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Last Updated: October 8, 2019
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Overview

  • Canada is one of the world’s top energy producers and is a principal source of U.S. energy imports.

  • Canada is a net exporter of most energy commodities and is a significant producer of natural gas, hydroelectricity, and crude oil and other liquids from oil sands. Energy exports to the United States account for most of Canada’s total energy exports.
  • Canada has abundant and varied natural resources, ranking fourth in 2018 among the top energy producers of petroleum and total liquids in the world, behind only the United States, Saudi Arabia, and Russia. Relatively energy intensive compared with other industrialized countries, Canada’s economy is fueled largely by petroleum and other liquids, natural gas, and hydroelectricity (Figure 1).

Figure 1. Total primary energy consumption in Canada by fuel type, 2018

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Petroleum and other liquids

Canada’s oil sands have significantly contributed to the recent and expected future growth in the world’s liquid fuel supply, and they comprise most of the country’s proved oil reserves, which rank third globally.

Reserves
  • The Oil & Gas Journal estimates that as of January 2019, Canada had 167 billion barrels of proved oil reserves, ranking third in the world.[1] Only Venezuela and Saudi Arabia hold higher reserves. In addition, Canada is one of only 3 countries among the top 10 proved reserves holders that is not a member of the Organization of the Petroleum Exporting Countries (OPEC).
Production and consumption
  • In 2018, Canada was the world’s fourth-largest petroleum and other liquids producer and was a net exporter of oil. Nearly all of its crude oil exports are destined for the United States because Canada lacks sufficient export capacity to send its liquids elsewhere.
  • Canada is a major producer of crude oil. Bitumen and upgraded synthetic crude oil produced from the oil sands of Alberta have driven recent growth in Canada’s liquid fuels production. Most of Canada’s proved oil reserves and the expected future growth in the country’s liquid fuels production will be derived from these resources.
  • Canada produced 5.3 million barrels per day (b/d) of petroleum and other liquid fuels in 2018, an increase of more than 300,000 b/d from the previous year. Crude oil (including condensate) accounted for 4.3 million b/d, and the remainder was produced as biofuels, natural gas, and other natural gas liquids (NGL) (Figure 2). Canada’s production is expected to grow modestly in 2019 and 2020 because of export capacity constraints and mandatory production curtailments set by the government of Alberta.

Figure 2. Canada liquid fuels production and consumption

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Refining
  • According to the Canadian Association for Petroleum Producers (CAPP), Canada has 17 refineries with a total crude oil processing capacity of 2.0 million b/d.[2] Eastern Canada’s eight refineries have 1.2 million b/d of capacity or about 60% of total crude oil refining capacity.[3] Because the eastern refineries are not as well connected to domestic crude oil production supplies, these refineries are more dependent on imported crude oil. Western Canada’s nine refineries have a total capacity of 748,000 b/d. In 2018, Phase One of the North West Redwater’s Sturgeon Refinery came online, which is the first refinery built in Canada since 1984.[4]
  • According to Natural Resources Canada, Canadian production of petroleum products reached 1.9 million b/d in 2018.[5] Most petroleum products are refined into motor gasoline (42%) and diesel fuel oil (30%).[6]
Exports and imports
  • Nearly all of Canada’s crude oil exports were sent to the United States in 2018 (see Figure 3). Currently, the largest regional market in the United States for Canadian crude oil exports is the Midwest where almost all Canadian crude oil exports originate from Western Canada.
  • Canada is the largest source of U.S. crude oil and refined products imports. Crude oil imports from Canada accounted for 48% of total U.S. crude oil imports in 2018, averaging 3.7 million b/d. Refined products imported from Canada accounted for 582,000 b/d, or 27% of total U.S. petroleum product imports.
  • Currently, producers face a complex set of market and logistical challenges. Oil supply in Western Canada exceeds the transport capacity of pipelines serving external markets. As export pipelines operate at full capacity and timing of new capacity remains uncertain, producers are increasingly relying on rail transportation to deliver incremental production to the market. The highest monthly volume imported to the United States from Canada was in January 2019 at 406,000 b/d, compared with a total average of 238,000 b/d in 2018.

Figure 3. Canada crude oil exports by destination, 2018

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Natural gas

Canada is one of the world’s largest producers of dry natural gas and is the source of most U.S. natural gas imports.

Reserves
  • The Oil & Gas Journal,[7] Canada held 72 trillion cubic feet (Tcf) of proved natural gas reserves at the end of 2018. Most of Canada’s natural gas reserves are traditional resources in the Western Canadian Sedimentary Basin (WCSB), including those associated with the region’s oil fields. Other areas with significant natural gas reserves include offshore fields near the eastern shore of Canada (primarily Newfoundland and Nova Scotia), the Arctic region, and the Pacific coast.
Production and consumption
  • In 2018, Canada produced 5.9 Tcf of dry natural gas and was the fourth-largest producer behind the United States, Russia, and Iran (see Figure 4). Most of Canada’s natural gas production occurs in the prolific WCSB. Although Canadian production of conventional natural gas has been declining, the production of Canadian unconventional natural gas has been rising.
Exports
  • Almost all of Canada’s natural gas exports go to the United States. In 2018, 97% of all U.S. natural gas imports came from Canada. Most of Canada’s natural gas exports to the United States originate in Western Canada and are shipped to U.S. markets in the West and Midwest regions.

Figure 4. Canada's dry natural gas production and consumption

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Electricity
  • Canada generated an estimated 651 billion kilowatthours (kWh) of electricity in 2017, of which about 60% was hydroelectric. Only China and Brazil produce more hydroelectricity than Canada.[8] Fossil fuel and nuclear plants satisfy most of Canada’s electricity needs not met by hydroelectricity (see Figure 5).
Trade
  • The United States imported 52 million megawatthours (MWh) of electricity from Canada in 2018, primarily into the Northeast and Midwest, and exported 73 million MWh, nearly all of which was from the Pacific Northwest. Canada is a net exporter of electricity to the United States, which accounts for a small, although locally important, share of bilateral trade.

Figure 5. Electricity generation by fuel, 2018

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Coal

As government policy attempts to lower domestic coal consumption, up to 50% of Canada’s coal production is exported.

Reserves
  • Canada’s total proved coal reserves stood at about 6.6 billion short tons in 2018.[9] More than 60% of the reserves are anthracite and bituminous coal. The remaining reserves are subbituminous and lignite coal.[10] Coal resources are located across the country, but they are actively mined and produced in only Alberta, British Columbia, and Saskatchewan.
Production and consumption
  • In 2017, Canada produced 68 million short tons of coal, a slight increase compared with the previous year. About 50% of Canada’s coal production is consumed domestically, a significant departure from more than a decade ago when Canada consumed nearly all of its domestic coal production.
  • In 2018, 49% of coal consumed in Canada was metallurgical coal used for steel manufacturing, and 51% was thermal coal used for electricity generation. Coal generates 9% of total electricity in Canada. In 2018, the government of Canada announced regulations to phase out traditional coal-fired electricity by 2030.[11]
Trade
  • Canada exports about half of its coal production. In 2018, Canada was the world's third-largest exporter of metallurgical coal after Australia and the United States. [12] Most of Canada's coal exports go to Asia.

Canada EIA petroleum Reserves production consumption refining exports imports natural gas electricity coal
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Short-Term Energy Outlook

Highlights  

Global liquid fuels

  • Brent crude oil spot prices averaged $60 per barrel (b) in October, down $3/b from September and down $21/b from October 2018. EIA forecasts Brent spot prices will average $60/b in 2020, down from a 2019 average of $64/b. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020. EIA expects crude oil prices will be lower on average in 2020 than in 2019 because of forecast rising global oil inventories, particularly in the first half of next year.
  • Based on preliminary data and model estimates, EIA estimates that the United States exported 140,000 b/d more total crude oil and petroleum products in September than it imported; total exports exceeded imports by 550,000 b/d in October. If confirmed in survey-collected monthly data, it would be the first time the United States exported more petroleum than it imported since EIA records began in 1949. EIA expects total crude oil and petroleum net exports to average 750,000 b/d in 2020 compared with average net imports of 520,000 b/d in 2019.
  • Distillate fuel inventories (a category that includes home heating oil) in the U.S. East Coast—Petroleum Administration for Defense District (PADD 1)—totaled 36.6 million barrels at the end of October, which was 30% lower than the five-year (2014–18) average for the end of October. The declining inventories largely reflect low U.S. refinery runs during October and low distillate fuel imports to the East Coast. EIA does not forecast regional distillate prices, but low inventories could put upward pressure on East Coast distillate fuel prices, including home heating oil, in the coming weeks.
  • U.S. regular gasoline retail prices averaged $2.63 per gallon (gal) in October, up 3 cents/gal from September and 11 cents/gal higher than forecast in last month’s STEO. Average U.S. regular gasoline retail prices were higher than expected, in large part, because of ongoing issues from refinery outages in California. EIA forecasts that regular gasoline prices on the West Coast (PADD 5), a region that includes California, will fall as the issues begin to resolve. EIA expects that prices in the region will average $3.44/gal in November and $3.12/gal in December. For the U.S. national average, EIA expects regular gasoline retail prices to average $2.65/gal in November and fall to $2.50/gal in December. EIA forecasts that the annual average price in 2020 will be $2.62/gal.
  • Despite low distillate fuel inventories, EIA expects that average household expenditures for home heating oil will decrease this winter. This forecast largely reflects warmer temperatures than last winter for the entire October–March period, and retail heating oil prices are expected to be unchanged compared with last winter. For households that heat with propane, EIA forecasts that expenditures will fall by 15% from last winter because of milder temperatures and lower propane prices.


Natural gas

  • Natural gas storage injections in the United States outpaced the previous five-year (2014–18) average during the 2019 injection season as a result of rising natural gas production. At the beginning of April, when the injection season started, working inventories were 28% lower than the five-year average for the same period. By October 31, U.S. total working gas inventories reached 3,762 billion cubic feet (Bcf), which was 1% higher than the five-year average and 16% higher than a year ago.
  • EIA expects natural gas storage withdrawals to total 1.9 trillion cubic feet (Tcf) between the end of October and the end of March, which is less than the previous five-year average winter withdrawal. Withdrawal of this amount would leave end-of-March inventories at almost 1.9 Tcf, 9% higher than the five-year average.
  • The Henry Hub natural gas spot price averaged $2.33 per million British thermal units (MMBtu) in October, down 23 cents/MMBtu from September. The decline largely reflected strong inventory injections. However, forecast cold temperatures across much of the country caused prices to rise in early November, and EIA forecasts Henry Hub prices to average $2.73/MMBtu for the final two months of 2019. EIA forecasts Henry Hub spot prices to average $2.48/MMBtu in 2020, down 13 cents/MMBtu from the 2019 average. Lower forecast prices in 2020 reflect a decline in U.S. natural gas demand and slowing U.S. natural gas export growth, allowing inventories to remain higher than the five-year average during the year even as natural gas production growth is forecast to slow.
  • EIA forecasts that annual U.S. dry natural gas production will average 92.1 billion cubic feet per day (Bcf/d) in 2019, up 10% from 2018. EIA expects that natural gas production will grow much less in 2020 because of the lag between changes in price and changes in future drilling activity, with low prices in the third quarter of 2019 reducing natural gas-directed drilling in the first half of 2020. EIA forecasts natural gas production in 2020 will average 94.9 Bcf/d.
  • EIA expects U.S. liquefied natural gas (LNG) exports to average 4.7 Bcf/d in 2019 and 6.4 Bcf/d in 2020 as three new liquefaction projects come online. In 2019, three new liquefaction facilities—Cameron LNG, Freeport LNG, and Elba Island LNG—commissioned their first trains. Natural gas deliveries to LNG projects set a new record in July, averaging 6.0 Bcf/d, and increased further to 6.6 Bcf/d in October, when new trains at Cameron and Freeport began ramping up. Cameron LNG exported its first cargo in May, Corpus Christi LNG’s newly commissioned Train 2 in July, and Freeport in September. Elba Island plans to ship its first export cargo by the end of this year. In 2020, Cameron, Freeport, and Elba Island expect to place their remaining trains in service, bringing the total U.S. LNG export capacity to 8.9 Bcf/d by the end of the year.


Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts the share of U.S. electric generation from coal to average 25% in 2019 and 22% in 2020, down from 28% in 2018. EIA’s forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, down from almost 8% in 2018. Wind, solar, and other nonhydropower renewables provided 9% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects total U.S. coal production in 2019 to total 698 million short tons (MMst), an 8% decrease from the 2018 level of 756 MMst. The decline reflects lower demand for coal in the U.S. electric power sector and reduced competitiveness of U.S. exports in the global market. EIA expects U.S. steam coal exports to face increasing competition from Eastern European sources, and that Russia will fill a growing share of steam coal trade, causing U.S. coal exports to fall in 2020. EIA forecasts that coal production in 2020 will total 607 MMst.
  • EIA expects U.S. electric power sector generation from renewables other than hydropower—principally wind and solar—to grow from 408 billion kilowatthours (kWh) in 2019 to 466 billion kWh in 2020. In EIA’s forecast, Texas accounts for 19% of the U.S. nonhydropower renewables generation in 2019 and 22% in 2020. California’s forecast share of nonhydropower renewables generation falls from 15% in 2019 to 14% in 2020. EIA expects that the Midwest and Central power regions will see shares in the 16% to 18% range for 2019 and 2020.
  • EIA forecasts that, after rising by 2.7% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.7% in 2019 and by 2.0% in 2020, partially as a result of lower forecast energy consumption. In 2019, EIA forecasts less demand for space cooling because of cooler summer months; an expected 5% decline in cooling degree days from 2018, when it was significantly higher than the previous 10-year (2008–17) average. In addition, EIA also expects U.S. CO2 emissions in 2019 to decline because the forecast share of electricity generated from natural gas and renewables will increase, and the share generated from coal, which is a more carbon-intensive energy source, will decrease.
November, 14 2019
The U.S. placed near-record volumes of natural gas in storage this injection season

The amount of natural gas held in storage in 2019 went from a relatively low value of 1,155 billion cubic feet (Bcf) at the beginning of April to 3,724 Bcf at the end of October because of near-record injection activity during the natural gas injection, or refill, season (April 1–October 31). Inventories as of October 31 were 37 Bcf higher than the previous five-year end-of-October average, according to interpolated values in the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report.

Although the end of the natural gas storage injection season is traditionally defined as October 31, injections often occur in November. Working natural gas stocks ended the previous heating season at 1,155 Bcf on March 31, 2019—the second-lowest level for that time of year since 2004. The 2019 injection season included several weeks with relatively high injections: weekly changes exceeded 100 Bcf nine times in 2019. Certain weeks in April, June, and September were the highest weekly net injections in those months since at least 2010.

weekly net changes in natural gas storage

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report

From April 1 through October 31, 2019, more than 2,569 Bcf of natural gas was placed into storage in the Lower 48 states. This volume was the second-highest net injected volume for the injection season, falling short of the record 2,727 Bcf injected during the 2014 injection season. In 2014, a particularly cold winter left natural gas inventories in the Lower 48 states at 837 Bcf—the lowest level for that time of year since 2003.

November, 11 2019
Your Weekly Update: 4 - 8 November 2019

Market Watch  

Headline crude prices for the week beginning 4 November 2019 – Brent: US$62/b; WTI: US$56/b

  • Good broader economic data helped push crude prices up, as better-than-expected US job numbers and a big uptick in Chinese manufacturing orders allayed some fears over the health of the global economy
  • Those worries still persist, but the upbeat data does show that the slowdown might not be prolonged, especially if the US and China manage to hammer out a comprehensive trade deal that White House officials have hinted is in the works
  • The USA, under Trump, has formally withdrawn from the Paris climate accord, placing the USA as one of only 3 countries not to be a party to the comprehensive collection of emission reductions by country
  • OPEC production rebounded to 29.7 mmb/d in October, recovering from the 1.23 mmb/d drop in September caused by the attacks on Saudi crude facilities
  • Having recently lost Qatar and Ecuador, OPEC – via Saudi Arabia – has reportedly informally reached out to Brazil to join the oil club, highlighting the growing importance of Brazilian output; President Jair Bolsonaro has indicated that he would be ‘eager to accept’ the offer
  • Ahead of the OPEC meeting in Vienna on 5-7 December, Saudi Aramco is now scheduled for public listing on the Saudi stock exchange on December 11; this might lead to a push for a deeper or longer tenure for the current supply deal at the Vienna meeting, as Aramco seeks to bolster its valuation
  • The massacre in onshore drilling countries in the US, as the Baker Hughes index indicates that five oil and three gas rigs were dropped last week for a net loss of 8 and a total of 822, as bankruptcies increase in major shale areas
  • There isn’t much room for crude prices to grow in the current environment; indeed, prices are likely to trade with a downward bias at US$58-60/b for Brent and US$53-55/bd for WTI

Headlines of the week

Upstream

  • Total has chosen to sell off its 86.95% stake in Brunei’s offshore Block CA1 to Shell for some US$300 million in line with its global non-core asset divestment
  • Myanmar’s delayed upstream licensing round has now been set for early 2020, with the government aiming to pass a draft oil and gas bill before moving ahead
  • Apache expects to bring two ‘high volume’ wells in the North Sea online over the next two months, with Storr operating by November and Garten by the end of the year, which could double its current 54,000 b/d North Sea output
  • A new offshore oil discovery has been announced in Equatorial Guinea by Kosmos Energy, with the S-5 well in the Rio Muni Basin yielding crude flows

Midstream/Downstream

  • ExxonMobil has put its refinery in Billings, Montana up for sale once again, looking to fetch US$500 million for the 60 kb/d plant, with interested buyers including Valero and Marathon
  • Russia is moving ahead with settling the cases of contaminated crude oil transported via its Druzhba pipeline; Lukoil and Hungary’s MOL have signed a settlement deal, while Total has opted to sell its 720,000-barrel cargo on the open market at a discount of over US$25/b
  • Saudi Aramco may be gaining a bigger foothold in Africa, as NNPC announced plans to collaborate with the Saudi oil firm to revamp Nigeria’s four ailing state refineries that are buckling from age
  • Marathon has folded under pressure from activist investors, announcing that it will be spinning off its fuel retail business while also reviewing a future possibility to spin off its pipeline business as well
  • ALFA Mexico’s petchems subsidiary Alpek has agreed to acquire PET manufacturer Lotte Chemical UK from South Korea’s Lotte Chemical
  • Kuwait Petroleum has started up the 2,264 b/d LPG processing plant at its Mina al-Ahmedi refinery, focusing on delivering LPG for petchems usage

Natural Gas/LNG

  • Kosmos Energy has announced a ‘major’ gas discovery in Mauritania at its Orca-1 well; combined with the Marsouin-1 discovery in the BirAllah, Orca-1 is the largest deepwater oil and gas discovery so far in 2019 and could underpin standalone LNG development in the West African nation
  • BP has announced it is on track to start production from the deepwater Raven field in Egypt by end-2019 – the third stage of its West Nile Delta project that also encompasses the producing Giza and Fayoum developments
  • Denmark’s state energy regulator has given permission for the controversial Nord Stream 2 pipeline to be built in its waters to connect Russia to Germany
  • Plans to expand the Sakhalin-2 LNG plant in Russia’s far east have been put on hold, reportedly due to a lack of gas resources and international sanctions in place, with Gazprom also looking to pipe gas to China instead of liquefying
  • Cheniere expects its Corpus Christi LNG Train 3 in Texas to start-up ahead of its previous timeline of 2H2021, while also expecting to begin operations at the Sabine Pass LNG Train 6 in Louisiana by 1H2023
  • Turkey’s state energy firm Botas is accepting tenders for up to 70 cargoes of LNG for delivery over 2020-2023, as it aims to diversify its gas sources
  • Sempra Energy and Japan’s Mitsui & Co have signed a new MoU to collaborate on more LNG projects, including the Cameron LNG Phase 2 and the future expansion of the Energia Costa Azul project in Baja California
November, 08 2019