January 2015 CERI Commodity Report — Crude Oil Relevant • Independent • Objecve CERI Commodity Report – Crude Oil Editor-in-Chief: Dinara Millington ([email protected]) About CERI The Canadian Energy Research Instute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant, independent, objecve economic research in energy and related environmental issues. We strive to build bridges between scholarship and policy, combining the insights of scienfic research, economic analysis, and praccal experience. For more informaon about CERI, please visit our website at www.ceri.ca. of bitumen producon was upgraded into SCO. Canadian producers like Syncrude and Suncor, which built upgraders and refineries in tandem with rising oil sands producon, produce substanal quanes of SCO, which sells at near parity with Brent benchmark oil. But new construcon of tradional refineries and upgraders, however, is nearly impossible today. 5 These massive plants are economical only on a large scale, requiring billions of dollars and years to construct and ramp up to full capacity. A typical upgrader carries a capital cost of about $8-10 billion. Environmental perming, market volality, and a low rate of return also have complicated the prospects of construcng mega-projects in the form of upgraders. For example, despite years of planning and preparaon, Suncor decided to scrap its Voyageur upgrader, taking a $1.68 billion write-down instead. The need for increased investment in new upgrading technology has intensified over the past 10 years by enhanced environmental protecons, which have made historical soluons for convenonal upgrading (such as building addional upgrader/refineries and pipelines) impossible, impraccal, or prohibively expensive. That is why the convenonal soluon to the diluent and transportaon problem is geng no tracon. While the US and Canadian industries would like to expand the network and capacies of current pipeline systems, environmental concerns have sparked fierce public and polical opposion to these proposed projects, such as the Keystone XL, in both countries, leading to indefinite delays in perming, construcon, and commissioning projects. Emerging Technologies High oil prices, environmental regulaons, industry and government R&D efforts have smulated investments in more cost-effecve upgrading technologies. The goal has been a soluon that would yield processed bitumen to meet pipeline specificaons of API gravity of 18-20° and viscosity of 350 cst at the pipeline reference temperature, a product that is not quite as light as SCO, but doesn’t require diluent to flow in the pipe, also known as paral upgrading. New Upgrading Technology Holds Promise Pipeline Transportaon and Diluent Use Dinara Millington It is a well-known fact that oil sands bitumen in its raw form cannot be transported via pipeline and requires a diluent to meet the pipeline specificaons. 1 Diluted bitumen for export, or dilbit, contains approximately 30- 40 percent diluent, which while facilitang transportaon creates addional load on the already strained infrastructure by consuming valuable pipeline space as well as requiring extra trucks and railroad cars. The available pipeline capacity has been shrinking in the last few years. Increased producon from oil sands has resulted in nearly full ulizaon of all available export pipelines and created strong demand for rail transportaon to deliver producon from Canada to US markets. While Alberta's bitumen producon is abundant, only a limited quanty reaches the US economically. Western Canadian Select (WCS) benchmark blend, 2 sells at a steep discount to West Texas Intermediate (WTI) at Edmonton on a FOB basis, with the discount disappearing when the commodity reaches US Gulf Coast refineries because of higher dilbit transportaon costs due to limited capacies along North American pipelines. The WCS/WTI discount, then, addionally lowers oil sands producer netbacks that already suffer from high diluent costs 3 and transportaon costs. 4 Tradional Soluons One soluon to the diluent problem has been construcon of addional upgrading in Canada to convert heavy, sour, and highly viscous bitumen into light, sweet synthec crude oil (SCO). Before 2012, half
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January 2015
CERI Commodity Report — Crude Oil
Relevant • Independent • Objective
CERI Commodity Report – Crude Oil Editor-in-Chief: Dinara Millington ([email protected]) About CERI The Canadian Energy Research Institute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant, independent, objective economic research in energy and related environmental issues. We strive to build bridges between scholarship and policy, combining the insights of scientific research, economic analysis, and practical experience. For more information about CERI, please visit our website at www.ceri.ca.
of bitumen production was upgraded into SCO. Canadian producers like Syncrude and Suncor, which built upgraders and refineries in tandem with rising oil sands production, produce substantial quantities of SCO, which sells at near parity with Brent benchmark oil. But new construction of traditional refineries and upgraders, however, is nearly impossible today.5 These massive plants are economical only on a large scale, requiring billions of dollars and years to construct and ramp up to full capacity. A typical upgrader carries a capital cost of about $8-10 billion. Environmental permitting, market volatility, and a low rate of return also have complicated the prospects of constructing mega-projects in the form of upgraders. For example, despite years of planning and preparation, Suncor decided to scrap its Voyageur upgrader, taking a $1.68 billion write-down instead. The need for increased investment in new upgrading technology has intensified over the past 10 years by enhanced environmental protections, which have made historical solutions for conventional upgrading (such as building additional upgrader/refineries and pipelines) impossible, impractical, or prohibitively expensive. That is why the conventional solution to the diluent and transportation problem is getting no traction. While the US and Canadian industries would like to expand the network and capacities of current pipeline systems, environmental concerns have sparked fierce public and political opposition to these proposed projects, such as the Keystone XL, in both countries, leading to indefinite delays in permitting, construction, and commissioning projects. Emerging Technologies High oil prices, environmental regulations, industry and government R&D efforts have stimulated investments in more cost-effective upgrading technologies. The goal has been a solution that would yield processed bitumen to meet pipeline specifications of API gravity of 18-20° and viscosity of 350 cst at the pipeline reference temperature, a product that is not quite as light as SCO, but doesn’t require diluent to flow in the pipe, also known as partial upgrading.
New Upgrading Technology Holds Promise Pipeline Transportation and Diluent Use Dinara Millington It is a well-known fact that oil sands bitumen in its raw form cannot be transported via pipeline and requires a diluent to meet the pipeline specifications.1 Diluted bitumen for export, or dilbit, contains approximately 30- 40 percent diluent, which while facilitating transportation creates additional load on the already strained infrastructure by consuming valuable pipeline space as well as requiring extra trucks and railroad cars. The available pipeline capacity has been shrinking in the last few years. Increased production from oil sands has resulted in nearly full utilization of all available export pipelines and created strong demand for rail transportation to deliver production from Canada to US markets. While Alberta's bitumen production is abundant, only a limited quantity reaches the US economically. Western Canadian Select (WCS) benchmark blend,2 sells at a steep discount to West Texas Intermediate (WTI) at Edmonton on a FOB basis, with the discount disappearing when the commodity reaches US Gulf Coast refineries because of higher dilbit transportation costs due to limited capacities along North American pipelines. The WCS/WTI discount, then, additionally lowers oil sands producer netbacks that already suffer from high diluent costs3 and transportation costs.4 Traditional Solutions One solution to the diluent problem has been construction of additional upgrading in Canada to convert heavy, sour, and highly viscous bitumen into light, sweet synthetic crude oil (SCO). Before 2012, half
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As a result, such companies as Ivanhoe Energy Inc., MEG Energy Corp., Western Research Institute (WRI), Value Creation Inc., Fractal Systems Inc., Field Upgrading Ltd., Petrosonic Energy Inc., and others offer a variety of upgrading technologies that largely can be classified into two categories: coking-thermal cracking (Ivanhoe’s HTL, MEG’s Hi-Q, WRI’s WRITE) and solvent deasphalting (Petrosonic). To date, only MEG and Value Creation have applied for field pilots, with the earliest pilot installation expected to be operational by 2016-2017. The rest exist in demonstration plants or limited field tests. Outside of the two categories there is also the molten sodium upgrading technology by Field Upgrading, cavitation-based JetShear technology by Fractal, and Superior Upgrading Technologies' (SUT) Hammer Technology (HT),6 of which the latter two can be broadly described as "cavitation technologies."7 All these technologies’ capital costs vary between $10,000-$30,000 per barrel per day of capacity; operating costs of $2-$6/barrel; and a proposed plant capacity of 3,000-10,000 b/d. SUT’s HT Technology SUT has developed a simplified, partial upgrading technology for bitumen that reduces the required volume of diluent for pipeline transportation, expedites the commodity's arrival to market, and lowers both capital and operating costs. Instead of using a more traditional, energy-intensive process that requires hydro-treating as well as sulfur and coke remediation to increase unprocessed bitumen's API gravity by 10 degrees to 18-20° API, SUT's HT implements an upgrading process that reduces viscosity by 50-85 percent and is accompanied by an API gravity increase of 1-4°.8 With SUT's HT upgrading process, there is no product loss, no incondensable gas formation, and very limited olefin production. In a typical thermal process, molecules collide randomly in a three-dimensional space. Some molecular collisions are energetic enough to break or form bonds. Thermal energy input, therefore, is the root of conventional petroleum chemistry, in which heat is added to large volumes of feedstock to force thermal (or catalytic) cracking of hydrocarbons. By contrast, instead of relying on high temperatures to promote energetic molecular collisions, SUT's HT creates high-velocity fluid streams
that break chemical bonds at near-ambient conditions, in which molecular motion is confined to one dimension and molecules collide head-on in an organized manner. Figure 1 illustrates how SUT’s HT process compares to a thermal process. Upgrading bitumen with SUT’s HT creates a partially upgraded product because the process occurs only in "hot spots" where the fluid streams collide and hence the depth of upgrading is not as large as in the conventional thermal process. The advantage is the design complexity of the process drops several levels of magnitude, as does energy use because the bulk of liquid remains at ambient temperature and pressure. As a result of SUT HT's relatively low process temperature, formation of coke, gas, and olefins also is negligible. Developed after two years of research, SUT HT provides bitumen upgrading that, in addition to its capability for deployment at wellheads, can be aggregated into a larger installation of 100-100,000 bbl/d at a construction cost of less than $2,000/bbl and an operating cost of less than $1-2/bbl.9
Figure 1: SUT’s HT Technology
Source: Oil & Gas Journal To validate the HT process, SUT constructed a 100 bbl/d demonstration plant in Bellefonte, Pennsylvania (see Figure 2 for the plant’s schematic), and tested it on bitumen and atmospheric residue.10
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Figure 2: SUT’s HT Schematic
The results established a typical performance of the SUT HT upgrading process for bitumen and residue: A 1-2° increase in API gravity. A 50-80% reduction in viscosity. Unchanged asphaltenes content. A slight increase (0.3%) in olefins. A 5-10% increase in distillation yields (mostly due to
gasoline and diesel fractions). It takes about 15 minutes to process 1.3 bbl of material, consuming a total of 25 kWh of power. This gives the performance of approximately 100 bbl/d and the energy use of 70 MJ/bbl, which translates into about $1/bbl assuming the $0.06/kwh power cost. This compares favourably against the cost of the conventional thermal process of cracking or hydro-treating. What remains to be seen are the results from field testing for this promising technology. Small-scale field testing on a 100-1,000 bbl/d bitumen project can help build a case for commercial application of the technology as well as reveal any potential problems. Endnotes 1API gravity of 18-20° and viscosity of 350 cst at the pipeline reference temperature. 2It is a heavy blended crude oil composed mostly of bitumen blended with sweet synthetic and condensate diluents and 25 existing streams of both conventional and unconventional Alberta heavy crude oils at the Husky blending terminal in Hardisty, Alberta. WCS was launched in December 2004 as a new heavy oil stream by Cenovus (then EnCana), Canadian Natural Resources Limited, Suncor (then Petro-Canada) and Talisman Energy Inc. who continue to produce it exclusively.
3Diluent sells at a 5-7% premium to WTI oil price. 4There is no direct pipeline link from Alberta to the Gulf refining sector; hence the transportation cost between the two locations is based on the current rail transport rate of around $18/barrel of dilbit. 5In 2017-2018 additional refining capacity will be added with the construction of the Northwest Upgrader with a total capacity of 150,000 b/d. 6Under the right conditions sound in liquids leads to cavitation - the process of intense bubble formation. When the cavitation bubbles collapse they act as enormous energy concentrators generating temperatures and pressures exceeding those found on the surface of the sun. Hammer Technology™ takes hydrodynamic cavitation to the new level by creating macroscopic fluid hammer events and colliding fluid streams that break molecular bonds and accelerate chemical reactions. 7A detailed review of these and other technologies can be found at: Castaneda, L., et. al., “Current situation of merging technologies for upgrading of heavy oils”. Catalysis Today, 220-222. 2014. 8Superior Upgrading Technologies. http://www.superiorupgrading.com/technology.shtml 9O&G Journal. “Novel upgrading technology cuts diluent use, capital costs”. February 2, 2015. 10The demonstration plant has air tight, all-stainless, closed-loop design and was pressure-tested to 80 psi. The SUT HT reactor is powered by a three-phase, 100 hp (75 kw) electric motor, controlled via a variable frequency drive (VFD) with power metering capability. To test bitumen at the plant, WCS crude oil was purchased from United Refinery Group, Warren, Pa. Prior to processing, diluent was removed by vacuum distillation. The crude oil storage tank was heated to 80° C, and diluent vapour was removed by a vacuum pump. A small portion of diluent remained in the blend after distillation, which resulted in the dilbit's slightly higher API gravity of 13° and lower viscosity when compared with raw bitumen (typical gravity of 10°). Atmospheric residue was obtained from the American Refining Group, Bradford, Pa., and corresponded to "cylinder stock". This material contained no diluent and had an initial boiling point of 400° C. The same testing method was used for both the bitumen and residue. Before treatment, the oil was preheated to the process temperature of 100°C by circulating via the feed pump through the Sterling hot oil heater and back into the feed tank using the preheat bypass. The raw sample was obtained from the feed tank. The feed tank's pressure remained at 0 psig throughout preheating. For treatment, the heater was turned off, the preheat bypass was closed, and power was supplied to the SUT HT reactor and water to the cooler. The flow rate was set to 3 gpm, and the pressure within the reactor was measured at 145 psig. The treatment process lasted about 15 minutes consuming 25 kWh of power according to the VFD. At the end of the treatment, the oil temperature in the feed tank was 200° C, and the pressure in the feed tank was 10-20 psig (due to light hydrocarbons produced during the treatment). Next, the oil was cooled by cycling it through the reactor and the cooler at 30 gpm by way of the feed pump. (The reactor was powered down and not restricting the flow.) After about 45 minutes, the oil was cooled to 50° C, and the feed tank pressure returned to 0 psig, indicating that all volatile hydrocarbons condensed back into liquid form and mixed with the oil. As a result, no incondensable gases remained that could be registered on the pressure gauge. At this point, an upgraded sample of oil was obtained from the feed tank.
Low Price Case 43.56 40.80 43.35 44.20 45.90 48.45
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Data Appendix
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A1: Historic Light Sweet Crude Futures Prices ($US per barrel)
A2: Historic Crude Product Futures Prices (¢US per gallon)
Notes (Tables A1 and A2): Prices are listed by contract month. Close: final contract close on the last day of trading. Last 3 Day Average Close: simple average con-
tract close on last three days of trading. Average When Near Month: simple average closing price on trading days when contract was near month. 12-Month Strip
Average: simple average of daily near 12-month contract closing prices in a given contract month. Spread: difference between one-month and two-month forward
prices in a given period. Source: New York Mercantile Exchange (NYMEX).
NYMEX Light Sweet Crude
Last 3 Day Avg. When 12-Month Spread
Close Average Near Mo. Strip Avg. (1-2 Mo.)
2012 94.86 95.15 95.30 96.89 -0.35
2013 96.82 97.37 97.01 97.45 -0.12
2014 96.53 96.37 96.73 87.56 0.54
4Q 2013 98.60 99.63 101.59 101.06 0.16
1Q 2014 98.89 98.13 96.84 64.89 0.03
2Q 2014 101.33 101.93 101.28 99.77 0.69
3Q 2014 102.58 102.08 102.22 99.28 0.90
4Q 2014 83.30 83.34 86.59 86.30 0.56
Yr-on-Yr Chg. -15.5% -16.4% -14.8% -14.6%
Feb-14 94.99 94.44 95.51 -0.14 -0.14
Mar-14 102.92 102.01 98.82 97.82 0.48
Apr-14 99.43 99.83 101.10 99.83 0.63
May-14 102.13 103.60 101.82 100.37 0.77
Jun-14 102.44 102.36 100.91 99.10 0.68
Jul-14 107.26 106.55 104.44 102.90 0.71
Aug-14 104.42 104.05 103.81 97.86 0.73
Sep-14 96.07 95.65 98.42 97.09 1.27
Oct-14 91.52 92.33 93.49 92.94 0.78
Nov-14 82.81 82.76 87.91 87.10 0.81
Dec-14 75.58 74.92 78.37 78.87 0.10
Jan-15 56.52 55.70 64.33 65.55 -0.19
Feb-15 46.39 47.11 50.64 52.78 -0.45
Yr-on-Yr Chg. -51.2% -50.1% -47.0% -39054.4%
NYMEX Unleaded Gasoline NYMEX Heating Oil
Last 3 Day Avg. When 12-Month Spread Last 3 Day Avg. When 12-Month Spread
Close Average Near Mo. Strip Avg. (1-2 Mo.) Close Average Near Mo. Strip Avg. (1-2 Mo.)
A3: World Crude Oil Contract Prices (FOB, $US per barrel)
A4: North American Posted Crude Prices (FOB, $US per barrel)
Notes: 1. ANS is Delivered price on US West Coast. 2. Edmonton Light Sweet prices are discontinued as of May 1, 2014 and replaced by the Canadian Light Crude
blend which is traded daily on the Net Energy Index. 3. Hardisty Heavy. Posted prices are based on price at the end of each month. Sources: Oil & Gas Journal;
Natural Resources Canada.
Notes: 1. Urals is Delivered price at Mediterranean. Contract prices are based on prices at the end of each month. Source: OPEC Monthly Oil Market Report.
Saudi U.A.E. Oman U.K. Norway Russia Venez. Kuwait Ecuador Mexico Nigeria Indon.
Arab Lgt Dubai Oman Brent Ekofisk Urals1 T.J. Light Blend Oriente Isthmus Bonny Lgt Minas
A5: Crude Oil Quality Differentials (FOB, $US per barrel)
A6: Crude Oil Spot Prices and Differentials (FOB, $US per barrel)
Notes: 1. OPEC-Reference Basket is average price of seven crude streams: Algeria Saharan Blend, Dubai Fateh, Indonesia Minas, Mexico Isthmus, Nigeria Bonny
Light, Saudi Arabia Light and Venezuela Tia Juana Light. Source: OPEC Monthly Oil Market Report.
Notes: 1. Edmonton Light Sweet prices are discontinued as of May 1, 2014 and replaced by the Canadian Light Crude blend which is traded daily on the Net Energy Index. 2. Hardisty Heavy. Based on contract prices at the end of each month. Sources: OPEC Monthly Oil Market Report: Oil & Gas Journal; Natural Resources Canada.
A7: World Petroleum Product Spot Prices ($US per barrel)
A8: Product Spot Prices in Selected American Cities (¢US per gallon)
Notes: 1. Reformulated regular unleaded gasoline. Spot prices are based on average daily prices over a specific timeframe. Source: EIA Weekly Petroleum Status
Report.
Notes: 1. Regular unleaded gasoline. 2. Waterborne 3. High Sulfur (3.5-4.0%) Residual Fuel Oil. Spot prices are based on average daily prices over a specific timeframe. Source: IEA Oil Market Report.
US Gulf Coast, Pipeline Rotterdam, Barges Singapore, Cargoes
B1: World Petroleum Supply and Demand Balance (million barrels per day)
Notes: 1. Totals for OECD and non-OECD supply include net refining gains; specific regions/groupings within each do not. 2. OPEC demand is an estimate based on
historical annual data. 3. Balance for World equals global stockbuilds (+) and stockdraws (-) for crude oil and petroleum products and miscellaneous gains and loss-
es. Regional surpluses (+) and deficits (-) are balanced through net-imports and stock changes in the short-term, and net-imports in the longer term. Supply includes
crude oil, condensates, NGLs, oil from non-conventional sources and processing gains. Demand is for petroleum products.
Source: IEA Oil Market Report.
OECD Non-OECD OPEC World
N. A. Europe Asia-Pac Total1 Asia Non-Asia FSU Total1 P. Gulf Non-Gulf Total2 Total3
Notes: 1. Production includes crude oil, condensates and NGLs. 2. Reserve-Production ratio is based on latest month production and British Petroleum reserve
estimates. Sources: IEA Oil Market Report and BP Statistical Review of World Energy.
Notes: 1. Product includes only finished petroleum products. 2. Total stocks include NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. All
stocks are closing levels for respective reporting period. Source: IEA Oil Market Report.
OECD Non-OECD OPEC World
N. A. Europe Asia-Pac Total Asia Non-Asia FSU Total P. Gulf Non-Gulf Total Total1
B4: OPEC Crude Oil Production and Targets (million barrels per day)
Notes: 1. Does not include NGLs; OPEC production targets apply to crude oil only. 2. Iraq does not have an official OPEC target. 3. OPEC-10 production targets. 4. As
Notes: 1. Based on dated Brent being processed in average US Gulf cracking refinery. 2. Based on dated Brent in average Rotterdam cracking refinery. 3. Based on
spot Dubai in average Singapore hydroskimming refinery. Source: IEA Oil Market Report.
C1: US Petroleum Supply and Demand Balance (million barrels per day)
Notes: 1. Does not balance because of unaccounted for crude oil. Regional surpluses (+) and deficits (-) are balanced through net-imports/transfers and stock chang-
es in the short-term, and net-imports/transfers in the longer term. 2. As of most recent month. Supply includes crude oil, condensates, NGLs, oil from non-
conventional sources and processing gains. Demand is for petroleum products. Source: EIA Petroleum Supply Monthly.
C2: US Petroleum Demand by Product (million barrels per day)
Notes: 1. Total includes other finished petroleum products. 2. Total petroleum demand includes refinery feedstocks, additives/oxygenates and other hydrocarbons.
Source: EIA Petroleum Supply Monthly.
C3: US Petroleum Stocks (million barrels)
Notes: 1. Petroleum stocks include crude oil, finished products, NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. 2. Includes Strategic
Petroleum Reserves. 3. Total includes other finished petroleum products. All stocks are closing levels for respective reporting period. Source: EIA Petroleum Supply
Monthly.
Finished Petroleum Products NGLs Petroleum
Gasoline Jet Fuel Distil. Resid. Total1 Total Total2
C4: US Petroleum Net Imports by Source (million barrels per day)
Notes: 1. Total includes net-imports from Russia and Asia-Pacific region. 2. Total OPEC includes the other eight cartel members. 3. As of latest month. Source EIA
Petroleum Supply Monthly.
C5: US Regional Crude Oil Production (million barrels per day)
Notes: 1. California includes Federal Offshore crude oil production. 2. Gulf of Mexico includes Federal Offshore production adjacent to Texas and Louisiana. 3. Crude
oil Reserve-Production ratio as of latest production month. Crude oil production does not include NGLs. Source: EIA Petroleum Supply Monthly.
OPEC
Canada Mexico Lat. Am. Europe Africa M.E. Total1 Venez. S. Arabia Nigeria Total2 P. Gulf
C6: US Refinery Activity Crude Input (MMbpd) - Utilization (percent)
Notes: 1) As of most recent month. Source: EIA Petroleum Supply Monthly.
C7: US Refinery Margins ($US per barrel)
Note: Based on specific crude being processed in average cracking refinery in a given area. As of February 2010, NY Harbor Arab Med. is now East Coast Composite.
D1: Canada Petroleum Supply and Demand Balances (million barrels per day)
D2: Canada Demand by Product (million barrels per day)
Notes: 1. As of most recent month. See notes for Table C1 for additional comments. Source: Statistics Canada’s Energy Statistics Handbook.
D3: Canada Petroleum Stocks (million barrels)
Notes: 1. Total includes other finished petroleum products. 2. Total petroleum demand includes refinery feedstocks, additives/oxygenates and other hydrocarbons. Source: Statistics Canada’s Energy Statistics Handbook.
Notes: 1. Total includes other finished petroleum products. 2. Total petroleum stocks include NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. All stocks are closing levels. Source: Statistics Canada’s Energy Statistics Handbook.
D4: Canada Crude Oil Production (million barrels per day)
Note: Total includes small amounts of production from Manitoba and Ontario. Source: Statistics Canada’s Energy Statistics Handbook.
D5: Canada Petroleum Imports by Source (thousand barrels per day)
Notes: 1. Includes all non-OPEC production. 2. Includes production by the other seven OPEC members. 3. As of most recent month. Sources: Statistics Canada’s
1. The World: OECD is comprised of countries from three regions: North America (Canada, Mexico, US); Europe (Austria, Belgium, Czech Republ ic,
Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Luxembourg, the Netherlands, Norway, Poland, Portugal, the Slovak
Republic, Spain, Sweden, Switzerland, Turkey, UK); and Asia-Pacific (Australia, Japan, New Zealand, South Korea). OPEC is comprised of Persian Gulf (Iran,
Iraq, Kuwait, Qatar, Saudi Arabia, United Arab Emirates) and non-Persian Gulf countries (Algeria, Indonesia, Libya, Nigeria, Venezuela). Non-OECD is
comprised of countries from three regions: Former Soviet Union (Armenia, Azerbaijan, Belarus, Georgia, Kazakhstan, Kirghizstan, Moldova, Russia,
Tajikistan, Turkmenistan, Ukraine, Uzbekistan); Asia (including non-OECD
Oceania); and non-Asia (Africa, Middle East, Latin America, and non-
OECD Europe). 2. United States: East (PADD I) – New England
(Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island,
Vermont); Central Atlantic (Delaware, Maryland, New Jersey, New York,
Pennsylvania, and the District of Columbia) and Lower Atlantic (Florida,
Georgia, North Carolina, South Carolina, Virginia, and West Virginia). Mid
3. Canada: East is comprised of Ontario, Manitoba, Quebec and the
Maritime provinces (New Brunswick, Newfoundland and Labrador, Nova
Scotia, and Prince Edward Island). West is comprised of Alberta, British
Columbia, Saskatchewan and the northern territories (NorthWest
Territories, Nunavuut, and Yukon).
Additional Notes
1. Petroleum and oil refer to crude oil and natural gas liquids (NGLs),
whereas crude oil refers to its namesake and field condensates.
Condensates derived from natural gas processing plants are classified as
NGLs. 2. The spot price is for immediate delivery of crude oil or refined
products at a specific location. Spot transactions are generally on a cargo
by cargo basis. In contrast, a futures price is for delivery of a specified
quantity of a commodity at a specified time and place in the future. 3.
Crude oil sold Free-On-Board (FOB) is made available to the buyer at the
loading port at a particular time, with transportation and insurance the
responsibility of the buyer. Crude oil sold Cost-Insurance-Freight (CIF) is
priced at a major destination point, with the seller responsible for the
transportation and insurance to that point. A “Delivered” transaction is
similar to a CIF transaction, except the buyer in the former pays based on the quantity and quality ascertained at the unloading port, whereas in a CIF
transaction, the buyer accepts the quantity and quality as determined at the loading port. 4. Processing gain is the volume of which refinery output is
greater than crude oil inputs. The difference is due to the processing of crude oil products, which in total have a lower specific gravity than crude oil. 5.
Unaccounted for crude oil reconciles the difference between crude input to refineries and the sum of domestic production, net imports/exports, stock
changes and documented losses (in the U.S.). 6. Totals may not equal the sum of their parts in the statistical tables due to rounding.
Crude Stream
Producing
Country or
Region
API
Gravity
(@60° F)
Sulfur
Content
(%)
BBLs/Metric
Tonne
Tapis Blend Malaysia 44 0.1 7.910
Ekofisk Blend Norway 43 0.2 7.773
WTI Texas 40 0.3 7.640
GCS Gulf of Mexico 40 0.3 7.640
Oklahoma Sweet Oklahoma 40 0.3 7.640
Kansas Sweet Kansas 40 0.4 7.640
Wyoming Sweet Wyoming 40 0.2 7.640
ELS Alberta 40 0.5 7.640
Brent Blend United kingdom 38 0.8 7.551
Bonny Light Nigeria 37 0.1 7.506
Oman Blend Oman 36 0.8 7.462
Arabian Light Saudi Arabia 34 1.8 7.373
Minas Indonesia 34 0.1 7.373
Isthmus Mexico 34 1.5 7.373
Michigan Sour Michigan 34 1.7 7.373
WTS Texas 33 1.7 7.328
Urals Russia 32 1.7 7.284
Tia Juana Light Venezuela 32 1.2 7.284
Dubai U.A.E. 31 1.7 7.239
Lost Hills California 30 0.6 7.194
Cano Limon Colombia 28 0.6 7.105
Arabian Heavy Saudi Arabia 27 2.8 7.061
ANS Alaska 27 1.1 7.061
Oriente Ecuador 25 1.4 6.971
Hardisty Heavy Alberta 25 2.1 6.971
Maya Mexico 22 3.3 6.838
Kern River California 13 1.0 6.436
Crude Oil Qualities
For more information, please contact Dinara Millington at [email protected]. Canadian Energy Research Institute 150, 3512 – 33 Street NW Calgary, AB T2L 2A6