian gas exports of 2.8 Tcf in 1996, the eighth straight year of gas export growth. Overall, Canadian gas exports to the United States have more than tripled since 1985. Canadian gas goes mainly (35%) to the central United States, 27% to California, 23% to the Northeast, 14% to the Pacific Northwest, and 1% to the Mountain region. Overall, Canadian natural gas made up 13% of U.S. consumption in 1996. Growth in Canadian gas exports to the United States has resulted in part from deregulation of both countries' natural gas industries.

With U.S. demand for Canadian gas supplies projected to continue increasing for the foreseeable future, Canadian natural gas export pipeline construction is accelerating to prevent a serious capacity bottleneck from developing. The Canadian Energy Pipeline Association estimates that as much as $14.5 billion will be spent on new and expanded pipelines in coming years, including $1 billion in 1997. To supply U.S. gas import demand, the Canadian Energy Research Institute has estimated that Canadian producers will need to nearly double the 4,500 new gas wells expected to be drilled in 1997.

Among other gas pipeline projects, the $2.5 billion, 1,900-mile Alliance pipeline (the longest ever built in North America) is designed to carry about 1.3 billion cubic feet per day (Bcf/d) from western Canada (Fort St. John, British Columbia) to the Chicago area, beginning in late 1999. The Alliance consortium includes mainly western Canadian producers, including Canadian Oxy, Chevron Canada, and Gulf Canada Resources. In addition, U.S.-based Coastal Corp. bought an 11% share of Alliance in September, 1997 for $127 million. Coastal plans to link its ANR pipeline system, which reaches into Joliet, Illinois, with the Alliance pipeline. Coastal also has proposed to expand -- by 1999 -- its U.S. pipeline network through SupplyLink, a $125 million expansion of ANR's existing system that will transport 750 Mmcf/d of gas from the Chicago area to Defiance, Ohio, and the Independence Pipeline, a $630 million pipeline to transport 900 Mmcf/d of gas from Defiance to the Leidy, Pennsylvania hub.

On November 3, 1997, Viking Voyageur, a competitor to the Alliance Pipeline plan, officially filed a proposal for a $1.2 billion, 775-mile, 1.4 Bcf/d pipeline connecting Emerson, Manitoba via Wisconsin with Joliet, Illinois. Owners of Viking Voyageur include Northern States Power of Minneapolis, TransCanada Pipelines, and Nicor Inc. of Naperville, Illinois. Viking Voyageur is strongly supported by Wisconsin utilities, since the pipeline would pass through Wisconsin and allow for spurs and connections directly to the line. Given approval by the U.S Federal Energy Regulatory Commission (FERC), Viking Voyageur expects to begin construction in 1999, with gas delivery to begin late that year. TransCanada also has stated that it plans to build a new, higher-pressure pipeline, called TransVoyageur, from Saskatchewan to Manitoba. This 388-mile pipeline would move up to 2 Bcf/d of gas to Viking Voyageur.

NOVA Corp., Calgary (a major Canadian natural gas services and petrochemical company) has challenged the economics of the Alliance project, claiming that the Chicago market is already near saturation with gas from U.S. and Canadian pipelines. NOVA has its own plans to add 500 million cubic feet per day in capacity to its own system, to be connected to an expanded Northern Border pipeline. NOVA also argues that Alliance's pipeline plan would duplicate parts of NOVA's existing Alberta pipeline network, and that this would not be "in the economic interest of the Western Canadian sedimentary basin."

However these competing proposals are eventually sorted out, it appears highly likely that the result will be a huge increase in natural gas supplied to the Chicago area. Chicago is thus shaping up as a major supply hub of Canadian natural gas for the eastern United States. Currently, there are several pipeline proposals on the table to move gas east from Chicago. These include: IPL's 1 Bcf/d Vector Pipeline from Chicago to Michigan and onwards; the CMS Energy's TriState Pipeline, a 200 Mmcf/d which would compete directly with Vector; and the Columbia Gas Transmission's Millennium Pipeline, a 28-mile, 650 Mmcf/d line from the border at Lake Erie (another, 84-mile pipeline would then continue on across Lake Erie en route to New York City). TransCanada said in early September that it would take a 35% equity share in Vector, as well as an equity share in the Millennium pipeline project.

Competing pipeline proposals exist for natural gas from eastern Canada, as well. Montreal-based Gaz Metropolitain, along with IPL Energy, has proposed a $1.3 billion, 400 million cubic feet per day pipeline from the 3 Tcf gas field at Sable Island (located off the coast of Nova Scotia) to the U.S. Northeast. This pipeline would extend the TransQuebec and Maritimes (TQM) pipeline from Quebec City, and could be up and running by 1999. This could help make Quebec an eastern hub for Canadian gas exports, although several other provinces appear opposed to this idea. Currently, Sable Island's gas field is being developed by a rival consortium to IPL led by Mobil Oil Canada, which discovered Sable's gas fields in the 1970s, but did not develop them until now due to low gas prices and lack of market.

Mobil's consortium also has proposed an alternative pipeline plan -- the Maritimes & Northeast Pipeline MNE -- to TQM. Like TQM, the MNE plan would serve the U.S. New England market from Sable, but would take a more direct route bypassing Quebec. The $840 million MNE pipeline project is led by Mobil Oil Canada Inc. (which holds a 25% interest in the pipeline), along with Vancouver-based Westcoast Energy Inc. and PanEnergy Corp. Both TQM and MNE would deliver gas to a connection with the Portland Natural Gas Transmission System at a border point at East Hereford, Quebec.

One more proposal, a $3.5 billion plan to ship gas via a 1,570-mile regional pipeline from the Grand Banks via Sable to New Hampshire, has been made by Tatham Offshore Inc., Houston, and its wholly-owned subsidiary, North Atlantic Pipeline Partners. North Atlantic claims that its 3-phase plan would be the "least environmentally intrusive" of all the proposed projects "to tap the vast offshore Atlantic Canada gas reserves." North Atlantic also touts its ability to provide the integrated infrastructure system needed to serve both Canadian and U.S. markets well into the future. Finally, North Atlantic's plan would provide the Atlantic coast with access to gas in the Grand Banks (located off of Newfoundland), a reserve thought to be roughly equal to Sable Island.

Environmental considerations represent a possible obstacle to further development of gas reserves at Sable Island. Canadian environmentalists are concerned about Sable's proximity to The Gully, a vast undersea canyon rich in marine life, including a colony of rare bottlenose whales. World Wildlife Fund, Canada has been working for years to have the canyon designated a Marine Protected Area. Current plans for Sable Island involve development of only six out of about two-dozen gas fields. Mobil Oil, which is developing Sable, has expressed strong concerns that any delays for environmental or other reasons could jeopardize the economics of the project, which they hope to have up and running by November 1999.

In October 1997, the consortium led by Mobil Oil Canada threatened to abandon development at Sable Island in response to inaction by Canadian regulators. Shortly thereafter, on October 27, 1997, Canadian regulators recommended that approval be given to the Mobil consortium's plans, including its affiliated MNE pipeline plan bypassing Quebec. The decision on this highly politicized proposal by Canada's Joint Public Review Panel came after 56 days of public hearings in Halifax, Nova Scotia, as well as after review of thousands of pages of evidence. The recommendations must now be approved by Prime Minister Chretien's Cabinet and by Canada's National Energy Board. Previously, Prime Minister Chretien had stated his preference -- based largely on considerations of national unity -- for a pipeline route from Sable Island that runs through Quebec Province en route to New England.

Besides traditional energy-producing areas, Canada's National Energy Board has concluded that potentially large volumes -- up to 10.2 Tcf -- of undiscovered natural gas exist in the northern Yukon and Northwest Territories regions. As with oil, however, little exploration has been conducted in these areas to date. Despite this lack of exploration, significant amounts of natural gas is expected to be found in the Mackenzie Delta/Beaufort Sea basin and the Sverdup Sedimentary Basin of the Arctic Islands area. Currently, there is one natural gas pipeline located in far northern Canada -- the 250 million cubic-feet-per-day Pointed Mountain line, built in 1971-1972, running from an Amoco processing plant near Fort Liard to Fort Nelson, B.C.

A Canadian panel is considering the possibility of leasing Canada's portion of the George's Bank off southwestern Nova Scotia for oil and gas exploration. Under current law, a moratorium is in effect for such activities in the George's Bank until January 1, 2000. A review panel is currently conducting an environmental and socioeconomic impact study, with recommendations due by July 1, 1999 to Federal and Provincial authorities.

COAL
Canada is a major coal producer and consumer, with output in 1996 of about 84 million short tons (mmst), and consumption of 60 mmst. Canada also had net coal exports of 25 mmst in 1996, ranking it fourth in the world. About 80% of Canada's coal exports are metallurgical, with the vast majority purchased by Japan (54%) and South Korea (16%). Alberta accounts for about half of Canada's coal production, while British Columbia and Saskatchewan account for about 30% and 15%, respectively, of the total. Bituminous coal makes up about half of Canada's coal output, with sub-bituminous (about one-third) and lignite accounting for the rest. Canadian coal consumption is primarily (87%) burned in electricity generation, with the remainder mainly used for steelmaking.

ELECTRIC POWER
Canada generated 549 terawatthours (Twh) of electricity in 1996, with net exports of 38 Twh. Overall, about 64% of Canada's electricity in 1996 was generated by hydroelectric plants, 19% by coal, 16% by nuclear, and 1% by oil, gas, and other. Quebec and Ontario produce the most electricity (well over 50% of Canada's total electricity generation). Nearly 97% of Quebec's electricity generation derives from hydro plants, with the remaining 3% mainly produced by nuclear facilities. In contrast, about 56% of Ontario's electric power production derives from nuclear, 29% from hydro, and 14% from coal-fired plants.

The majority of Canada's electricity exports originate in the eastern provinces of Quebec, Ontario, and New Brunswick, and are sold to consumers in New England and New York. The western provinces of British Columbia and Manitoba also export large amounts of electricity, mainly to Washington state, Minnesota, California, and Oregon. Except for Alberta, all Canadian provinces bordering the United States have transmission links to neighboring U.S. systems.

In August 1997, Ontario Hydro -- one of the largest utilities in North America -- announced that it likely would be forced to shut down seven of its 19 operating reactors after an internal report concluded that poor management had compromised safety at the plants. To replace this lost capacity, Ontario Hydro may be forced to spend an extra $2.2 billion through 2001 to cover the increased costs of shifting to coal and oil generation. The company also may spend as much as $5.6 billion through 2001 to overhaul a dozen newer reactors which will continue to operate on the shores of Lakes Ontario and Huron. The reactors which would be shut down are all of the Candu model, an indigenous Canadian design that is the heart of Canada's nuclear program, as well as a major export to countries like Argentina, Romania, South Korea, and China.

In an important move towards deregulation, and as part of an effort to spur competition and exports of electric power to the United States, the government of Ontario is planning to allow competition in the province's electricity system, but is not planning to sell off assets of Ontario Hydro, according to a "White Paper" presented by provincial Energy Minister Jim Wilson. Wilson expects the provincial legislature to pass laws splitting Ontario Hydro into three "commercial," but government-owned, parts. These parts would include: 1) the company's 30,000-megawatts of fossil fuel, hydroelectric, and nuclear power electric generating capacity; 2) Ontario Hydro's 18,000-mile transmission grid; and 3) a new, government-run entity to oversee power distribution and help ensure that the market runs fairly for all producers. If the government plan goes ahead, competition for generation and retail activities is scheduled to begin after the year 2000. Ontario Hydro's huge, $22 billion debt, incurred largely as a consequence of heavy expenditures in the troubled nuclear sector, is to be held by a publicly-owned financial holding company.

Ontario's electricity deregulation plan represents part of an ambitious effort to integrate the Canadian and U.S. power grids into one competitive market. New U.S. rules now allow Canadian companies the opportunity to market directly to customers in the United States. Two Canadian electric utilities -- in Alberta and British Columbia -- already have been given permission by FERC to do so. Ontario Hydro and Quebec Hydro, however, have not to date been granted such permission by FERC due to fears that these companies' monopoly positions in Canada give them an unfair advantage over U.S. power producers.

ENVIRONMENT
Soon after his appointment in June 1997, Canada's new Natural Resources Minister, Ralph Goodale, reassured the oil and gas industries that he had no intention of introducing a carbon or Btu tax as part of any plan to help Canada meet its greenhouse gas emissions goals. This statement came only months before a United Nations Climate Summit (scheduled for December 1997) in Kyoto, Japan. The summit puts the spotlight on the failure to date of Canada's voluntary program to stabilize the country's greenhouse gas emissions. Canada is committed under the 1992 climate change convention signed in Rio de Janeiro to stabilize greenhouse gas emissions at 1990 levels by the year 2000. Despite this commitment, the United Nations secretariat has identified Canada, with its highly energy-intensive economy, as one of the largest world contributors to the growth in worldwide greenhouse gas emissions, particularly of methane and carbon dioxide, during the 1990s.

COUNTRY OVERVIEW
Prime Minister: Jean Chretien (since 11/4/93)
Independence: July 1, 1867 (from UK)
Population (1996E): 30.0 million
Location/Size: Northern North America/3.85 million sq. miles (slightly larger than United States)
Major Cities: Toronto, Montreal, Vancouver, Ottawa (capital), Edmonton, Calgary, Winnipeg, Quebec
Languages: English (official), French (official)
Ethnic Groups: British Isles origin (40%), French origin (27%), other European (20%), indigenous Indian, Eskimo (1.5%)
Religions: Roman Catholic (45%), Protestant (41%)
Defense (8/96): Army (21,500), Navy (9,500), Air Force (16,400), Unspecified (23,100)

ECONOMIC OVERVIEW
Currency: Canadian Dollar (Can$)
Exchange Rate (11/17/97): 1 Can$ = $0.706 U.S.
Gross Domestic Product (GDP), (1997E, $US): $615.9 billion
Real GDP Growth Rate (1997E): 3.6% (1998E): 3.3%
Inflation Rate (1997E): 1.7% (1998E): 1.4%
Unemployment Rate (1997E): 9.3% (1998E): 8.8%
Current Account Balance (1997E, $US): -$3.8 billion
(1998E, $US): $7.2 billion
Merchandise Exports (1997E, $US): $209.5 billion
Merchandise Imports (1997E, $US): $184.1 billion
Major Export Products: Newsprint; wood pulp; timber; crude oil; machinery; natural gas; aluminum; motor vehicles and parts; telecommunications equipment
Major Import Products: Crude oil; chemicals; motor vehicles and parts; durable consumer goods; computers; telecommunications equipment
Major Trading Partners: United States, Japan, United Kingdom

ENERGY OVERVIEW
Minister of Natural Resources: Ralph Goodale (replaced Anne McLellan in June 1997)
Proven Oil Reserves (1/1/97): 4.9 billion barrels
Oil Production (1H97E): 2.53 million barrels per day (bbl/d); of which 1.85 million bbl/d is crude oil
Oil Consumption (1H97E): 1.81 million bbl/d
Crude Refining Capacity (1/1/97): 1.9 million bbl/d
Net Oil Exports (1H97E): 0.72 million bbl/d
Natural Gas Reserves (1/1/97): 68.1 trillion cubic feet (Tcf)
Natural Gas Production (1996E): 5.85 Tcf
Natural Gas Consumption (1996E): 3.1 Tcf
Net Natural Gas Exports (1996E): 2.8 Tcf
Coal Reserves (12/93E): 9.5 billion short tons
Coal Production (1996E): 84 million short tons
Coal Consumption (1996E): 60 million short tons
Net Coal Exports (1996E): 25 million short tons
Electric Generation Capacity (1/1/96): 115 gigawatts
Electricity Generation (1996E): 549 terawatthours
Electricity Consumption (1996E): 511 terawatthours
Net Electricity Exports (1996E): 37.6 terawatthours

ENVIRONMENT OVERVIEW
Total Energy Consumption (1995E): 11.7 quadrillion Btu
Energy Consumption per 1987 Dollar of GDP (1995E): 24.6 thousand Btu (vs. U.S. average of 16.7 thousand Btu)
Energy Consumption per Capita (1995E): 395.9 million Btu (vs. U.S. average of 345.9 million Btu)
Energy-related Carbon Emissions (1995E): 132.4 million metric tons (2.2% of U.S. emissions)
Carbon Emissions per 1987 Dollar of GDP (1995E): 0.28 metric tons (vs. U.S. average of 0.26 metric tons)
Carbon Emissions per Capita (1995E): 4.5 metric tons (vs. U.S. average of 5.4 metric tons)
Major Environmental Issues: Canada ranks seventh among the world's industrialized countries in per capita production of solid wastes. Acid rain is a widespread problem, affecting many lakes and forests. Smelting of aluminum and other metals has resulted in release of pollutants. Canada pledged in 1992 to stabilize carbon emissions at 1990 levels by 2000. Note: Canada's relatively high energy use per dollar of output results largely from its reliance on energy-intensive industries based on the use of cheap and abundant hydroelectric power.

OIL and GAS INDUSTRIES
Organization: Generally private sector, although the Canadian government maintains a 20% share in PetroCanada -- far less than its formerly dominant 70% share -- in the company.
Major Oil and Gas Producing Provinces: Alberta; British Columbia; Saskatchewan
Major Oil Pipelines: Trans Mountain; Interprovincial
Major Oil Refining Provinces (Capacity): Ontario (545,300 bbl/d); Alberta (397,600); Quebec (364,800); New Brunswick (237,500 bbl/d)
Major Gas Pipeline Companies: IPL, TransCanada PipeLines Ltd., Calgary

Links to other sites:
1997 CIA World Factbook - Canada
U.S. International Trade Administration, Country Commercial Guide - Canada
U.S. International Trade Administration, Department of Commerce - Canada
U.S. Department of Energy's Office of Fossil Energy's International section - Canada
US Department of State Country Background Notes
Country Report on Economic Policy and Trade Practices - Canada (1996) - U.S. Department of State

The following links are provided solely as a service to our customers, and therefore should not be construed as advocating or reflecting any position of the Energy Information Administration (EIA) or the United States Government. In addition, EIA does not guarantee the content or accuracy of any information presented in linked sites.

National Energy Board of Canada
National Resources Canada's latest long-term energy outlook for Canada
US Embassy in Canada
Canadian Embassy in the United States

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File last modified: November 24, 1997

Contact:

Lowell Feld
lfeld@eia.doe.gov
Phone: (202)586-9502
Fax: (202)586-9753