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EXECUTIVE2017SUMMARY
Crude Oil Forecast, Markets and Transportation
CAPP’s annual Crude Oil Forecast, Markets and Transportation report provides a long-term outlook (2017 to 2030) for total Canadian crude oil production and western Canadian crude oil supply, plus key information on markets both existing and potential, and an updated synopsis of the transportation projects that could connect projected supply to various markets.
Canada’s crude oil supply is forecast to grow by 5 per cent per year to 2020 then slow to 2 per cent growth per year to 2030, due to many market uncertainties.The success of Canada’s energy future relies on the ability to overcome thesechallenges, including low commodity prices, pipeline capacity, industry competitiveness, regulatory uncertainty, and access to new markets.
WESTERN CANADIAN CRUDE OIL SUPPLY IS GROWING BY 1.5 MILLION B/D
Disclaimer: This publication was preparedby the Canadian Associationof Petroleum Producers (CAPP). While it is believed that the information contained herein is reliable under conditions and subject to the limitations set out, CAPP does not guarantee the accuracy or completeness of the information. The use of this report or any information contained will be at the user’s sole risk, regardless of any fault or negligence of CAPP.
© Material may be reproduced for public non-commercial use provided due diligence is exercised in ensuring accuracy of information reproduced; CAPP is identified as the source; and reproduction is not represented as an official version of the information reproduced nor has any affiliation.
2016 20301.5MILLION
B/D
2017
CRUDE OIL FORECAST,MARKETS AND TRANSPORTATION
CAPP.CA 2017-0009
The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP’s member companies produce about 80 per cent of Canada’s natural gas and crude oil. CAPP’s associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP’s members and associate members are an important part of a national industry with revenues from oil and natural gas production of about $120 billion a year.
CALGARY 2100, 350 - 7 Avenue SWCalgary, Alberta, Canada
T2P 3N9
OTTAWA 1000, 275 Slater StreetOttawa, Ontario, Canada
K1P 5H9
ST.JOHN’S1004, 235 Water Street
St. John’s, Newfoundland and Labrador, CanadaA1C 1B6
VICTORIA 360B Harbour Road
Victoria, British Columbia, CanadaV9A 3S1
EXECUTIVE2017SUMMARY
Crude Oil Forecast, Markets and Transportation
CAPP’s annual Crude Oil Forecast, Markets and Transportation report provides a long-term outlook (2017 to 2030) for total Canadian crude oil production and western Canadian crude oil supply, plus key information on markets both existing and potential, and an updated synopsis of the transportation projects that could connect projected supply to various markets.
Canada’s crude oil supply is forecast to grow by 5 per cent per year to 2020 then slow to 2 per cent growth per year to 2030, due to many market uncertainties. The success of Canada’s energy future relies on the ability to overcome these challenges, including low commodity prices, pipeline capacity, industry competitiveness, regulatory uncertainty, and access to new markets.
WESTERN CANADIAN CRUDE OIL SUPPLY IS GROWING BY 1.5 MILLION B/D
Disclaimer: This publication was prepared by the Canadian Association of Petroleum Producers (CAPP). While it is believed that the information contained herein is reliable under conditions and subject to the limitations set out, CAPP does not guarantee the accuracy or completeness of the information. The use of this report or any information contained will be at the user’s sole risk, regardless of any fault or negligence of CAPP.
© Material may be reproduced for public non-commercial use provided due diligence is exercised in ensuring accuracy of information reproduced; CAPP is identified as the source; and reproduction is not represented as an official version of the information reproduced nor has any affiliation.
2016 20301.5MILLION
B/D
2017
CRUDE OIL FORECAST,MARKETS AND TRANSPORTATION
CAPP.CA 2017-0009
The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP’s member companies produce about 80 per cent of Canada’s natural gas and crude oil. CAPP’s associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP’s members and associate members are an important part of a national industry with revenues from oil and natural gas production of about $120 billion a year.
CALGARY 2100, 350 - 7 Avenue SW Calgary, Alberta, Canada
T2P 3N9
OTTAWA 1000, 275 Slater Street Ottawa, Ontario, Canada
K1P 5H9
ST.JOHN’S 1004, 235 Water Street
St. John’s, Newfoundland and Labrador, Canada A1C 1B6
VICTORIA 360B Harbour Road
Victoria, British Columbia, CanadaV9A 3S1
20302016
EXISTING PIPELINE CAPACITY 39%
2017
2014
$34BILLION $15
BILLION
ADDITIONAL CAPACITY NEEDED PRICES AND INVESTMENT
Crude oil prices dropped from more
than US$100 per barrel in 2014, due
to a global oversupply of oil. Prices
have recovered somewhat since
early 2016 to almost US$50 per
barrel in May 2017. CAPP estimates
2017 producer capital spending for
oil sands will decline for the third
consecutive year, which reflects a
dramatic change to projects due
to continuing uncertainty in the
long term.
Drilling by conventional crude oil
producers is expected to increase
by 70 per cent compared to 2016,
but would still be 40 per cent
lower than in 2014.
3KEY COMPETITVENESS CHALLENGES FACING CANADA’S OIL INDUSTRY
PRODUCTION AND SUPPLY
Western Canadian crude oil supply accounts for the bulk of Canadian crude oil supply and is forecast to grow from 3.9 million b/d in 2016 to 5.4 million b/d in 2030.
• WESTERN CANADA HEAVY OIL SANDS SUPPLY provides 95 per cent of this growth.
• THE ANNUAL AVERAGE GROWTH IN WESTERN CANADA SUPPLY is projected to be 5 per cent from 2017 to 2020, then slow to an average annual growth rate of 2 per cent through 2030.
• EASTERN CANADA is forecast to contribute up to 307,000 b/d of production by 2024 but then decline steadily.
MARKETS
CAPP forecasts an additional 1.5 million b/d of supplies coming from Western Canada by 2030. The combined regional opportunities in Canada, the U.S. and globally can reasonably be expected to absorb these incremental supplies.
SUPPLY OF WESTERN CANADIAN CRUDE OIL
WILL GROW 39 PER CENT BY 2030 TO 5.4 MILLION BARRELS PER DAY (B/D).
CAPITAL INVESTMENT IN THE OIL SANDS
THE COMBINED DEMAND GROWTH FROM CHINA AND INDIA OF
10.1 MILLION B/D IS EQUAL TO MORE THAN 90 PER CENT
OF THE WORLD DEMAND INCREASE FROM 2015 TO 2040.
Key industry challenges are tempering long-term growth prospects.
1. UNCERTAINTY. Canada’s policies and regulations are becoming increasingly more stringent and costly, resulting in reduced attractiveness for investment.
2. CUMULATIVE IMPACTS OF GOVERNMENT POLICY CHANGES. Developing resources responsibly to help achieve key regulatory, social and environmental outcomes, is important and needs be done in a manner that does not unnecessarily burden industry and risk more jobs.
3. POTENTIAL DIVERGENT POLICIES FROM U.S. COMPETITORS. U.S. producers may not have to face similar policies to those in Canada. Additionally, protectionist policies that may be pursued by the current U.S. administration are also a cause for concern.
SOURCE: IEA World Energy Outlook 2016, New Policies Scenario
FOR INFORMATION CONTACT: (403) 267-1141 / CAPP.CA
PADD V
PADD IV
PADD II
PADD III PADD I
PADD
WA
ORMT
CO
IA
WI
IN
NE
NM
GA
MS
ID
UT
NVCA
AZ
TX
OK
NDMN
SD
KS
WY
NC
KY
SC
IL
MI
MO
AR
AL
OH
TN
LA
VAWVDE
MD
PA
NY
NH
MA
CT
VT
ME
NJ
RI
VANCOUVER TO:Japan - 4,300 milesTaiwan - 5,600 milesS.Korea - 4,600 milesChina - 5,100 miles
San Francisco - 800 milesLos Angeles - 1,100 miles
2016 CANADIAN CRUDE OIL PRODUCTION 000 m3/d 000 b/d
British Columbia 10 61Alberta 457 3,066Saskatchewan 73 461Manitoba 6 40Northwest Territories 1 9
Western Canada 578 3,637Eastern Canada 34 213Total Canada 612 3,850
Major Existing Crude Oil Pipelines carryingCanadian crude oil
Selected Other Crude Oil Pipelines
Crude Refining Capacities as at June 1, 2017(thousand barrels per day)
Petroleum Administration for Defense District
Flanagan PhiladelphiaNewell
Port Arthur/Nederland/Beaumont
ArtesiaBigSpring
Slaughter
ThreeRivers
Crane
FL
CENTURION
WAS
CANA
SPEARHEAD
SOUTH
PONY EXPRESSWHITE CLIFFS
TRANSCAN
ADA G
ULF CO
AST
SEAWAY TW
IN
ENBRIDGE LINE 9
NAI
KTO
NE
PEGASUS
Come by Chance
LakeCharles
St.James
SHELL CHEVRO
NPACIFIC
EXXONMOBIL
BRIDGETEX
PERMIAN EXPRESSCRANE
HO-HOCACTUS
EXXONMOBIL
KEYSTON
E
KEYSTON
E
HUSKY
RAINBO
W
ENBRIDGE NW
Saint John
Montréal
Westover
MONTREAL
VANCOUVERChevron........... 55
PUGET SOUNDBP (Cherry Pt) .............234Phillips 66 (Ferndale) ...101Shell (Anacortes)..........137Tesoro (Anacortes) .......120TrailStone (Tacoma) .......42
SAN FRANCISCOChevron...................257Phillips 66................120Shell ........................144Tesoro .....................166Valero ......................145
BAKERSFIELDKern Oil .....................26San Joaquin...............14
GREAT FALLSCalumet ......................25
BILLINGSCHS (Laurel) ................56Phillips 66....................60ExxonMobil ..................60
LOS ANGELESAlon USA .. . . . . . . . . . . . . . . . . . . . . . . .70Tesoro (Carson/Wilmington) ... 380Chevron ................................ 291PBF ...................................... 155Phillips 66 ............................ 139Valero .................................... 85
EDMONTONImperial .........................191Suncor...........................142Shell ................................92LLOYDMINSTERHusky asphalt plant .........29Husky Upgrader...............82
REGINA
Complex ......................................135MOOSE JAWMoose Jaw asphalt plant ...............19
WYOMINGSinclair (Casper) ............................25Sinclair Oil (Sinclair).......................85
) ..................18HollyFrontier (Cheyenne) ................52
OHIOBP-Husky (Toledo)........................160PBF (Toledo).................................170Marathon (Canton) .........................93Husky (Lima)................................160Marathon (Catlettsburg) ...............273
MISSISSIPPI RIVERExxonMobil (Baton Rouge) ...........503PBF (Chalmette)...........................189Marathon (Garyville).....................543Shell (Convent).............................235Shell (Norco) ................................229Valero (Norco) ..............................215Valero (Meraux)............................125Phillips 66 (Belle Chasse).............247Alon (Krotz Springs) .......................74Placid (Port Allen)...........................60
HOUSTON/TEXAS CITYPRSI (Pasadena) ........... 100Marathon (Galveston).... 459Shell (Deer Park)........... 312ExxonMobil ................... 561LyondellBasell .............. 268Marathon ....................... 86Valero (2) ................80+225
ALABAMAHunt (Tuscaloosa) ..........................40Shell (Saraland) .............................85
THREE RIVERSValero ............................. 89CORPUS CHRISTICITGO ........................... 157Flint .............................. 300Valero ........................... 275
SWEENYPhillips 66..................... 247
LAKE CHARLESCITGO ............................. 425Phillips 66....................... 249Calcasieu.......................... 75
PORT ARTHUR/BEAUMONTExxonMobil ....................363
.578Valero ............................335Total ..............................226
SAINT JOHNIrving ...................300
NEW JERSEYPhillips 66 (Bayway)........ 241PBF (Paulsboro) .............. 168Axeon SP (Paulsboro) ........ 74DELAWAREPBF (Delaware City) ........ 190
MEMPHISValero ..................180EL DORADODelek.....................80
TYLERDelek.....................75
DETROITMarathon.......... 132
OKLAHOMAPhillips 66 (Ponca City) .........................203HollyFrontier (Tulsa) .............................125Coffeyville Res. (Wynnewood) .................70Valero (Ardmore).....................................86
KANSAS
NEW MEXICO/W. TEXASHollyFrontier (Artesia) ...........................100Alon (Big Spring). ....................................73
BORGER/MCKEEWRB ............................ 146Valero .......................... 195
DENVER/COMMERCE CITYSuncor........................... 98
SALT LAKE CITYBig West ............. 35Chevron.............. 53HollyFrontier ....... 45Tesoro ................ 63
ST. PAULFlint Hills .............339
SUPERIORCalumet............45
CHICAGOBP ..........................430ExxonMobil ..............236PDV ........................180
SARNIAImperial ............... 119Shell ...................... 73Suncor................... 85NANTICOKEImperial ............... 113
MONTRÉAL/QUÉBECSuncor.................... 137Valero ..................... 230
PENNSYLVANIAMonroe Energy (Trainer)................ 195Phil. Energy Solutions (Phil.).......... 335
WARRENUnited .......... 70
NEWELL, WVErgon............ 23
UPGRADERSSyncrude (Fort McMurray)................. 465Suncor (Fort McMurray) .................... 438Shell (Scotford) ................................. 240CNRL (Horizon) ................................. 210
WOOD RIVERWRB .................................314ROBINSONMarathon..........................231MT VERNONCountrymark.......................28
NEWFOUNDLAND & LABRADORSilver Range (Come by Chance) .......... 115
PRINCE GEORGEHusky.............. 12
Hibernia White Rose
Terra NovaHebron
PIPELINE TOLLS FOR LIGHT OIL (US$ PER BARREL)
Edmonton to Burnaby (Trans Mountain) 1.70 Anacortes (Trans Mountain/Puget) 2.00 Sarnia (Enbridge) 4.40 Montréal (Enbridge) 6.05 Chicago (Enbridge) 4.00 Cushing (Enbridge) 5.15*-6.40 Wood River (Enbridge/Mustang/Capwood) 5.40 USGC (Enbridge/Seaway) 6.10†-10.40Hardisty to Guernsey (Express/Platte) 3.10* Wood River (Express/Platte) 4.80* Wood River (Keystone) 4.50**-5.35 USGC (Keystone/Gulf Coast Ext.) 7.15**-11.65
USEC to Montréal (Portland/Montréal) 1.40
St. James to Wood River (Capline/Capwood) 1.30
PIPELINE TOLLS FOR HEAVY OIL (US$ PER BARREL)
Hardisty to: Chicago (Enbridge) 4.20 Cushing (Enbridge) 5.35*-6.60 Cushing (Keystone) 6.20**-6.90 Wood River (Enbridge/Mustang/Capwood) 6.05 Wood River (Keystone) 5.15**-6.05 Wood River (Express/Platte) 5.35* USGC (Enbridge/Seaway) 6.95†-11.10 USGC (Keystone/Gulf Coast Ext.) 7.80**-12.60
Notes 1) Assumed exchange rate = 0.?? US$ / 1C$ (May 2017 average) 2) Tolls rounded to nearest 5 cents 3) Tolls in effect July 1, 2017
* 10-year committed toll**20-year committed toll†First Open Season,15-year, 50,000+ b/d committed volumes
Tesoro (Gallup)........................................25Tesoro (El Paso)................................... .135
Tesoro .................102
Canadian and U.S. Crude Oil Pipelines and Refineries - 2017
Dickinson
NORTH DAKOTATesoro (Mandan) ........74Tesoro (Dickinson) .....20
CHS (McPherson)....................................85HollyFrontier (El Dorado) ......................135Coffeyville Res. (Coffeyville) ..................115
reviR dooW
HCOK
LOUISIANACalumet (Shreveport) ........ 60
MISSISSIPPIChevron (Pascagoula) ..................330Ergon (Vicksburg)...........................25
DAKOTA ACCESS
ETCO
P
Diamond
20302016
EXISTING PIPELINE CAPACITY 39%
2017
2014
$34BILLION $15
BILLION
ADDITIONAL CAPACITY NEEDED PRICES AND INVESTMENT
Crude oil prices dropped from more
than US$100 per barrel in 2014, due
to a global oversupply of oil. Prices
have recovered somewhat since
early 2016 to almost US$50 per
barrel in May 2017. CAPP estimates
2017 producer capital spending for
oil sands will decline for the third
consecutive year, which reflects a
dramatic change to projects due
to continuing uncertainty in the
long term.
Drilling by conventional crude oil
producers is expected to increase
by 70 per cent compared to 2016,
but would still be 40 per cent
lower than in 2014.
3KEY COMPETITVENESS CHALLENGES FACING CANADA’S OIL INDUSTRY
PRODUCTION AND SUPPLY
Western Canadian crude oil supply accounts for the bulk of Canadian crude oil supply and is forecast to grow from 3.9 million b/d in 2016 to 5.4 million b/d in 2030.
• WESTERN CANADA HEAVY OIL SANDS SUPPLY provides 95 per cent of this growth.
• THE ANNUAL AVERAGE GROWTH IN WESTERN CANADA SUPPLY is projected to be 5 per cent from 2017 to 2020, then slow to an average annual growth rate of 2 per cent through 2030.
• EASTERN CANADA is forecast to contribute up to 307,000 b/d of production by 2024 but then decline steadily.
MARKETS
CAPP forecasts an additional 1.5 million b/d of supplies coming from Western Canada by 2030. The combined regional opportunities in Canada, the U.S. and globally can reasonably be expected to absorb these incremental supplies.
SUPPLY OF WESTERN CANADIAN CRUDE OIL
WILL GROW 39 PER CENT BY 2030 TO 5.4 MILLION BARRELS PER DAY (B/D).
CAPITAL INVESTMENT IN THE OIL SANDS
THE COMBINED DEMAND GROWTH FROM CHINA AND INDIA OF
10.1 MILLION B/D IS EQUAL TO MORE THAN 90 PER CENT
OF THE WORLD DEMAND INCREASE FROM 2015 TO 2040.
Key industry challenges are tempering long-term growth prospects.
1. UNCERTAINTY. Canada’s policies and regulations are becoming increasingly more stringent and costly, resulting in reduced attractiveness for investment.
2. CUMULATIVE IMPACTS OF GOVERNMENT POLICY CHANGES. Developing resources responsibly to help achieve key regulatory, social and environmental outcomes, is important and needs to be done in a manner that does not unnecessarily burden industry and risk more jobs.
3. POTENTIAL DIVERGENT POLICIES FROM U.S. COMPETITORS. U.S. producers may not have to face similar policies to those in Canada. Additionally, protectionist policies that may be pursued by the current U.S. administration are also a cause for concern.
SOURCE: IEA World Energy Outlook 2016, New Policies Scenario
FOR INFORMATION CONTACT: (403) 267-1141 / CAPP.CA
PADD V
PADD IV
PADD II
PADD III PADD I
PADD
WA
ORMT
CO
IA
WI
IN
NE
NM
GA
MS
ID
UT
NVCA
AZ
TX
OK
NDMN
SD
KS
WY
NC
KY
SC
IL
MI
MO
AR
AL
OH
TN
LA
VAWVDE
MD
PA
NY
NH
MA
CT
VT
ME
NJ
RI
VANCOUVER TO:Japan - 4,300 milesTaiwan - 5,600 milesS.Korea - 4,600 milesChina - 5,100 miles
San Francisco - 800 milesLos Angeles - 1,100 miles
2016 CANADIAN CRUDE OIL PRODUCTION 000 m3/d 000 b/d
British Columbia 10 61Alberta 457 3,066Saskatchewan 73 461Manitoba 6 40Northwest Territories 1 9
Western Canada 578 3,637Eastern Canada 34 213Total Canada 612 3,850
Major Existing Crude Oil Pipelines carryingCanadian crude oil
Selected Other Crude Oil Pipelines
Crude Refining Capacities as at June 1, 2017(thousand barrels per day)
Petroleum Administration for Defense District
Flanagan PhiladelphiaNewell
Port Arthur/Nederland/Beaumont
ArtesiaBigSpring
Slaughter
ThreeRivers
Crane
FL
CENTURION
WAS
CANA
SPEARHEAD
SOUTH
PONY EXPRESSWHITE CLIFFS
TRANSCAN
ADA G
ULF CO
AST
SEAWAY TW
IN
ENBRIDGE LINE 9
NAI
KTO
NE
PEGASUS
Come by Chance
LakeCharles
St.James
SHELL CHEVRO
NPACIFIC
EXXONMOBIL
BRIDGETEX
PERMIAN EXPRESSCRANE
HO-HOCACTUS
EXXONMOBIL
KEYSTON
E
KEYSTON
E
HUSKY
RAINBO
W
ENBRIDGE NW
Saint John
Montréal
Westover
MONTREAL
VANCOUVERChevron........... 55
PUGET SOUNDBP (Cherry Pt) .............234Phillips 66 (Ferndale) ...101Shell (Anacortes)..........137Tesoro (Anacortes) .......120TrailStone (Tacoma) .......42
BAKERSFIELDKern Oil .....................26San Joaquin...............14
GREAT FALLSCalumet ......................25
BILLINGSCHS (Laurel) ................56Phillips 66....................60ExxonMobil ..................60
LOS ANGELESAlon USA .. . . . . . . . . . . . . . . . . . . . . . . .70Tesoro (Carson/Wilmington) ... 380Chevron ................................ 291PBF ...................................... 155Phillips 66 ............................ 139Valero .................................... 85
EDMONTONImperial .........................191Suncor...........................142Shell ............................. .100LLOYDMINSTERHusky asphalt plant .........29Husky Upgrader...............82
REGINA
Complex ......................................135MOOSE JAWMoose Jaw asphalt plant ...............19
WYOMINGSinclair (Casper) ............................25Sinclair Oil (Sinclair).......................85
) ..................18HollyFrontier (Cheyenne) ................52
OHIOBP-Husky (Toledo)........................160PBF (Toledo).................................170Marathon (Canton) .........................93Husky (Lima)................................160Marathon (Catlettsburg) ...............273
MISSISSIPPI RIVERExxonMobil (Baton Rouge) ...........503PBF (Chalmette)...........................189Marathon (Garyville).....................543Shell (Convent).............................235Shell (Norco) ................................229Valero (Norco) ..............................215Valero (Meraux)............................125Phillips 66 (Belle Chasse).............247Alon (Krotz Springs) .......................74Placid (Port Allen)...........................60
HOUSTON/TEXAS CITYPRSI (Pasadena) ........... 100Marathon (Galveston).... 459Shell (Deer Park)........... 312ExxonMobil ................... 561LyondellBasell .............. 268Marathon ....................... 86Valero (2) ................80+225
ALABAMAHunt (Tuscaloosa) ..........................40Shell (Saraland) .............................85
THREE RIVERSValero ............................. 89CORPUS CHRISTICITGO ........................... 157Flint .............................. 300Valero ........................... 275
SWEENYPhillips 66..................... 247
LAKE CHARLESCITGO ............................. 425Phillips 66....................... 249Calcasieu.......................... 75
PORT ARTHUR/BEAUMONTExxonMobil ....................363
.578Valero ............................335Total ..............................226
SAINT JOHNIrving ...................300
NEW JERSEYPhillips 66 (Bayway)........ 241PBF (Paulsboro) .............. 168Axeon SP (Paulsboro) ........ 74DELAWAREPBF (Delaware City) ........ 190
MEMPHISValero ..................180EL DORADODelek.....................80
TYLERDelek.....................75
DETROITMarathon.......... 132
OKLAHOMAPhillips 66 (Ponca City) .........................203HollyFrontier (Tulsa) .............................125Coffeyville Res. (Wynnewood) .................70Valero (Ardmore).....................................86
KANSAS
NEW MEXICO/W. TEXASHollyFrontier (Artesia) ...........................100Alon (Big Spring). ....................................73
BORGER/MCKEEWRB ............................ 146Valero .......................... 195
DENVER/COMMERCE CITYSuncor........................... 98
SALT LAKE CITYBig West ............. 35Chevron.............. 53HollyFrontier ....... 45Tesoro ................ 63
ST. PAULFlint Hills .............339
SUPERIORCalumet............45
CHICAGOBP ..........................430ExxonMobil ..............236PDV ........................180
SARNIAImperial ............... 119Shell ...................... 73Suncor................... 85NANTICOKEImperial ............... 113
MONTRÉAL/QUÉBECSuncor.................... 137Valero ..................... 230
PENNSYLVANIAMonroe Energy (Trainer)................ 195Phil. Energy Solutions (Phil.).......... 335
WARRENUnited .......... 70
NEWELL, WVErgon............ 23
UPGRADERSSyncrude (Fort McMurray)................. 465Suncor (Fort McMurray) .................... 438Shell (Scotford) ................................. 240CNRL (Horizon) ................................. 210
WOOD RIVERWRB .................................314ROBINSONMarathon..........................231MT VERNONCountrymark.......................28
NEWFOUNDLAND & LABRADORSilver Range (Come by Chance) .......... 115
PRINCE GEORGEHusky.............. 12
Hibernia White Rose
Terra NovaHebron
PIPELINE TOLLS FOR LIGHT OIL (US$ PER BARREL)
Edmonton to Burnaby (Trans Mountain) 2.00 Anacortes (Trans Mountain/Puget) 2.30 Sarnia (Enbridge) 4.50 Montréal (Enbridge) 6.10 Chicago (Enbridge) 4.10 Cushing (Enbridge) 5.25*-6.50 Wood River (Enbridge/Mustang/Capwood) 5.25 USGC (Enbridge/Seaway) 6.30† - 8.85§
Hardisty to Guernsey (Express/Platte) 3.20* Wood River (Express/Platte) 4.90* Wood River (Keystone) 4.40**-5.30 USGC (Keystone/Gulf Coast Ext.) 7.15§ -11.55
USEC to Montréal (Portland/Montréal) 0.50
St. James to Wood River (Capline/Capwood) 1.30
PIPELINE TOLLS FOR HEAVY OIL (US$ PER BARREL)
Hardisty to: Chicago (Enbridge) 4.30 Cushing (Enbridge) 5.45*-6.70 Cushing (Keystone) 6.10**-6.85 Wood River (Enbridge/Mustang/Capwood) 5.85 Wood River (Keystone) 5.05**-6.00 Wood River (Express/Platte) 5.50* USGC (Enbridge/Seaway) 7.00† - 9.05§
USGC (Keystone/Gulf Coast Ext.) 7.80§ - 12.55
Notes 1) Assumed exchange rate = 0.73 US$ / 1C$ (May 2017 average) 2) Tolls rounded to nearest 5 cents 3) Tolls in effect July 1, 2017
* 10-year committed toll**20-year committed toll†First Open Season,15-year, 50,000+ b/d committed volumes§ International Joint Tariff
Tesoro (Gallup)........................................25Tesoro (El Paso)................................... .135
Tesoro .................102
Canadian and U.S. Crude Oil Pipelines and Refineries - 2017
Dickinson
NORTH DAKOTATesoro (Mandan) ........74Tesoro (Dickinson) .....20
CHS (McPherson)....................................85HollyFrontier (El Dorado) ......................135Coffeyville Res. (Coffeyville) ..................115
reviR dooW
HCOK
LOUISIANACalumet (Shreveport) ........ 60
MISSISSIPPIChevron (Pascagoula) ..................330Ergon (Vicksburg)...........................25
DAKOTA ACCESS
ETCO
P
Diamond
SAN FRANCISCOChevron (sold to Parkland Fuels) ....257Phillips 66......................................120Shell ..............................................144Tesoro ...........................................166Valero ............................................145
KANSAS
Crude Oil Forecast, Markets & Transportation i
Trans Mountain Expansion Project
Existing Pipeline Infrastructure to Gulf Coast
TransCanada Keystone XL
TransCanada Energy East
Enbridge Line 3 Replacement
Vancouver
Edmonton
BakerMontréal
Saint John
Steele City
Patoka
Cushing
Port Arthur
Winnipeg
Superior
Lévis
Hardisty
Pipeline Proposals
ENBRIDGE LINE 3 REPLACEMENT
ADDITIONAL CAPACITY:
370,000 b/dPOTENTIAL MARKETS:
Central and Eastern Canada,U.S. Midwest and Gulf Coast
STATUS:Approved November 29, 2016
with 89 conditions by the federal government.
TRANSCANADA KEYSTONE XL
ADDITIONAL CAPACITY:
830,000 b/dPOTENTIAL MARKETS:
Heavy oil refineries along Gulf Coast
STATUS:U.S. Presidential permit received
on March 24, 2017.
TRANS MOUNTAIN
EXPANSION PROJECTADDITIONAL CAPACITY:
590,000 b/dPOTENTIAL MARKETS:
Asia and California
STATUS:Approved November 29, 2016
with 157 conditions by the federal government.
TRANSCANADA ENERGY EAST
ADDITIONAL CAPACITY:
1,100,000 b/dPOTENTIAL MARKETS:
Eastern Canada, U.S. East Coast,Europe, Africa and Asia
STATUS:NEB hearing pending.
THE U.S. GULF COAST HAS AN ESTIMATED HEAVY OIL
PROCESSING CAPACITY OF MORE THAN 2 MILLION B/D, WHICH IS IDEALLY SUITED TO REFINING FORECASTED
WESTERN CANADIAN HEAVY OIL SUPPLIES.
TRANSPORTATION
Connecting Western Canada’s growing crude oil supplies to global markets is a priority.
• The existing pipeline network originating in Western Canada can TRANSPORT 4.0 MILLION B/D.
• By 2030, the annual supply of WESTERN CANADIAN OIL IS FORECAST TO BE 5.4 MILLION B/D, AN INCREASE OF 1.5 MILLION B/D FROM TODAY.
• NEW PIPELINE INFRASTRUCTURE WILL BE NEEDED to move this growing volume of Canadian oil to Canadians and markets abroad.
ii CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
TABLE OF CONTENTS
EXECUTIVE SUMMARY IFC
LIST OF FIGURES AND TABLES iii
1 INTRODUCTION 1
2 CRUDE OIL PRODUCTION & SUPPLY FORECAST 32.1 Production & Supply Forecast Methodology 3
2.2 Canadian Production 4
2.3 Eastern Canada Production 5
2.4 Western Canada Production 6
2.5 Western Canada Supply 10
2.6 Crude Oil Production & Supply Summary 12
3 CRUDE OIL MARKETS 133.1 Canada 14
3.2 United States 16
3.3 International 22
3.4 Markets Summary 22
4 TRANSPORTATION 234.1 Crude Oil Pipelines Exiting Western Canada 24
4.2 Oil Pipelines to the U.S. Midwest 28
4.3 Oil Pipelines to the U.S. Gulf Coast 30
4.4 Oil Pipelines to the West Coast of Canada 33
4.5 Oil Pipelines to Eastern Canada 33
4.6 Diluent Pipelines 36
4.7 Crude Oil by Rail 37
4.8 Transportation Summary 38
GLOSSARY 39
APPENDIX A.1: CAPP Canadian Crude Oil Production Forecast 2017 – 2030 41
APPENDIX A.2: CAPP Western Canadian Crude Oil Supply Forecast 2017 – 2030 43
APPENDIX B: Acronyms, Abbreviations, Units and Conversion Factors 44
APPENDIX C: Map of Canadian and U.S. Crude Oil Pipelines and Refineries 45
Crude Oil Forecast, Markets & Transportation iii
LIST OF FIGURES AND TABLES
FIGURESFigure 1.1 World Total Primary Energy Demand, 2014 1Figure 1.2 Capital Investment in Oil Sands 2
Figure 2.1 Canadian Oil Sands & Conventional Production 4Figure 2.2 Newfoundland & Labrador Production 6Figure 2.3 Western Canada Conventional Production 7Figure 2.4 Oil Sands Regions 8Figure 2.5 Western Canada Oil Sands Production 9Figure 2.6 Western Canada Oil Sands & Conventional Supply 11
Figure 3.1 Canada and U.S.: 2016 Crude Oil Receipts by Source 13Figure 3.2 2016 PADD I: Foreign Sourced Supply by Type and Domestic Crude Oil 16Figure 3.3 2016 PADD II: Foreign Sourced Supply by Type and Domestic Crude Oil 18Figure 3.4 2016 PADD III: Foreign Sourced Supply by Type and Domestic Crude Oil 19Figure 3.5 2016 PADD IV: Foreign Sourced Supply by Type and Domestic Crude Oil 19Figure 3.6 2016 PADD V: Foreign Sourced Supply by Type and Domestic Crude Oil 20Figure 3.7 Global Net Oil Imports: 2015 to 2040 22
Figure 4.1 Existing and Proposed Canadian & U.S. Crude Oil Pipelines 23Figure 4.2 Canadian Fuel Oil and Crude Petroleum Moved by Rail: Car Loadings & Tonnage 37Figure 4.4 Existing Takeaway Capacity from Western Canada vs. Supply Forecast 38
TABLESTable 2.1 Canadian Crude Oil Production 4Table 2.2 Atlantic Canada Projects and Recent Discoveries 5Table 2.3 Western Canada Crude Oil Production 6Table 2.4 Oil Sands Production 8Table 2.5 Western Canada Crude Oil Supply 11
Table 3.1 Refineries in Western Canada by Province 14Table 3.2 Refineries in Eastern Canada by Province 15 Table 3.3 Rail Offloading Terminals in Eastern Canada and PADD I 17Table 3.4 Refinery Upgrade Projects in PADD II 18 Table 3.5 Rail Offloading Terminals in Western Canada & PADD V 21Table 3.6 Total Oil Demand in Major Asian Countries 22
Table 4.1 Major Existing Crude Oil Pipelines Exiting Western Canada 24Table 4.2 Proposed Crude Oil Pipelines Exiting Western Canada 25Table 4.3 Enbridge Mainline System: Upstream Superior 26Table 4.4 Summary of Crude Oil Pipelines to the U.S. Midwest 29Table 4.5 Summary of Crude Oil Pipelines to the U.S. Gulf Coast 30Table 4.6 Summary of Crude Oil Pipelines to the West Coast of Canada 33Table 4.7 Summary of Crude Oil Pipelines to Eastern Canada 36Table 4.8 Summary of Diluent Pipelines 36Table 4.9 Rail Uploading Terminals in Western Canada 37
1 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
Crude oil is the lifeblood of the modern economy. According to the International Energy Agency (IEA), crude oil accounts for the largest share of the total world primary energy demand (Figure 1.1) and is forecasted to remain so to 2040. CAPP’s annual Crude Oil Forecast, Markets and Transportation report provides the association’s latest long-term outlook for total Canadian crude oil production and western Canadian crude oil supply. It also contains key information on Canadian crude oil markets, both existing and potential, as well as an updated synopsis of developments in the transportation projects that could connect this projected supply to various markets. A primary purpose of this report is to inform discussion and to support a fundamental understanding of oil industry issues.
INTRODUCTION1
The 2017 edition of this publication has been produced as challenges to industry competitiveness continue to arise and temper growth prospects for oil sands development in the long term. In addition to continuing low prices, Canadian producers will need to contend with carbon pricing and cumulative impacts from other federal and provincial climate change policies, which their competitors in the U.S. may not be facing. Protectionist policies that may be pursued by the current U.S. administration are also a cause for concern.
FIGURE 1.1 WORLD TOTAL PRIMARY ENERGY DEMAND, 2014
Other Renewables1%
Bioenergy10%
Hydro2%
Nuclear5%
Natural Gas21%
Oil31%
Coal29%
Source: IEA, World Energy Outlook 2016
Crude Oil Forecast, Markets & Transportation 2
In 2014, crude oil prices dropped from over US$100 per barrel to half that level by year-end before reaching a low of US$26 per barrel in early 2016. Lower oil prices have been attributed to a global oversupply of oil. Geopolitical events in various oil producing areas, market uncertainty, weather conditions, infrastructure constraints and government regulations can also influence prices, both regionally and globally.
More recently, prices have improved somewhat, with West Texas Intermediate (WTI) spot crude prices in May 2017 hovering just under US$50 per barrel. Conventional producers in Canada are expected to respond with a 70 per cent increase in drilling of conventional oil wells in 2017 compared to 2016 but would still be almost 40 per cent lower when compared to 2014.
FIGURE 1.2 CAPITAL INVESTMENT IN OIL SANDS
0
5
10
15
20
25
30
35
40
2017 F2016 E201520142013
C$ billions
3134
23
17 15
E = estimateF = forecast
In terms of the oil sands outlook, CAPP estimates 2017 producer capital spending for oil sands will decline for the third consecutive year (Figure 1.2), which reflects a dramatic rationalization of projects due to the continuing uncertainty in the long term. Projects that have recently started up or are in construction are expected to proceed and so contribute to growing production through to 2020. Oil sands will be an integral part of the global supply in the future as well, since CAPP forecasts a steady, albeit slower growth from 2020 to the end of the forecast period in 2030. The slower growth is reflective of continuing uncertainty as companies assess the impact of impending risks to their operating environment. The economic competitiveness of the oil sands on a global scale is vital in order to attract capital to build for the future.
In addition to low oil prices, Canada’s oil industry is facing a number of challenges to its ability to compete in the global market. Canadian and U.S. regulators have offered divergent responses to climate change and potential U.S. protectionist policies threaten Canada’s unfettered access to its traditional export markets. These factors continue to weigh heavily on the outlook in the long term. On the upside, the oil sands industry is focusing on technologies that reduce costs and greenhouse gas (GHG) emissions for existing and future operations. Although CAPP’s most current forecast for conventional oil production is showing some recovery, the oil sands outlook is essentially unchanged from its 2016 forecast. CAPP forecasts crude oil production from Western Canada to grow 1.3 million b/d by 2030. After blending and the inclusion of imported diluent, this translates into over 1.5 million b/d of additional crude oil supplies requiring transport capacity to markets.
3 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
2.1 PRODUCTION & SUPPLY FORECAST METHODOLOGY
CAPP’s western Canada conventional and eastern Canadian production forecasts are both developed through an internal analysis of historical trends, expected drilling activity, as well as discussions with industry stakeholders and government agencies.
For the oil sands forecast, CAPP surveyed oil sands producers in the first quarter of 2017 for the following data:
• Expected production for each project;
• Upgraded crude oil production; and
• The type and volume of diluent in order tomove the heavy oil production to market.
Producers were asked to respond to the survey based on their own company’s view of the price outlook as well as recent policy developments including federal and provincial climate change policies. The survey results were then “risked” based on each project’s stage of development while giving consideration to each company’s past performance for previous phases of projects relative to public announcements. The reasonableness of the overall forecast was then assessed against historical trends during a final review. No direct constraints were put on the forecast due to availability of condensate for blending purposes or lack of transportation infrastructure although company assessments on these issues may have impacted individual producer survey responses.
Crude oil supplies that are delivered to refining markets are greater than production volumes because they include imported diluent volumes.
Canada has the third largest reserves of crude oil in the world and is ranked by the Oil & Gas Journal as the sixth largest global producer. In 2016, Canada produced 3.85 million b/d of crude oil, including pentanes & condensates, which was equal to over 5 per cent of global production. With such vast resources, there is tremendous potential for the industry to grow, which would provide many economic and social benefits to Canadians. However, Canadian production continues to be tempered by lower oil prices, and new federal and provincial environmental policies that differ from the regulatory approach of other competing jurisdictions. CAPP forecasts a growth in crude oil production of 1.3 million b/d from 2016 to 2030 in Western Canada. This translates into 1.5 million b/d of additional crude oil supply after blending and including imported diluent volumes.
2 CRUDE OIL PRODUCTION &
SUPPLY FORECAST
Crude Oil Forecast, Markets & Transportation 4
2.2 CANADIAN PRODUCTION
Eastern Canada is a notable source of Canadian supply, primarily from offshore projects. However, Western Canada contributes the bulk of supply from both conventional drilling and oil sands projects.
Total Canadian crude oil production was almost unchanged in 2016 from 2015 levels, as increased production from Eastern Canada was offset by the production losses in Western Canada due to conventional production declines and the impact of the Fort McMurray fires on oil sands production. Conventional production, including pentanes & condensate, accounted for 32 per cent of total production. Oil sands comprised 62 per cent whereas Eastern Canada production made up the remaining 6 per cent.
TABLE 2.1 CANADIAN CRUDE OIL PRODUCTION
million b/d 2016 2020 2025 2030
Eastern Canada 0.21 0.28 0.29 0.19
Western Canada 3.64 4.34 4.59 4.93
Total Canada* 3.85 4.62 4.88 5.12*Total may not add up due to rounding.
Total production is forecast to grow from 3.85 million b/d in 2016 to 5.12 million b/d by 2030 (Figure 2.1). Oil sands is the main driver for the 1.3 million b/d of production growth. Conventional production is relatively flat at around 1.2 million b/d throughout the forecast period to 2030. Drilling of conventional oil wells is recovering thereby slowing the rate of decline until 2020 and resulting in flat production thereafter. The near-term declines in conventional light and heavy crude oil production will be partially offset by the higher production in pentanes as industry continues to develop liquids-rich natural gas pools.
The significant investment in light tight oil (LTO) is expected to lead to further growth. This upside potential is not fully reflected in this forecast as LTO production is in the early stages of development.
0
1
2
3
4
5
6
2030202820262024202220202018201620142012201020082006
Pentanes/Condensate
million barrels per day
Actual Forecast
Eastern Canada
Conventional Light
June 2016 Forecast
Conventional Heavy
Oil Sands
2017
FIGURE 2.1 CANADIAN OIL SANDS & CONVENTIONAL PRODUCTION
5 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
2.3 EASTERN CANADA PRODUCTION
Crude oil from Eastern Canada is sourced primarily from three oil fields located offshore of Newfoundland and Labrador. They are the Hibernia, Terra Nova and White Rose projects. However, Ontario and New Brunswick also contribute some small volumes of production. In 2016, production increased by 38,000 b/d to reach 213,000 b/d, which represents a 21 per cent increase over 2015 production of 176,000 b/d. The increase is attributed to higher production from the Hibernia South Extension satellite field. Table 2.2 summarizes details of the producing, in-development, and recently discovered fields.
Oil production is expected to decrease slightly in 2017 with lower production at all three fields. High upfront capital costs associated with offshore drilling encourages the maximization of production out of existing wells, leading to high decline rates. However, while during the next decade production from these fields is expected to decline quickly, the increased reserves from associated satellite pools can extend the lives of these projects and the associated production from these pools will slow the overall rate of decline.
In May 2017, proponents of the West White Rose Extension Project announced that the project will be proceeding. As a result, the project has been included in CAPP’s forecast for the first time with startup targetted in 2022. In addition, first oil from a fourth major oil field, Hebron, is expected in late 2017. Overall production will be set to increase until 2024 as production from these projects ramp up (Figure 2.2). After 2024 production is expected to decline steadily through to the end of the outlook.
Future production levels could rise higher than forecast in the outlook depending on the pace and timing of new projects and exploration. Production from recent discoveries are currently not included in CAPP’s Atlantic Canada production forecast due to their early stages of evaluation.
TABLE 2.2 ATLANTIC CANADA PROJECTS AND RECENT DISCOVERIES
Producing Field Year Discovered
First Oil Cumulative Production to December 31, 2016
(million barrels)
Estimated Recoverable Reserves
(million barrels)
Hibernia Hibernia South Extension
1979 Nov 1997 1,002 (61% of reserves) 1,644
Terra Nova 1984 Jan 2002 391 (77% of reserves) 506
White Rose North Amethyst South White Rose Extension North Amethyst Hibernia West White Rose
1984 Nov 2005May 2010Mid 2015Sep 2015
2022
269 (56% of reserves) 479
Hebron 1980 Late 2017 n/a 707
Recent Discoveries Year Discovered
First Oil Estimated Recoverable Reserves
(million barrels)
Mizzen 2009 no estimate 102 (heavy oil)
Harpoon Jun 2013 no estimate Under evaluation
Bay du Nord Aug 2013 2020+ 300 to 600 (light oil)
Source: Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB)
Crude Oil Forecast, Markets & Transportation 6
2.4 WESTERN CANADA PRODUCTION
All of the oil sands resources and the major conventional oilfields are concentrated in Western Canada. Consequently, this area provides almost 95 per cent of total production in Canada and practically all the anticipated future growth. Conventional sources comprised 34 per cent of this production in 2016 and are expected to continue to contribute around 28 per cent through the outlook period. Although the Fort McMurray wildfires noticeably impacted 2016 production, oil sands production will be responsible for overall growth of 1.3 million b/d from 3.6 million b/d in 2016 to 4.9 million b/d by 2030 (Figure 2.1). This forecast equates to an average growth in production in Western Canada of 93,000 b/d year over year.
TABLE 2.3 WESTERN CANADA CRUDE OIL PRODUCTION
million b/d 2016 2020 2025 2030
Conventional (including pentanes/condensate)
1.24 1.22 1.24 1.26
Oil sands (bitumen & upgraded)
2.40 3.12 3.35 3.67
Total Western Canada 3.64 4.34 4.59 4.93
*Total may not add up due to rounding.
2.4.1 CONVENTIONAL
In 2016, there was 1.2 million b/d of conventional production, of which 261,000 b/d (21 per cent) was pentanes & condensate. While the crude oil component declined by 117,000 b/d, this decline was partially offset by increased production of pentanes & condensate. As a result, overall conventional production declined 76,000 b/d (6 per cent) versus 2015.
Combined production from Alberta and Saskatchewan accounts for over 90 per cent of conventional production with the remainder coming from British Columbia, Manitoba and the Northwest Territories. The forecast for total conventional production in Western Canada through to 2030 is shown in Figure 2.3. With crude oil prices rebounding from a low of US$26 seen in early 2016, conventional crude oil drilling is recovering in 2017. Conventional crude oil production is not expected to return to the highs of 2014 but will remain fairly stable through the outlook period. Increases in crude oil drilling are not expected to be robust enough to compensate for the loss of production resulting from well decline rates and the lower levels of drilling in the past two years. The production outlook for pentanes & condensate that is on average 90,000 b/d higher than was forecast in 2016 should, however, stabilize overall conventional production at around 1.26 million b/d in 2030.
FIGURE 2.2 NEWFOUNDLAND AND LABRADOR PRODUCTION
0
50
100
150
200
250
300
350
400
20302028202620242022202020182016201420122010200820062004200220001998
thousand barrels per day
Actual Forecast
June 2016 Forecast
Hibernia
Terra Nova
White Rose
North Amethyst
7 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
Alberta
In 2016, Alberta produced 444,000 b/d of conventional crude oil production or 46 per cent of the Western Canada total. The province also produced 85 per cent of total pentanes & condensate, or 222,000 b/d. The Alberta Energy Regulator (AER) estimates that Alberta has 1.6 billion barrels of established conventional crude oil reserves remaining as of December 31, 2016. Use of horizontal drilling coupled with multi-stage hydraulic fracturing techniques are helping producers raise recovery rates for many oilfields by providing economic access to “tight” oil reserves, most notably in the Cardium, Viking, Duvernay and Montney plays in Alberta.
Decreasing costs is also a key driver behind the higher drilling rates. The Petroleum Services Association of Canada (PSAC) estimates drilling and completion costs in the Cardium are lower by 6 per cent in the winter of 2017 compared to the previous winter. Casing and cement costs have dropped by around 22 per cent.
Manitoba, British Columbia, NWT
Manitoba produced 40,000 b/d of crude oil in 2016, equal to 3 per cent of total conventional production from Western Canada. Strong horizontal drilling and hydraulic fracturing activity also revived production in southwestern Manitoba where the outer extensions of the Bakken formation and Three Forks oil plays are located. However, production is still forecast to decline to the end of the outlook in 2030.
Since 2005, condensate production has been steadily comprising a larger part of the total conventional production in British Columbia. In 2016, of the 61,000 b/d of conventional production, 38,000 b/d were pentanes & condensate. The Montney formation lies in both Alberta and British Columbia. It is primarily a natural gas play but has promising light oil potential and a significant amount of natural gas liquids. Producers are expected to continue targeting liquid-rich areas in the Montney.
There is little production currently from the Northwest Territories and no exploratory development to report. However, the last assessment of the unconventional oil-in-place reported 46 billion barrels for the Bluefish Shale and 145 billion barrels for the Canol Shale. The amount of recoverable crude oil has not been estimated to date but this could be a significant resource if even only 1 per cent of the in-place resource can be recovered.
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
2030202820262024202220202018201620142012201020082006
Pentanes/Condensate
million barrels per day
Actual Forecast
Saskatchewan
Manitoba
BC & NWT
Alberta
June 2016 Forecast
2017
FIGURE 2.3 WESTERN CANADA CONVENTIONAL PRODUCTION
Crude Oil Forecast, Markets & Transportation 8
Saskatchewan
In 2016, Saskatchewan produced 459,000 b/d or 47 per cent of the total Western Canada conventional crude oil production. Pentanes & condensate production is negligible. The combination of horizontal drilling and multi-stage fracturing has led to essentially a second phase of production of light tight oil in three main formations. The Bakken formation in southeast Saskatchewan is the most developed of these, followed by the Viking and Lower Shaunavon formations. Drilling is expected to increase in 2017 as resource plays for some producers become more economically viable at higher prices. Companies have also successfully reduced operating costs significantly. If productivity and efficiency gains can be maintained, producers can be more competitive. Saskatchewan production is forecast to initially decline but eventually recover to 2016 production levels, or 461,000 b/d of crude oil by 2030.
2.4.2 OIL SANDS
This latest forecast for oil sands production is relatively unchanged from the 2016 outlook, increasing by 1.3 million b/d from 2016 to reach 3.7 million b/d by 2030 (Table 2.4). For comparison, over 6 million b/d of oil sands production has been approved to date (including approved projects that have proceeded to production). However, not all of the approved projects are expected to be operating by the end of the forecast period. Additional projects are also expected to proceed to the approval stage.
TABLE 2.4 OIL SANDS PRODUCTION
million b/d 2016 2020 2025 2030
Mining 1.03 1.41 1.43 1.51
In situ 1.37 1.71 1.92 2.16
Total* 2.40 3.12 3.35 3.67
*Total may not add up due to rounding.
The oil sands resources are situated almost entirely in Alberta and are delineated by three deposits. These regions, referred to as the Athabasca, Cold Lake and Peace River deposits are shown in Figure 2.4. The AER estimated at year-end 2016 there are 165 billion barrels of established reserves, of which 32 billion barrels, or 19 per cent is considered recoverable by mining and 133 billion barrels or 81 per cent can be recovered using in situ techniques.
The AER estimates 2016 capital costs for a 100,000 b/d mining project to range from $9 to $11 billion and supply costs to range from US$65 to US$80 WTI equivalent per barrel. In comparison, a 30,000 b/d in situ steam-assisted gravity drainage (SAGD) project is estimated to cost from $750 million to $1.35 billion with supply costs that range from US$30 to US$50 WTI equivalent per barrel. These supply cost estimates illustrate the challenges of developing oil sands projects in a lower price environment and the vulnerability such projects have to policies that increase costs and impair relative competitiveness.
FIGURE 2.4 OIL SANDS REGIONS
Edmonton
Calgary
Lloydminster
PeaceRiver
FortMcMurray
AthabascaDeposit
Cold LakeDeposit
Peace RiverDeposit
CAPP’s latest oil sands forecast grows from 2.4 million b/d to 3.7 million b/d (Figure 2.5). Mining production grows from 1.0 million b/d in 2016 to reach 1.5 million b/d in 2030. In situ development is the primary driver of growth, expanding from 1.4 million b/d currently and reaching 2.2 million b/d by the end of the outlook. All oil sands projects will need to pay out in the longer term in order to attract investment but in situ projects require less upfront capital than mining projects and incremental production can be added in smaller phases. Although 2016 production was impacted by the Fort McMurray forest fires there was no fundamental infrastructure damage, so 2017 production is set to rebound sharply. Generally, the forecast has a higher rate of growth up to 2020 than in the latter years, which is supported by projects that have recently been completed or are already under construction.
9 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
There is slower growth anticipated further out in the
forecast due to: longer term price uncertainty; the
impact of burgeoning U.S. shale supplies on the global
market; and the impact of federal and provincial
climate change policies on relative competitiveness.
Canadian producers are also wary of protectionist
policies that may emanate from the U.S.
Upgrading
The production volumes from oil sands projects are
shown by combining raw bitumen production and
upgraded crude production from integrated projects.
By volume, there is generally a yield loss associated
with the upgrading process that converts mined
bitumen into upgraded crude oil. The yield losses
associated with upgrading volumes from oil sands
projects without associated upgraders is incorporated
in the calculation of the supply volumes discussed
in the following section. Refer to Appendix A.1 for
detailed production data.
Since Nexen idled the upgrader at its Long Lake
project in July 2016, there are currently no in situ
projects with integrated upgrader facilities. Some
in situ volumes from Suncor’s Firebag and MacKay
River projects can be upgraded at the Suncor
upgrader a! liated with its Millennium mine project
but in general, the smaller size of in situ projects are
not economically conducive for the joint location of a
full upgrader.
The following is a list of the existing integrated mining
and upgrading projects:
• Athabasca Oil Sands Project (AOSP) which
includes Muskeg River Mines and Jackpine
Mine.
• Canadian Natural Horizon Project.
• Suncor Steepbank and Millennium Mine.
• Syncrude Mildred Lake Mine and Aurora Mine.
0
1
2
3
4
5
6
2030202820262024202220202018201620142012201020082006
million barrels per day
Actual Forecast
June 2016 Forecast
In Situ
Mining
2017
FIGURE 2.5 WESTERN CANADA OIL SANDS PRODUCTION
Crude Oil Forecast, Markets & Transportation 10
Imperial’s existing Kearl mine, and Suncor’s Fort Hills mine, which is slated for operations by the end of 2017, are both stand-alone mines with no associated upgrading facilities. Partial upgrading may be employed at some stage, however this technology has not been developed on a commercial scale to date although its potential is promising. The crude oil produced by full upgrading of bitumen is light and may compete with the increasing volumes of light U.S. shale production but partial upgrading could produce a medium or heavy crude that would not require the addition of diluent for blending to transport through pipelines. There would be cost savings resulting from the removal of the diluent cost as well as a reduction in the pipeline capacity required to move the same volume of bitumen production.
Regulations
On December 9, 2016, the federal government and all provinces except Saskatchewan signed the Pan-Canadian Framework to meet the federal government’s 2030 target of a 30 per cent reduction in GHG emissions. The Pan-Canadian Framework requires all provinces and territories to have a carbon pricing scheme in some form by 2018. Provinces that fail to enact a provincial carbon pricing scheme in this timeframe will be subject to federal regulations. To date, there has been no legislation introduced on the federal carbon pricing scheme.
The Alberta government enacted new climate change regulations including a carbon tax that is applied across all sectors starting January 1, 2017. Natural gas produced and consumed on site by conventional oil and gas producers will be exempt from the carbon levy until January 1, 2023. The oil sands will be subject to a legislated emissions limit of 100 megatonnes (Mt) per year under the Oil Sands Emissions Limit Act.
In February 2017, Environment and Climate Change Canada (ECCC) published a discussion paper on a clean fuel standard aimed at trimming annual emissions of carbon dioxide by 30 Mt by 2030 over and above cuts that would be achieved through existing programs. The standard would apply to a broad range of fuels and cover emissions by industries, homes, and buildings as well as transportation.
2.5 WESTERN CANADA SUPPLY
Crude oil supply refers to the crude oil that is delivered to the end-use market. CAPP is forecasting 1.5 million b/d of growth in Western Canada crude oil supplies by 2030 (Figure 2.6), which is very similar to last year’s outlook. Conventional supplies are expected to decline by 86,000 b/d from 901,000 b/d in 2016 to 815,000 b/d by 2030. Oil Sands Heavy supply is forecast to increase by 1.45 million b/d from 2.38 million b/d in 2016, reaching 3.84 million b/d by 2030. Upgraded Light supply increases by 163,000 b/d from 631,000 b/d to reach 794,000 b/d in 2030.
The conventional production in Appendix A.1 reports domestic sources of diluent, which is included in the heavy supply volumes reported in Appendix A.2. On a volumetric basis, the Western Canada supply forecast reported in Appendix A.2 is greater than the sum of the conventional and oil sands production because of the addition of imported diluent volumes that are required for blending. Western Canada oil supply represents the total of Conventional Light, Conventional Heavy, Upgraded Light, and Oil Sands Heavy crude oil. The Oil Sands Heavy category includes upgraded heavy sour crude oil, SynBit and DilBit. The Upgraded Light category includes light crude oil volumes produced from both bitumen and conventional heavy oil upgraders.
Both conventional heavy crude oil and oil sands bitumen that is not upgraded must be diluted by blending with a lighter hydrocarbon to enable flow through a pipeline.
Pentanes & condensates are the main source of diluent, and when used, result in a heavy crude oil mixture known as “DilBit.” Imports of condensate compensate for the shortfall between demand for use in blending and domestic supply. Other bitumen volumes are diluted with upgraded light crude oil, resulting in a heavy crude oil known as “SynBit.” Blending for DilBit requires approximately a 70:30 bitumen to condensate ratio while the blending ratio of SynBit is approximately 50:50. Raw bitumen and “RailBit,” which has a reduced diluent requirement, can be transported by rail. CAPP’s forecast includes relatively small volumes of RailBit or raw bitumen being transported under the assumption that pipelines are being built. In the absence of new pipelines however, the increased supply would once again look to rail to reach markets.
11 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
In 2016, roughly 440,000 b/d in total of imported condensates, upgraded crude oil, as well as quantities of butane were needed to supplement the condensate supply originating from natural gas wells in Western Canada. CAPP’s forecast is not constrained by the availability of condensate imports as new sources of condensate are assumed to be made available to meet market requirements. New technology such as partial upgrading can also serve to reduce diluent requirements.
Table 2.5 shows the projections for total western Canadian crude oil supply. The growth will essentially be in heavy crude oil supplies with only minor growth in light crude oil supplies. Refer to Appendix A.2 for more detailed data.
TABLE 2.5 WESTERN CANADA CRUDE OIL SUPPLY
million b/d 2016 2020 2025 2030
Light 1.25 1.32 1.32 1.40
Heavy 2.66 3.36 3.65 4.05
Total Supply* 3.91 4.68 4.97 5.45
*Total may not add up due to rounding.
FIGURE 2.6 WESTERN CANADA OIL SANDS & CONVENTIO NAL SUPPLY
0
1
2
3
4
5
6
2030202820262024202220202018201620142012201020082006
million barrels per day
Actual Forecast
Conventional Light
June 2016 Forecast
Conventional Heavy
Oil Sands Heavy *
Upgraded Light
* Oil Sands Heavy includes some volumes of upgraded heavy sour crude oil and bitumen blended with diluent or ugpraded crude oil.2017
Crude Oil Forecast, Markets & Transportation 12
2.6 CRUDE OIL PRODUCTION & SUPPLY SUMMARY
Canadian production is forecast to grow by 1.27 million b/d by 2030, increasing from 3.85 million b/d in 2016 to 5.12 million b/d in 2030. Western Canada will be the primary source of supply and future production growth. In Eastern Canada, although the Hebron project is expected to start up at the end of 2017, overall production from this region will enter long-term decline within the outlook.
• Eastern Canada’s contribution increases to 307,000 b/d in 2024 but is forecast to fall to 186,000 b/d by 2030.
• Western Canada oil sands production grows by 1.3 million b/d from 2.4 million b/d in 2016 to 3.7 million b/d in 2030.
• Western Canada conventional crude oil production, contributes 884,000 b/d on average throughout the outlook.
• Pentanes & condensate production from Western Canada have grown markedly in recent years and the outlook reflects an uplift in this production given gas producers’ desire to continue to target liquids-rich plays. Pentanes & condensate are forecast to be 361,000 b/d in 2030 compared to 261,000 b/d in 2016.
• An incremental 1.5 million b/d of crude oil supply from Western Canada is forecast to enter the global market by 2030, of which over 90 per cent will be heavy crude oil.
• From 2017 to 2020, the growth in supply is projected to be, on average, 5 per cent per annum before falling to a slower average annual rate of growth at 2 per cent from 2021 through 2030.
• Long-term activity and growth is significantly lower compared to the outlook compiled in 2014 when oil prices were over US$100 per barrel.
• Long-term oil sands production growth is being affected by:
o Indications of possible U.S. protectionist policies.
o Federal and provincial climate change policies, which impose constraints on the ability to reduce capital and operating costs.
o Divergent environmental policies between Canada and the U.S.
13 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
AB, BC, SK[553]
OtherWestern Canada 5
OtherAtlantic
Canada 36
PADD V [2,349]
PADD IV [598]
PADD III - Gulf Coast[8,527]
PADD II[3,622]
PADD I - East Coast [1,108]
[2016 total refinery receipts]
Sources: CAPP, CA Energy Commission, EIA, Statistics Canada
ON [330]
QC+ Atlantic Canada [704]
thousand barrels per day
U.S. - Alaska onlyU.S. (excluding Alaska)Other ImportsAtlantic CanadaWestern Canada
Crude oil is processed in refineries where its hydrocarbons are separated and molecules are split apart before being reassembled and blended to manufacture a variety of products including transportation fuels like gasoline, diesel and aviation fuel. Essentially all exports of crude oil supply from Western Canada are destined for the U.S. Figure 3.1 shows the main refinery markets in North America and their sources of crude oil in 2016.
FIGURE 3.1 CANADA AND U.S.: 2016 CRUDE OIL RECEIPTS BY SOURCE
3 CRUDE OIL
MARKETS
Crude Oil Forecast, Markets & Transportation 14
The North American crude oil market has undergone a significant transformation in recent years with the emergence of light crude oil production from shale plays located throughout the U.S. However, the U.S. remains the primary destination for Canada’s crude oil supplies and significant opportunities are still available that would increase the volumes being sold to this market. The growth in Canadian production is forecast to be mainly heavy crude oil from oil sands, while U.S. domestic production will be predominately light crude oil. The U.S. refineries that have made the investment in technology to process heavy crude oil will prefer to rely on this cheaper feedstock. U.S. domestic light crude oil supplies are no longer captive to U.S. refineries since the removal of restrictions on U.S. crude oil exports in December 2015.
Canada will need multiple pipeline paths to tidewater in order to reach a wider spectrum of global market opportunities. With a pipeline connection to the East Coast, western Canadian crude oil could also displace some foreign crude oil supplies in Eastern Canada and the U.S. East Coast (PADD I). Improved pipeline access to Canada’s West Coast and the U.S. Gulf Coast will be key to the ability of Canadian producers to expand markets.
3.1 CANADA
Refineries located in Canada have 1.9 million b/d of crude oil processing capacity. In 2016, these refineries processed 1.6 million b/d, including 581,000 b/d of imported crude oil by refineries in Eastern Canada.
3.1.1 WESTERN CANADA The eight refineries located in Western Canada have a combined crude oil processing capacity of 683,000 b/d (Table 3.1). In 2016, these refineries processed 553,000 b/d of crude oil that was sourced exclusively from Western Canada. There will be a step increase in demand after the startup of the North West Redwater Partnership (NWR) Sturgeon refinery, Canada’s first new refinery in 30 years. At a price tag of $8.5 billion, Phase 1 is designed to process up to 50,000 b/d of blended bitumen, and is scheduled for startup at the end of 2017. The timing and future for the remaining two phases, which would each process 50,000 b/d of blended bitumen, is uncertain.
TABLE 3.1 REFINERIES IN WESTERN CANADA BY PROVINCE
Owner Location
Crude Oil Processing Capacity
(b/d)
ALBERTA
Imperial Strathcona 191,000
Husky Lloydminster 29,000
Suncor Edmonton 142,000
Shell Scotford 100,000
North West Redwater Partnership
Sturgeon County +50,000 (expected in late 2017)
Alberta Subtotal: (4 refineries + 1 in construction)
462,000 + 50,000
BRITISH COLUMBIA
Chevron (sale to Parkland Fuels announced in April to be finalized by end 2017)
Burnaby 55,000
Husky Prince George 12,000
British Columbia Subtotal: (2 refineries) 67,000
SASKATCHEWAN
Federated Co-operatives Regina 135,000
Gibson Moose Jaw 19,000
Saskatchewan Subtotal: (2 refineries) 154,000
TOTAL 683,000 + 50,000
Proposals for three different export refineries to be based in British Columbia (BC) are in the concept stage. Under two of these proposals, bitumen feedstock would be delivered by rail to the refinery and converted into refined products for export to Asia. Kitimat Clean Ltd. proposes to build a heavy oil refinery near Kitimat that would process 400,000 b/d of bitumen into gasoline, aviation fuel and diesel for export, at an estimated cost of $22 billion. In October 2016, the proponent requested a temporary suspension of the federal environmental assessment of the project due to funding concerns.
15 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
Pacific Future Energy Corp. (PFEC) is proposing to build a bitumen refinery between Terrace and Kitimat and is working closely with local First Nations. The refinery is estimated to cost between $12 and $14 billion and would have the capacity to process 200,000 b/d of “neat” bitumen, which contains less than 2 per cent diluent. As part of the plan, PFEC anticipates building an Alberta-based Diluent Recovery Unit (DRU) to extract the diluent from delivered bitumen blends and resell it back into the Alberta market prior to transporting NeatBit to the refinery. The proponents reported production could begin in 2023 if construction was able to start in the summer of 2019. In October 2016, it was announced that a review panel to be appointed by the federal government will conduct the environmental assessment for the project.
A third proposal, by Eagle Spirit Energy, envisages upgrading bitumen either in northern Alberta or northeastern BC before sending the light upgraded crude oil through a pipeline for export from Grassy Point, located just north of Prince Rupert.
On May 12, 2017, the Government of Canada introduced Bill C-48, the proposed Oil Tanker Moratorium Act. This legislation prohibits oil tankers carrying crude oil from stopping, loading and unloading in northern BC. Other related petroleum products included are: bitumen, bitumen blends, partially upgraded bitumen, synthetic crude oil, condensate, No. 4 fuel oil, No. 5 fuel oil, No. 6 fuel oil and gas oils The area covered would extend from the northern tip of Vancouver Island all they way to the BC-Alaska border, including Haida Gwaii.
The proposed moratorium could be an obstacle for Eagle Spirit as presently proposed, and potentially the other proposals depending on their final product slates.
3.1.2 EASTERN CANADA
There are eight refineries in Eastern Canada, located in Ontario, Québec and Atlantic Canada. These refineries primarily process light crude oil and provide a combined crude oil refining capacity of 1.2 million b/d (Table 3.2)
In 2016, about 264,000 b/d or 80 per cent of total crude oil feedstock for Ontario refineries was served by western Canadian crude oil. Since late 2015, refineries in Québec have had access to Western Canada supplies via the Enbridge Line 9 pipeline. In an April 2017 investor presentation, Suncor noted its coker project at its Montréal refinery as a potential opportunity for post 2019, which would lead to an increase in heavy oil demand in this market.
While some of the refineries located in Atlantic Canada have rail access to western Canadian crude supplies, the higher cost of receiving light crude oil by rail compared to pipeline today puts western Canadian crude supplies at a disadvantage to foreign imports, as currently WTI (North American) crude prices are close to parity with Brent crude prices (global). Imports of U.S. light oil has displaced the majority of imports of offshore oil in this market.
TABLE 3.2 REFINERIES IN EASTERN CANADA BY PROVINCE
Owner Location
Crude Oil Processing Capacity
(b/d)
ONTARIO
Imperial Nanticoke 113,000
Imperial Sarnia 119,000
Shell Sarnia 75,000
Suncor Sarnia 85,000
Ontario Subtotal: (4 refineries) 392,000
QUÉBEC
Suncor Montréal 137,000
Ultramar Québec City 230,000
Québec Subtotal: (2 refineries) 367,000
ATLANTIC CANADA
Irving Saint John, NB 300,000
North Atlantic Refining
Come by Chance, NFLD 115,000
Atlantic Canada Subtotal: (2 refineries) 415,000
TOTAL 1.174 million b/d
Crude Oil Forecast, Markets & Transportation 16
If additional pipeline infrastructure is built to the East Coast, i.e. Energy East (see section 4.5.2), there would be an opportunity to capture a portion of the 415,000 b/d market represented by the Atlantic refineries currently served by imported crude.
3.2 UNITED STATES
Canada is the largest foreign supplier of crude oil to the U.S. and will likely remain so for the foreseeable future because these countries are natural trading partners due to their geographic proximity. Essentially all Canadian crude oil exports in 2016, totaling 3.1 million b/d, were to the U.S. Looking ahead, U.S. domestic production is expected to continue to rise if crude prices remain at current levels or higher. Although the growth in Western Canada supplies is mostly heavy crude oil, as opposed to the light crude oil produced from U.S. shale, competition has intensified as Canada’s upgraded light crude oil is a similar crude type to U.S. shale production.
The U.S. Department of Energy divides the 50 states into five market regions termed Petroleum Administration of Defense Districts or PADDs (Appendix C). These PADDs were originally created in World War II to help allocate fuels derived from petroleum products. Today, this delineation continues to be used when reporting regional U.S. crude oil market data.
3.2.1 PADD I (EAST COAST)
The U.S. East Coast market consists of nine refineries with a combined crude processing capacity of 1.3 million b/d. These refineries process primarily light crude oil.
In 2016, of the total 1.1 million b/d crude oil feedstock, almost 80 per cent was sourced from foreign suppliers (Figure 3.2). In comparison, in 2014 and 2015, foreign sources comprised only 60 per cent as a higher differential between WTI and Brent crude prices made deliveries of U.S. light production via rail more competitive. Today U.S. crude oil delivered by rail is less attractive compared to imports of waterborne crude.
In 2016, imported crude oil included 243,000 b/d from Canada, of which 116,000 b/d was primarily heavy crude oil from Western Canada and 126,000 b/d was light crude oil from Atlantic Canada. New pipeline infrastructure to the East Coast would increase western Canadian producers’ opportunity to serve both Atlantic Canada and PADD I. Assuming all other imports could be displaced, this would represent an incremental market opportunity to western Canadian producers in PADD I of 640,000 b/d, over and above current levels. The majority of this market, however, is comprised of light crude oil and Canadian producers must compete with growing light tight U.S. crude oil production.
FIGURE 3.2 2016 PADD I: FOREIGN SOURCED SUPPLY BY TYPE AND DOMESTIC CRUDE OIL
U.S. Domestic( 227 )
Light Sweet*( 451 )
Light/MediumSour
( 222 )
Heavy( 208 )
Total refining capacity = 1,300 thousand barrels per day
* Includes small volumes of Medium SweetSource: EIA
17 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
TABLE 3.3 RAIL OFFLOADING TERMINALS IN EASTERN CANADA AND PADD I
Operator LocationCapacity
(thousand b/d)Scheduled In-Service Description
Eastern Canada
Imperial (refinery) Nanticoke, ON 20 Op. since 2013
Irving (refinery) Saint John, NB 145 Expansion op. since 2014
Suncor (refinery) Montréal, QC 30 Op. since Q4 2013
Valero (refinery) Québec City, QC 60 Op. since Aug 2013
Eastern Canada Total Existing Capacity 255,000 b/d
PADD I
PBF Energy (refinery)
Delaware City, DE 170 (130 light/40 heavy)
Operating since Feb 2013; expanded Aug
2014
Both light and heavy crude oil unloading capacity. Light oil double loop track for two 100-car unit trains.
Axeon Specialty Partners (refinery)
Savannah, GA 9**16 tank cars per day of heavy crude; expandable
up to 32)
Operating since Jan 2014
Crude oil that is shipped by rail to Savannah could move to Paulsboro via backhauls on waterborne vessels.
Westville Eagle Point (near Paulsboro), NJ
44**66 cars / day
Operating since Jan 2012
Can unload 66 cars/day using 22 offload spots or a unit train every 2 days.
Axeon Specialty Partners (refinery)
Paulsboro, NJ small volumes Unit train capable
Operating since 2014 Unit train capability is being contemplated.
Buckeye Partners, L.P.
Perth Amboy, NJ 60-80 104-car unit train/day
Operating since Q3 2014
Light crude; possibly handle heavy in the future.
Buckeye Partners, L.P.
Albany, NY n/a Operating since Nov 2012; converted to
product service Q4 2016
Multi-year agreement with Irving refinery.
Global Partners Albany, NY 160 (estimated to be operating at 100)
Operating since 2011 Light crude oil receipts; seeking permit for facility to heat crude oil. Phillips 66 has a 5 year contract for 50,000 b/d.
Eddystone Rail Company (Enbridge JV)
Philadelphia, PA 80**one 118-car unit train;
expandable to 2 unit trains (160,000+ b/d)
Operating since April 2014
A crude-by-rail-to-barge facility. First train received on May 3, 2014. Exclusive long-term contract with Bridger Logistics for existing capacity. Transport Bakken crude.
Philadelphia Energy Solutions (refinery)
Philadelphia, PA 280
four 104-car unit trains/day
Operating since Oct 2013; expanded Oct
2014
A crude-by-rail-to-barge facility. Terminal started operation on October 23, 2013 and was expanded from 2 unit trains to 4 on October 28, 2014.
Plains All American Pipeline (PAAP)
Yorktown, VA 60 Operating since Dec 2013
First 98-car unit train received on December 30, 2013. Up to 800 trains per year can be unloaded with up to 104 rail cars per train.
PADD I Total Existing Capacity 863,000 b/d
Crude Oil Forecast, Markets & Transportation 18
3.2.2 PADD II (MIDWEST)
With 4.0 million b/d of crude oil refining capacity, the Midwest accounts for 22 per cent of U.S. total capacity. Since 2012, a number of refineries have made significant investments in upgrades that increased their ability to process heavy crude oil. These refineries are highly reliant on Canada for their heavy crude oil feedstock requirements and will remain so for the foreseeable future as the existing pipeline network is well connected to most of these refineries.
The Midwest is currently Canada’s largest market. In 2016, Western Canada supplied this market with 2.2 million b/d, which was equal to 98 per cent of all foreign imports to this region and around 60 per cent of its refineries’ demand. Heavy crude oil supplies totaled almost 1.6 million b/d (Figure 3.3). Although the region is already quite saturated with heavy crude supplies, deliveries from Western Canada could rise from current levels if planned refinery upgrades proceed (Table 3.4).
The Midwest plays a significant role in determining crude oil prices because the largest commercial tank farm in the U.S. is located in this region. As most recently reported in September 2016 by the EIA, over 77 million barrels of working storage is located in Cushing, Oklahoma. Cushing is the main trading hub for U.S. crude oil and is also the delivery point for New York Mercantile Exchange (NYMEX) traded futures contracts.
FIGURE 3.3 2016 PADD II: FOREIGN SOURCED SUPPLY BY TYPE AND DOMESTIC CRUDE OIL
U.S. Domestic ( 1,415 )
LightSweet*( 277 )
Light/Medium
Sour ( 360 )
Heavy( 1,568 )
Total refining capacity = 3,992 thousand barrels per day
* Includes small volumes of Medium SweetSource: EIA
The EIA reports receipts into PADD II in excess of those attributable to refineries in the region. This is because of volumes that are delivered into storage and then distributed later to other locations, including refineries in PADD III.
The primary market hubs within PADD II are located at Clearbrook, Minnesota; Wood River-Patoka, Illinois area and Cushing, Oklahoma. See Appendix C refinery map for locations.
TABLE 3.4 REFINERY UPGRADE PROJECTS IN PADD II
Operator LocationCurrent Capacity
(thousand b/d)Scheduled In-Service
Estimated Cost
(US$ million) Description
BP/Husky Toledo, OH 160 Completed Jul 2016
Feedstock optimization project. The refinery is now able to process approximately 65,000 b/d of heavy crude oil from the Sunrise oil sands project.
Husky Lima, OH 160 2019(originally
2017)
300 Modifications to coker and other processing units to increase ability to process heavy crude oil by up to 40,000 b/d.
CHS McPherson, KS
100 Completed Feb 2016
555 Expanded capacity to 100,000 b/d from 85,000 b/d and increased heavy crude oil processing capacity to 50% with installation of new delayed coker.
19 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
3.2.3 PADD III (GULF COAST)
There are 50 refineries located in the Gulf Coast market that have a combined crude oil processing capacity of 9.4 million b/d, which represents more than half of the U.S. total. The vast majority of this capacity is located in two coastal states, Louisiana and Texas.
The Gulf Coast market, with an estimated heavy oil processing capacity of over 2 million b/d that is potentially accessible over land, has long been recognized as an ideal market for the growing supplies from Western Canada with the potential to absorb all the forecasted growth in heavy crude oil supplies.
In 2016, foreign imports of crude oil totaled 3.4 million b/d, which was comprised of relatively minimal volumes of light crude oil (Figure 3.4). Venezuela, supplying 693,000 b/d, and Mexico, supplying 557,000 b/d, were the top suppliers of heavy crude oil into the region. Although Canadian deliveries to this region have increased in recent years as some additional pipeline infrastructure has gone into service, Canada is in third place supplying 333,000 b/d of the heavy crude oil demand.
FIGURE 3.4 2016 PADD III: FOREIGN SOURCED SUPPLY BY TYPE AND DOMESTIC CRUDE OIL
U.S. Domestic( 5,168 )
Light Sweet*( 115 )
Light/MediumSour ( 1,055 )
Heavy( 2,189 )
Total refining capacity = 9,380 thousand barrels per day
* Includes small volumes of Medium SweetSource: EIA
Seaway and TransCanada’s Gulf Coast extension pipelines have allowed crude oil at Cushing, Oklahoma to move south to the refineries in Louisiana and Houston. However, constraints remain on the initial pipeline segments out of Western Canada that connect to this trading hub. If the TransCanada Keystone XL project were to be constructed, it would represent the most direct route for western Canadian crude oil to reach this market. The Enbridge Line 3 replacement project would also provide valuable additional capacity upstream to eventually connect to the Seaway pipelines and to this market.
3.2.4 PADD IV (ROCKIES)
There are 15 refineries in PADD IV with a combined crude oil processing capacity of 693,000 b/d. All imports into this market are sourced from Western Canada and represented 45 per cent of the refining demand in this market in 2016 (Figure 3.5). With no reported refining expansions on the horizon, this region does not provide any likely expansion opportunities for Western Canada crude oil supplies.
FIGURE 3.5 2016 PADD IV: FOREIGN SOURCED SUPPLY BY TYPE AND DOMESTIC CRUDE OIL
U.S. Domestic( 330 )
Light Sweet*( 38 )
Light/Medium Sour (24 )
Heavy( 206 )
Total refining capacity = 693 thousand barrels per day
* Includes small volumes of Medium SweetSource: EIA
Crude Oil Forecast, Markets & Transportation 20
3.2.5 PADD V (WEST COAST)
The Rocky Mountains separate PADD V from the rest of the U.S. and this geographic isolation has affected the development of crude oil supply sources to the region. These refineries receive U.S. domestic crude oil supplies from California and Alaska and also have access to global crude oil through marine shipments.
There is 2.9 million b/d of crude oil processing capacity located in the region. In 2016, foreign imports accounted for half of the crude oil feedstock demand (Figure 3.6). This share will likely grow to replace the declining production from Alaska.
FIGURE 3.6 2016 PADD V: FOREIGN SOURCED SUPPLY BY TYPE AND DOMESTIC CRUDE OIL
U.S. Domestic - Alaska ( 473 )
Other U.S. Domestic
( 712 )Light
Sweet*( 223 )
Light/MediumSour ( 546 )
Heavy( 394 )
Total refining capacity = 2,907 thousand barrels per day
* Includes small volumes of Medium SweetSource: EIA
Although there are refineries in four states located in PADD V, including Alaska and Hawaii, it is Washington and California that comprise the main current and future prospects for western Canadian crude oil in the region.
Washington
There are five refineries located in Washington that provide a combined crude oil processing capacity of 634,000 b/d. Most of the crude feedstock arrives by tanker from Alaska and elsewhere. From its peak level of around 2 million b/d in 1988, Alaskan production has declined to roughly a quarter of that level falling to 489,500 b/d in 2016. Washington refineries will continue to become increasingly dependent on foreign imports although rail provides some access to North Dakota’s crude oil production. The Trans Mountain pipeline delivers western Canadian crude oil to this market.
California
California dominates PADD V in both crude oil production and refining capacity. There are 14 refineries located in California that contribute a combined refining capacity of 1.9 million b/d. Almost all of the refineries are located near the coast in the Los Angeles and San Francisco Bay areas. There is no direct pipeline access to California from producing areas outside of the state. Therefore, as Alaskan crude oil declines, an opportunity arises to process more crude oil from North Dakota and potentially from Canada. Kinder Morgan’s federally approved Trans Mountain pipeline expansion project would allow western Canadian crude to be better connected to the West Coast where crude oil could then be loaded on to tankers to serve these refineries. In 2016, California imported 872,000 b/d of which 361,000 b/d was heavy crude oil imported primarily from Ecuador and Colombia as well as smaller volumes from other more distant suppliers. Given its proximity to California, exports off the west coast of Canada could conceivably displace heavy crude oil imports from other existing suppliers.
Table 3.5 lists the rail offloading terminals for markets on the West Coast.
21 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
TABLE 3.5 RAIL OFFLOADING TERMINALS IN WESTERN CANADA & PADD V
Company LocationCurrent Capacity (thousand b/d)
Scheduled In-Service Description
Western Canada
Chevron (refinery) - pending finalization of sale to Parkland Fuels by end 2017
Burnaby, BC 8 Operating since 2013
Western Canada capacity subtotal 8,000 b/d
Washington
Shell (refinery) Anacortes, WA +50 TBD Applied for permits
Tesoro (refinery) Anacortes, WA 50 Operating since 2012
BP (refinery) Cherry Point/Blaine, WA 60 Operating since Dec 2013
Phillips 66 (refinery) Ferndale, WA 30 Expansion operating since Dec 2014
Currently receiving manifest trains; applied for permits for expansion
US Oil (refinery) Tacoma, WA 30 Operating since 2012 Unit train capable
US Development Group Grays Harbour, WA - Gave up option on land lease Apr 2016
Applied for permits
Westway Grays Harbour, WA +27 TBD Applied for permits
Tesoro/Savage Port of Vancouver, WA +120 (expandable to 280)
Late 2017 Applied for permits
Global Partners of Massachusetts
Port Westward/Calskanie, WA
65 (expandable to 130)
Operating since Q4 2012 24 trains per month; expandable to 50
Washington capacity subtotal 235,000 b/d; potential for additional 197,000 b/d
California
Alon USA Bakersfield, CA manifest; +Expansion to 150
Operating 2016
Heavy and light crude oil capacity
Plains All American Bakersfield, CA 65 Operating since Dec 2014
Valero (refinery) Benicia, CA + 70 2016 western Cdn crude + US
Phillips 66 (refinery) Santa Maria, CA + 41 2016
California capacity subtotal 65,0000 b/d; potential for additional 261,000 b/d
TOTAL 300,000 b/d; potential for additional 458,000 b/d
Crude Oil Forecast, Markets & Transportation 22
3.3 INTERNATIONAL
On a global scale, any claims that new technology will render crude oil obsolete or that renewables will be able to displace fossil fuels in the foreseeable future appear to be greatly exaggerated. Undoubtedly, the energy landscape is expected to change in the longer-term. However, elimination of fossil fuels from the energy mix is unlikely as energy demand will continue to grow to fuel the higher levels of economic activity and improve the living standards in the world’s emerging economies.
According to the International Energy Agency’s (IEA) World Energy Outlook 2016 report, global primary energy demand will increase by 31 per cent from 2014 to 2040. Fossil fuels will still comprise 74 per cent of global primary energy demand in 2040 with oil expected to supply 27 per cent.
Growth in global oil demand is concentrated in Asian markets. Table 3.6 shows forecasted oil demand in major Asian markets. The combined demand growth from China and India of 10.1 million b/d is equal to over 90 per cent of the projected world demand increase from 2015 to 2040.
According to the IEA, China will become the world’s largest importer of crude oil by 2020 with India rising to second by 2035. Figure 3.7 shows the changing global net import needs. China and India represent significant growth opportunities thus market diversification will remain a priority for Canadian producers. U.S. net import needs are forecast to shrink but significant heavy crude oil imports from Canada are expected to grow while U.S. domestic light oil is exported.
TABLE 3.6 TOTAL OIL DEMAND IN MAJOR ASIAN COUNTRIES
million b/d 2015 2020 2030 2040 2015 to 2040
Growth
China 11.0 12.6 14.3 15.1 +4.1
India 3.9 5.0 7.1 9.9 +6.0
Japan 3.9 3.3 2.6 2.1 -1.8
World 92.5 95.9 99.8 103.5 +11.0
Source: IEA World Energy Outlook 2016, New Policies Scenario
FIGURE 3.7 GLOBAL NET OIL IMPORTS: 2015 TO 2040
0
2
4
6
8
10
12
14
2040203020202015
UnitedStates
OECDEurope
JapanIndiaChina
million barrels per day
Source: Derived from IEA data. IEA World Energy Outlook 2016, New Policies Scenario
3.4 MARKETS SUMMARY
The oil market landscape for western Canadian crude oil producers is constantly evolving. CAPP forecasts an additional 1.5 million b/d of supplies coming from Western Canada by 2030. The combined regional opportunities in Canada, the U.S. and globally can reasonably be expected to absorb these incremental supplies.
The U.S. Gulf Coast market represents a large and important opportunity given its overall size and the ability of the refineries in the region to process the type of heavy crude oil produced in Western Canada. Eastern Canada, California and Washington, also represent opportunities for expanded markets in North America for Canadian crude oil. PADD II is essentially saturated with western Canadian and domestic U.S. supplies however, increased deliveries to this market will be significant as market hubs in the region facilitate transhipment and the largest U.S. tank farm is located in Cushing, Oklahoma. If built, proposed pipeline projects will also enable large volumes to be transported to tidewater and reach additional international markets.
23 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
Additional transportation infrastructure to tidewater needs to be developed to connect the growing crude oil supplies originating from Western Canada to global refining markets. A number of new major pipeline projects have been proposed that together would form a pipeline network that would allow delivery of crude oil to Canada’s West Coast, East Coast and U.S. Gulf Coast (Figure 4.1) for refining or further transport on marine tankers. Only with better market access can Canadian crude oil resources compete globally and receive full value.
FIGURE 4.1 EXISTING AND PROPOSED CANADIAN & U.S. CRUDE OIL PIPELINES
Portland
Montréal
Québec City Saint John
Sarnia
St. Paul
Salt Lake City
HoustonSt. James
New Orleans
Crane
Freeport
Edmonton
AnacortesBurnaby
TransCanada Keystone
Alberta Clipper Expansion
TransMountain
Ozark
Enbridge
Mid
Vall
ey
Hardisty
Shell Ho-Ho
Express
Platte
Spearhead South
Spearhead North + Spearhead North Twin
Superior
WoodRiver
Cromer
Clearbrook
Guernsey
TransCanadaKeystone XL
Kinder MorganTM Expansion
Kitimat
MustangS. Access Extension
Patoka
Seaway & Seaway Twin
TransCanada Gulf Coast
Enbridge Line 9
Lima
Warren
Westover
Southern Access ExpansionTransCanada Energy East
Flanagan South
Bakken Expansion
Flanagan Chicago
Capl
ine
ETCO
P
Minnesota
N. Dakota System
Rang
elan
d
Bow
Riv
er
Line 5
Pegasus
Pony
White Cliffs
BasinCenturion
Portland-Montréal
Canadian and U.S. Oil PipelinesEnbridge Pipelines and connectionsto the U.S. Midwest
Spectra Express/Platte
Kinder Morgan Trans Mountain
TransCanada KeystoneProposed pipelines to the West Coast
Existing / Proposed pipelines to the E. Canada
Existing / Proposed pipelines to PADD III
Expansion/Reversal to existing pipeline
El Paso
Longhorn
Midland
Casper
Express
Port Arthur
BP
KOCH
Dakota Access
Diamond
Memphis
Cushing
TRANSPORTATION4
Crude Oil Forecast, Markets & Transportation 24
The cost of crude oil in any region is a function of the type of crude and the transportation costs incurred to deliver the crude from production areas. Pipelines are the preferred mode of transporting large volumes of crude oil for long distances over land, given the inherent economies of scale associated with this method of transportation. However, with the current pipeline system now at capacity, use of rail to transport crude oil is again rising. As approved pipelines are built, use of rail would tend to decline.
4.1 CRUDE OIL PIPELINES EXITING WESTERN CANADA
Existing pipelines used for exporting crude oil from Western Canada are currently at or near capacity. The nameplate design capacity is 4.0 million b/d. However, the estimated available capacity for Canadian crude oil exiting Western Canada on the major pipeline systems is only 3.3 million b/d after operational downtime, downstream constraints, and the capacity allocated to refined petroleum products (RPP) as well as U.S. Bakken crude oil that share pipeline capacity is considered (Table 4.1).
TABLE 4.1 MAJOR EXISTING CRUDE OIL PIPELINES EXITING WESTERN CANADA
Pipeline In ServiceOutside Diameter
SizeDistance
(km)
Average Annual
Capacity (thousand b/d)
2016 Annual Throughput
(thousand b/d)
Estimated* Annual Available Capacity for Canadian Crude
Oil Exiting WCSB (thousand b/d)
Enbridge Mainline
Operating since 1950 Various pipelines - See Table 4.3
Various pipelines - See
Table 4.3
2,851 2,527 2,307
Kinder Morgan Trans Mountain
Operating since Oct 1953
24”
36”
30”
1,147
827
150
170
300 316 250
Enbridge Express
Operating since 1997 24” 1,265 280 216 225
TransCanada Keystone
Operating since 2010
since 2010
since Feb 2011
since Jan 2014
since Aug 2016
P1: 36” (converted)
P1: 30”
P2: 36”
P3a: 36”
P3b: 36 (Houston Lateral)
4,700
864
2,592
468
700
76
591 524 561
Total 4,022 3,583 3,343
*Notes for estimating available capacity for Canadian crude oil to exit Western Canada on the major pipelines:
Enbridge Mainline = design capacity x 95% for operational downtime & downstream constraints minus estimated RPP capacity as well as estimates for US Bakken moved on this system
Trans Mountain = design capacity minus estimate of RPP moved = 300-50 = 250
Express = design capacity x 80% (adjusted for crude type moved, historical operational downtime, and downstream constraints)
Keystone = design capacity x 95% (adjusted for crude type moved and historical operational constraints)
25 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
The available supply of western Canadian crude oil in 2016 was 3.9 million b/d, which exceeded the capacity available on major pipeline systems to transport this crude oil. Some of this volume supplies refineries in Alberta and Saskatchewan and may utilize regional pipelines or trucks. In addition, transport by rail tank cars is reported at about 100,000 b/d. So, without any of the new pipeline projects proposed, rail transport would likely significantly increase in order to transport growing supplies.
An additional 2.89 million b/d of pipeline capacity would be available from four pipeline proposal projects that are being developed. This is the total combined capacity from Enbridge’s Line 3, Kinder Morgan’s Trans Mountain Expansion, TransCanada’s Keystone XL and TransCanada’s Energy East Pipeline (Table 4.2). Combined, these projects would offer considerable flexibility to the overall system as they are intended to serve different markets.
The next sections describe both the existing and proposed pipeline systems categorized by destination market.
4.1.1 ENBRIDGE MAINLINE
The Enbridge Mainline is a multi-pipeline system with a current capacity to transport 2.85 million b/d of refined products and crude oil from Western Canada, Montana, and North Dakota to markets in Western Canada, the U.S., and Ontario. The Mainline connects to several pipelines: Line 9 at Sarnia, Ontario; the Minnesota Pipeline at Clearbrook, Minnesota; Spearhead South and Flanagan South at Flanagan, Illinois; Chicap at Patoka Illinois; Mustang at Chicago, Illinois and Toledo at Stockbridge, Michigan. The Mainline has experienced significant apportionment, whereby demand exceeded available capacity and shippers were curtailed in the volumes they could ship on the Mainline. Consequently, shippers were required to seek less desirable alternatives to transport some of their supplies.
TABLE 4.2 PROPOSED CRUDE OIL PIPELINES EXITING WESTERN CANADA
Pipeline Outside Diameter Size Distance (km)
Target In Service
Capacity (thousand b/d)
Enbridge Line 3 Restored 36” 1,659 2019 +370
Kinder Morgan Trans Mountain Expansion
36”
30”
24”
1,184
987 (new)
3.6 x 2 (new)
193 (reactivated)
End 2019 +590
TransCanada Keystone XL 36” 1,897 2020+ +830
TransCanada Energy East 42” 4,516
(new mainline, converted lines (3,000 km) + 2 laterals
2021+ +1,100
Total Proposed Additional Capacity 3,583 +2,890
Crude Oil Forecast, Markets & Transportation 26
Enbridge - Bakken Shippers
Crude oil production in the North Dakota Bakken region rose dramatically from an average of 236,000 b/d in 2010 to over 1.1 million b/d in 2015. The lower price environment in 2016 reduced drilling activity, resulting in a slight fall in production to 987,000 b/d. However, the expectation is that higher crude oil prices in the future will lead to increased exploration and new production growth in the region. The North Dakota System and the Bakken Pipeline System have been developed to accommodate the existing and planned growth.
Enbridge’s North Dakota System, including the Bakken Expansion Pipeline, gathers light crude oil from Western Canada, Montana and North Dakota for delivery to the Berthold Rail Project and the Enbridge Mainline.
In February 2017, Enbridge and Marathon finalized an agreement to acquire a 49 per cent equity stake in the Bakken Pipeline System, which consists of two projects – the Dakota Access Pipeline (DAPL), and the Energy Transfer Crude Oil Pipeline (ETCOP). DAPL is a new pipeline that started service in May 14, 2017 and delivers Bakken production to Patoka, Illinois while ETCOP extends from Patoka to the Sunoco Terminal in Nederland, Texas.
Enbridge Mainline Expansion Projects
There are six pipelines that comprise the Enbridge Mainline upstream of Superior, Wisconsin (Table 4.3). These pipelines have a combined capacity of 2.85 million b/d exiting Western Canada. Line 3 is one of the primary pipelines that comprise Enbridge’s Mainline system but requires extensive maintenance and is currently restricted to a capacity of 390,000 b/d. The Line 3 Replacement Program will replace the original pipeline and restore Line 3 to its original capacity of 760,000 b/d.
Beyond Superior, the Enbridge Mainline has a capacity of 2.45 million b/d provided by Line 5, Line 6 and Line 14 and the Southern Access Pipeline. These pipelines connect to a number of other pipelines that serve as market extensions of the Enbridge Mainline system. The principal markets of the Enbridge Mainline are the U.S. Midwest and Central Canada.
Enbridge Line 3 Replacement Program
The proposed new Line 3 replacement pipeline will be able to transport 760,000 b/d, which was the original design capacity of the existing pipeline. This project will be essential to ensure continued service required by refiners in Minnesota, neighboring states, Eastern Canada and the Gulf Coast (see page 27).
TABLE 4.3 ENBRIDGE MAINLINE SYSTEM: UPSTREAM SUPERIOR
Enbridge Pipeline Outside Diameter Pipe Size
Distance (km)
Target In Service
Capacity (thousand b/d)
Line 1 18”/20” 1,767 Operating since 1950 237
Line 2 24”/26” 1,774 Operating since 1957 442
Line 3 34” 1,767 Operating since 1968 390
Line 3 Replacement 36” 1,660 2019 +370
Line 4 36”/48” 1,770 Operating since 2002 796
Line 65 20” 504 Operating since 2010 186
Alberta Clipper (Line 67)
Original
Phase 1 Expansion
Phase 2 Expansion
36” 1,790
Operating since 2010
Operating since 2014
Operating since 2015
800
450
120
230
Total Existing Capacity 2,851
27 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
Hardisty
Regina
Superior
ENBRIDGE LINE 3 REPLACEMENT PROGRAM (L3RP)
2014 2015 2016 2017 2018 2019
Nov 5 • Application �led with NEB.
Jul 20 • Application to Minnesota Dept. of Commerce �led.Jul 1 • Minnesota Public Utilities Commission (MPUC) deems application complete; starts regulatory process.
Nov 30 - Dec 14 • NEB oral hearings.
Apr 25 • NEB recommends approval subject to 89 conditions.
Nov 29 • Government of Canada approval.
May 16 - Jul 10 • Minnesota Dept. of Commerce initiated comment period on Environmental Impact Statement (EIS).
2019 • Expected in service.
Apr • Minnesota Public Utilities Commission decision expected.
ENBRIDGE LINE 3 REPLACEMENT (L3RP)
COST: US$7.5 Billion (2016 estimate)
CAPACITY: 760,000 b/d (+370,000 b/d)
LENGTH: 1,659 kilometres
DIAMETER: 36 inch replacing 34 inch
Apr 24 • Applications to MPUC for Certi�cate of Need and Route Permit.
AB
SK
MB
ON
ND
MNWI
Crude Oil Forecast, Markets & Transportation 28
4.1.2 KINDER MORGAN TRANS MOUNTAIN
The Trans Mountain system is currently the only crude oil pipeline serving Canada’s West Coast. It originates near Edmonton, Alberta and transports refined products in addition to crude oil to destinations in British Columbia (BC), Washington and the Westridge marine terminal in Burnaby, BC. From Burnaby, crude oil can be loaded for exports to California or the U.S. Gulf Coast or overseas to Asia.
The current capacity on the pipeline system is 300,000 b/d (assuming 20 per cent of the volumes being transported are heavy crude oil). Of this capacity, 221,000 b/d is allocated to refineries that have connections in BC and Washington State, and the remaining 79,000 b/d is allocated to the Westridge Dock terminal for marine exports. With respect to the capacity designated for the marine terminal, 54,000 b/d or 68 per cent is underpinned by firm contracts. Nominations for service on this pipeline have been in apportionment since 2010, and demand for access to this pipeline is expected to grow as additional capacity is made available. See section 4.4.2 for details on the Trans Mountain Expansion project.
4.1.3 ENBRIDGE EXPRESS-PLATTE The Express Pipeline is a 280,000 b/d capacity pipeline that originates at Hardisty, Alberta extending to Casper, Wyoming, where it connects to the Platte Pipeline. The Platte pipeline can transport up to 164,000 b/d from Casper to Guernsey, Wyoming and 145,000 b/d from Guernsey to Wood River, Illinois. The principal market for this pipeline is U.S. PADD IV and the Midwest.
The pipeline was previously owned by Kinder Morgan and was purchased by Spectra Energy in 2013. A merger agreement between Enbridge and Spectra was announced on September 6, 2016. On February 27, 2017 the merger was finalized after clearance by the U.S. Federal Trade Commission (US FTC) and the Canadian Competition Bureau.
4.1.4 TRANSCANADA KEYSTONE
The Keystone pipeline system transports crude oil to refining markets in the U.S. Midwest and U.S. Gulf Coast. The Keystone pipeline system originates at Hardisty, Alberta and extends to Steele City, Nebraska. From this juncture, crude oil can be transported east to terminals in Wood River and Patoka, Illinois or south to Cushing, Oklahoma. At Cushing, the system can extend further through the Gulf Coast Extension pipeline and reach refineries at the Port Arthur and Houston areas in Texas.
The pipeline system began operating in July 2010, initially serving the Wood River/Patoka markets with 435,000 b/d capacity. In February 2011, the Cushing extension came online and the system was expanded to its current capacity for Canadian crude oil of 591,000 b/d. About 545,000 b/d of this capacity is under contracts and thus reserved for committed shippers.
4.2 OIL PIPELINES TO THE U.S. MIDWEST
The U.S. Midwest is the largest market for western Canadian crude oil. The key market hubs in this region are located at Wood River and Patoka in Illinois and at Cushing, Oklahoma. Table 4.4 summarizes the pipelines that deliver Canadian crude oil to the Midwest.
4.2.1 SPECTRA EXPRESS-PLATTE
See Section 4.1.3.
4.2.2 TRANSCANADA KEYSTONE
See Section 4.1.4.
29 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
TABLE 4.4 SUMMARY OF CRUDE OIL PIPELINES TO THE U.S. MIDWEST
Pipeline Originating Point Destination Status Capacity(thousand b/d)
Enbridge Mainline - Line 5 - Line 6 - Line 14/64
Superior, WI various delivery points Operating 1,525 540 667 318
Enbridge Mainline - Southern Access - Original - Phase 1 Expansion - Phase 2 Expansion - Phase 3 Expansion
Superior, WI Flanagan, ILOperatingOp. since Aug 2014Op. since 2015Proposed
935 400 160 375
+265
Enbridge Spearhead North Enbridge Spearhead North Twin Enbridge Spearhead South Enbridge Flanagan South Enbridge Southern Access Ext. Enbridge Mustang
Flanagan, ILFlanagan, ILFlanagan, ILFlanagan, ILFlanagan, ILLockport, IL
Chicago, ILChicago, ILCushing, OKCushing, OKPatoka, ILPatoka, IL
OperatingOp. since Nov 2015OperatingOp. since Dec 2014Op. since Jan 2016Operating
235570193585300100
Koch Minnesota Pipeline Clearbrook, MN Minnesota refineries Operating 465
Spectra Express-Platte Guernsey, WY Wood River, IL Operating 280/145
TransCanada Keystone Hardisty, AB to Steel City, NE
east to Patoka, IL / Wood River, IL or south to Cushing, OK
P1 op. since Jul 2010P2 op. since Feb 2011
591
4.2.3 ENBRIDGE MAINLINE MARKET EXTENSIONS
The Enbridge Mainline has a number of pipeline segments that connect to Chicago and Patoka in Illinois and Cushing, Oklahoma. These include: Spearhead North, Spearhead North Twin, Spearhead South, Flanagan South, Southern Access Extension and Mustang (Table 4.4). Together, these pipelines have almost 2.0 million b/d of capacity but would require expansion to the Mainline system upstream or more rail transportation if there was sufficient market demand that required all these downstream segments to be fully utilized.
4.2.4 MINNESOTA PIPELINE SYSTEM
The Minnesota Pipe Line (MPL) system transports crude oil originating from Western Canada and North Dakota through pipeline connections at Clearbrook, Minnesota and is the primary supply link for Minnesota’s two refineries located in Pine Bend and St. Paul. The MPL system is owned by Minnesota Pipe Line Company, LLC and is operated by Koch Pipeline Company.
The MPL system is comprised of four pipelines that together can transport about 465,000 b/d. The first pipeline in the MPL system was built in 1954; the second was built in the 1970s; the third in the 1980s; and the last pipeline MPL Line 4, formerly known as MinnCan, was constructed in 2008. MPL Line 4 can currently transport about 165,000 b/d. The Minnesota Pipe Line Company has proposed a project to increase capacity of the pipeline by 185,000 b/d to reach 350,000 b/d through the addition of six pump stations and upgrading two existing stations. At an estimated cost of $125 million this project is intended to give MPL the flexibility to shift volumes to its newest pipeline in the event of an outage on other segments of the pipeline system. The construction is targeted for completion in the fourth quarter of 2017.
Crude Oil Forecast, Markets & Transportation 30
4.3 OIL PIPELINES TO THE U.S. GULF COAST
The Gulf Coast represents the most significant opportunity for market growth in North America for Canadian heavy crude oil supplies. Although Saudi Arabia is among the top three exporters to the region, only Venezuela and Mexico rank higher than Canada in terms of the source of heavy crude oil imports into the region. Crude oil is also sourced from other countries including Colombia, Iraq and Brazil. Canada’s ability to supply to the Gulf Coast has increased with new connecting pipelines and expansions to existing pipelines exiting Cushing that were completed in 2014. Additional upstream pipeline infrastructure out of Western Canada to connect to Cushing would further increase Canada’s ability to serve this market region.
4.3.1 TRANSCANADA GULF COAST EXTENSION OF THE KEYSTONE PIPELINE SYSTEM
TransCanada’s Gulf Coast Extension, which is part of its Keystone pipeline system, started delivering crude oil on January 22, 2014. It is also known as the TransCanada Cushing Marketlink pipeline and provides capacity of 700,000 b/d from Cushing, Oklahoma to Port Arthur, Texas. In August 2016, the Houston Lateral pipeline was completed and came online, providing shippers with the option of a delivery point connected to the refining capacity in the Houston area. The Gulf Coast Extension pipeline and the Houston Lateral together form the southern portion of the TransCanada Keystone XL pipeline (see section 4.3.2). The Keystone XL pipeline from Canada will provide an efficient option to deliver incremental Canadian barrels to Cushing for onward delivery to the Gulf Coast as service can be provided by a single system.
4.3.2 TRANSCANADA KEYSTONE XL
See page 32.
4.3.3 ENBRIDGE/ENTERPRISE SEAWAY
The Seaway Pipeline system is jointly owned by Enbridge Inc. and Enterprise Products Partners L.P. and is comprised of two parallel pipelines (Seaway and Seaway Twin). The total system capacity is 850,000 b/d with 400,000 b/d contributed by the Seaway pipeline between Cushing, Oklahoma and the Freeport, Texas area and 450,000 b/d contributed by the Seaway Twin pipeline.
U.S. Gulf Coast market access for western Canadian crude oil has only started to emerge in recent years. The direction of flow on the Seaway pipeline was reversed on May 17, 2012 in order to allow crude oil to be transported from the bottlenecked Cushing, Oklahoma hub to the Gulf Coast refineries near Houston. The original capacity of the reversed pipeline was 150,000 b/d but was increased in January 2013 to 400,000 b/d through pump station modifications and additions. Seaway Twin was brought into service on December 1, 2014.
4.3.4 CAPLINE REVERSAL
The Capline pipeline currently transports crude oil northbound from St. James, Louisiana to Patoka, Illinois. It is a pipeline system with 1.2 million b/d capacity. If reversed, the pipeline could move western Canadian crude oil to refineries in Louisiana but additional infrastructure upstream of the origination point would be required to connect their sources of supply. Marathon operates the pipeline while Plains All American Pipeline is the majority owner; the other part owner is BP P.L.C.
TABLE 4.5 SUMMARY OF CRUDE OIL PIPELINES TO THE U.S. GULF COASTPipeline Originating Point Destination Status Capacity
(thousand b/d)
Seaway Seaway Twin Line
Cushing, OK Freeport, TX Expansion op. since Jan 2013Op. since Dec 2014
400450
TransCanada Keystone XL Cushing extension of Keystone Gulf Coast extension of Keystone
Hardisty, ABSteele City, NECushing, OK
Steele City, NECushing, OKNederland, TX
Presidential Permit Granted Jan 2017Op. since Feb 2011 (Segment 1)Op. since Jan 2014 (Segment 2)
+830-
700
Capline Reversal Patoka, IL St. James, LA Proposed +1,200
31 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
Nederland
Hardisty
Patoka
Steele City
Baker
CushingWood River
Houston
4.3.2 TRANSCANADA KEYSTONE XL
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
TRANSCANADA KEYSTONE XL
COST: C$10.85 Billion (2014 estimate) US$8 Billion (2014 estimate)
CAPACITY: 830,000 b/d
LENGTH: 526 kilometres
DIAMETER: 36 inches
CONTRACTS: 380,000 b/d (Currently updating)
Keystone Pipeline: Hardisty toSteele City, Wood River & Patoka
Gulf Coast Project: Cushing toNederland/Houston
Proposed Keystone XL: Hardisty to Steele City
Mar 11 • NEB recommends approval with 22 conditions.
Apr 22 • Government of Canada approval.
Jan 18 • President Obama denies application citing insuf�cient time to review new route.
Apr 18 • U.S. State Dept. suspends regulatory process.
2020+ • Earliest estimate for in service.
Mar 24 • Presidential permit received from U.S. State Dept.
Feb 27 • Facilities application �led with the NEB.
Sep 15 - Oct 2 • Oral hearing at NEB.
Nov 10 • U.S. State Dept. requests reroute to avoid ecologically sensitive area in Nebraska.
Nov 6 • Obama Administration rejects application.
Jan 26 • Reapplication for U.S. Presidential permit.
Feb 16 • Application �led with Nebraska Public Service Commission (PSC).
Aug 7 - 11 • Nebraska PSC scheduled hearing.
Nov 23 • Nebraska PSC decision deadline.
AB
SK
MB
MTND
SD
NB
KS
OK
TX
MIIL
Crude Oil Forecast, Markets & Transportation 32
Nederland
Hardisty
Patoka
Steele City
Baker
CushingWood River
Houston
4.3.2 TRANSCANADA KEYSTONE XL
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
TRANSCANANDA KEYSTONE XL
COST: C$ 10.85 Billion (2014 estimate) US$ 8 Billion (2014 estimate)
CAPACITY: 830,000 b/d
LENGTH: 526 kilometres
DIAMETER: 36 inches
CONTRACTS: 380,000 b/d (Currently updating)
Keystone Pipeline: Hardisty toSteele City, Wood River & Patoka
Gulf Coast Project: Cushing toNederland/Houston
Proposed Keystone XL: Hardisty to Steele City
Mar 11 • NEB recommends approval with 22 conditions.
Apr 22 • Government of Canada approval.
Jan 18 • President Obama denies application citing insuf�cient time to review new route.
Apr 18 • U.S. State Dept. suspends regulatory process.
2020+ • Earliest estimate for in service.
Mar 24 • Presidential permit received from U.S. State Dept.
Feb 27 • Facilities application �led with the NEB.
Sep 15 - Oct 2 • Oral hearing at NEB.
Nov 10 • U.S. State Dept. requests reroute to avoid ecologically sensitive area in Nebraska.
Nov 6 • Obama Administration rejects application.
Jan 26 • Reapplication for U.S. Presidential permit.
Feb 16 • Application �led with Nebraska Public Service Commission (PSC).
Aug 7 - 11 • Nebraska PSC scheduled hearing.
Nov 23 • Nebraska PSC decision deadline.
AB
SK
MB
MTND
SD
NB
KS
OK
TX
MIIL
33 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
4.4 OIL PIPELINES TO THE WEST COAST OF CANADA
The Kinder Morgan Trans Mountain pipeline is currently the only pipeline transporting crude oil from Alberta to the West Coast. There is significant interest in building new pipeline capacity to the West Coast where it can be offloaded for marine transport to reach a variety of markets including California, the U.S. Gulf Coast and Asia (Table 4.6).
4.4.1 ENBRIDGE NORTHERN GATEWAY
Northern Gateway was a proposed pipeline project with an initial capacity of 525,000 b/d that would have extended from Bruderheim, Alberta to Kitimat, BC. In June 2014, the project was approved by the Governor in Council subject to 209 conditions. In July 2016, the Federal Court of Appeal overturned the approval of the project with the finding that the government had failed in its duty to adequately consult with Aboriginal groups. On November 29, 2016, the federal government officially rejected the project and directed the National Energy Board (NEB) to dismiss the application for the project.
4.4.2 TRANS MOUNTAIN EXPANSION
See page 34.
4.5 OIL PIPELINES TO EASTERN CANADA
The size of the refinery market in Eastern Canada is almost double that of Western Canada. In 2016, refineries in Eastern Canada processed over 1 million b/d of crude oil of which 581,000 b/d originated from foreign sources. The current pipeline capacity to this market is 300,000 b/d, while the proposed Energy East project would add 1.1 million b/d of pipeline connnectivity for western Canadian producers to supply Atlantic refineries and for exports off the East Coast and overseas (Table 4.7).
4.5.1 ENBRIDGE LINE 9
The Line 9 pipeline extends the Enbridge Mainline system from Sarnia, Ontario to Montréal, Québec. This pipeline was recently reversed allowing western Canadian producers to serve more eastern markets. In August, 2013, the portion from Sarnia, Ontario to North Westover, Ontario started flowing east with an initial capacity of 152,000 b/d. The second portion from North Westover, Ontario to Montréal, Québec started flowing oil in December 2015. The fully operating pipeline currently has a capacity of 300,000 b/d.
4.5.2 TRANSCANADA ENERGY EAST
TransCanada Energy East is a proposed pipeline system that could provide western Canadian crude oil access to markets in Eastern Canada, U.S. East Coast, U.S. Gulf Coast and other international destinations via a marine terminal in New Brunswick. About 995,000 b/d is underpinned by firm contracts for an average term of 19 years (see page 35).
TABLE 4.6 SUMMARY OF CRUDE OIL PIPELINES TO THE WEST COAST OF CANADA
Pipeline Originating Point Destination Status Capacity(thousand b/d)
Kinder Morgan Trans Mountain Edmonton, AB Burnaby, BC Operating 300
Kinder Morgan Trans Mountain Expansion Approved by Gov of Canada - End 2019 target in service
+590
Crude Oil Forecast, Markets & Transportation 34
Edmonton
Line 1 (350,000 b/d: Light Crude + RPP)
Line 2 (540,000 b/d: Heavy Crude)Edson
JasperDar�eld
Abbotsford
Anacortes
Ferndale
Kamloops
HopeBurnaby
4.4.2 TRANS MOUNTAIN EXPANSION
2013 2014 2015 2016 2017 2018 2019 2020
Dec 16 • Facilities application �led with NEB.
May 17 • Ministerial panel assigned to engage communities and Aboriginal groups. May 19 • NEB recommends approval subject to 157 conditions.
Nov 29 • Government of Canada approval.
Jan 11 • B.C. Environmental Assessment Of�ce (EAO) grants EA certi�cation subject to 37 conditions.
May 30 • Final investment decision (FID) made. Successful IPO announced.
Dec • Proposed start date.
TRANS MOUNTAIN EXPANSION
COST: C$7.4 Billion (March 2017 estimate)
CAPACITY: 890,000 b/d (350,000 b/d existing + 540,000 b/d additional)
LENGTH: 1,183 kilometres (987 new + 193 reactivated + 2 x 3.6 km)
DIAMETER: 36 inches
CONTRACTS: 707,500 b/d (15 shippers: 15/20 yr terms)
New Pipeline
Trans Mountain Puget Sound
Reactivated Pipeline
Existing Active Pipeline
Apr 2 • NEB determined application complete.
Aug 21 • Steven Kelly evidence struck from record.Sep 17 - Jan 8 • Excluded period to allow hearing panel to acquire information that was stricken from record.
Sep • Planned construction start.
AB
BC
WA
HintonHargreaves
Black Pines
35 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
Moosomin
Hardisty
Montréal
Lévis
Cacouna
Saint John
Trois Rivières
4.5.2 TRANSCANADA ENERGY EAST
2014 2015 2016 2017 2018 2019 2020 2021
Oct 30 • Application �led with NEB.
Dec 17 • Revised application �led. Québec port removed.
Jan 9 • New NEB panel assigned (Don Ferguson, Carole Malo, Marc Paquin).Jan 27 • New panel ruling all decisions by previous panel voided.
Feb 3 • NEB direction to consolidate application.
TRANSCANADA ENERGY EAST
COST: C$19.3 Billion (May 2016 estimate)
CAPACITY: 1.1 Million b/d
LENGTH: 4,521 kilometres (1,427 new + 92 new laterals + 3,002 converted)
DIAMETER: 42 inches
CONTRACTS: 995,000 b/d (845,000 b/d Québec/Saint John, 150,000 b/dsubject to ongoing discussion on delivery point options)
Existing (Converted) Pipeline Segments
New Pipeline Segments
Tank Terminal
May 10 - 31 • NEB seeking comments on list of issues.
May 17 • Consolidated application �led.
Q4 • Earliest estimate for in service.
Q3 • Originally proposed construction start.
AB
SKMB
ONQC
NB
Crude Oil Forecast, Markets & Transportation 36
TABLE 4.7 SUMMARY OF CRUDE OIL PIPELINES TO EASTERN CANADA
Pipeline Originating Point Destination Status Capacity(thousand b/d)
Enbridge Line 9 9A 9B
Sarnia, ON Sarnia, ON North Westover, ON
Montréal, QC North Westover, ON Montréal, QC
Operating Op. since Aug 2013 Op. since Dec 2015
300
TransCanada Energy East Hardisty, AB Québec City, QC / St. John, NB
Proposed - 2021+ +1,100
4.6 DILUENT PIPELINES
Table 4.7 provides a summary of projects that aim to bring diluent supply in order to satisfy the blending component needed to transport the growing supply of heavy crude oil produced in Western Canada by pipelines. In comparison, rail has minimal diluent requirements.
4.6.1 ENBRIDGE SOUTHERN LIGHTS
The Southern Lights pipeline runs from Manhattan, Illinois to Edmonton, Alberta and has been operating since July 2010. The capacity of the pipeline is 180,000 b/d, of which 162,000 b/d is secured by long-term contracts.
4.6.3 TRANSCANADA GRAND RAPIDS DILUENT
TransCanada plans to build a new diluent line from the Heartland region, near Edmonton, to Fort Saskatchewan, Alberta. The diluent pipeline would have a capacity of 330,000 b/d and is expected to be operating in late 2017.
Keyera Corp. has agreed to acquire a 50 per cent interest in the southernmost portion of the 20-inch diameter Grand Rapids diluent pipeline. The 45-kilometre pipeline will be constructed by Grand
Rapids Pipeline Limited Partnership, an affiliate of TransCanada PipeLines Limited and Brion Energy Corporation. The pipeline will extend from Keyera’s Edmonton Terminal (KET) to TransCanada’s Heartland Terminal near Fort Saskatchewan, Alberta as part of TransCanada’s previously announced Grand Rapids pipeline project. In connection with this agreement, Keyera will be constructing a pump station at KET where the pipeline will connect.
4.6.4 KINDER MORGAN COCHIN SYSTEM
Kinder Morgan’s Cochin system is a multi-product pipeline. In April 2014, the pipeline was removed from ethane-propane service. Since July 2014, the pipeline has been shipping condensate from Kankakee County, Illinois to Fort Saskatchewan, Alberta. The pipeline’s estimated capacity is 95,000 b/d.
TABLE 4.8 SUMMARY OF DILUENT PIPELINES
Pipeline Originating Point Destination Status Capacity(thousand b/d)
Enbridge Southern Lights Flanagan, IL Edmonton, AB Operating 180
Kinder Morgan Cochin Conversion
Kankakee County, IL Fort Saskatchewan, AB Operating since July 2014 95
TransCanada Grand Rapids Heartland, AB Fort Saskatchewan, AB in Construction - late 2017 +330
37 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
TABLE 4.9 RAIL UPLOADING TERMINALS IN WESTERN CANADA
Operator Location Capacity* (thousand b/d)
Scheduled Startup
ALBERTA
Keyera/Enbridge Cheecham 32 Operating since Oct 2013
Cenovus (Ex Canexus) Bruderheim (near Edmonton) 70 Expansion operating since Sep 2014; expandable
Gibson Edmonton 20 Operating since Q3 2015
Keyera/Kinder Morgan Edmonton 40 Operating since Sep 2014
Gibson/USDG Hardisty 120 Operating since Jul 2014
Altex Lynton (Ft. McMurray) 15 Operating
Kinder Morgan/Imperial Sherwood Park (Strathcona County) 210 Operating since Apr 2015; can be expanded to 250
SASKATCHEWAN
TORQ Transloading Bromhead 20 Operating
Plains Kerrobert (70) Startup Nov 2015. As of May 2016, operations temporarily closed
Altex Lashburn 60 Expansion operating
TORQ Transloading Lloydminster 25 Operating;
Crescent Point Stoughton 45 Operating since Feb 2012
Altex Unity 15 Operating
TORQ Transloading Unity 22 Operating
MANITOBA
Tundra Cromer 60 Expansion operating since Q4 2014
TOTAL 754,000 b/d + potential expansions
Note: Facilities with less than 15,000 b/d are not shown
*Estimated capacities based on assumptions for operating hours, available car spots, type of crude oil transported, and contracts in place (if known).
4.7 CRUDE OIL BY RAIL
Rail offers an alternative mode of transportation for crude oil. In May 2016, when the Fort McMurray wildfires impacted production, the number of rail car loadings of crude oil and petroleum products reached its lowest level since 2012. Transportation by rail has since been rebounding, reaching 11,899 carloads in February 2017 (Figure 4.2).
Industry data reported almost 100,000 b/d of western Canadian crude oil was transported to market by rail in 2016, compared to over 180,000 b/d that was transported in 2014. In the first quarter 2017 almost 140,000 b/d were transported by rail.
The current rail loading capacity originating in Western Canada is 754,000 b/d. Table 4.9 lists the rail terminals for uploading crude in Western Canada.
FIGURE 4.2 CANADIAN FUEL OIL AND CRUDE PETROLEUM MOVED BY RAIL: CAR LOADINGS & TONNAGE
Source: Statistics Canada; CANSIM table 404-0002.
thousand tonnes
0
200
400
600
800
1,000
1,200
1,400
1,600
20172016201520142013201220112010 0
3
6
9
12
15
18
21
24
tonnes
rail cars
thousand rail cars
Crude Oil Forecast, Markets & Transportation 38
4.8 TRANSPORTATION SUMMARY
Takeaway capacity currently remains tight for oil producers in Western Canada. Both physical and economic market access is key to the long-term prosperity of the industry and has important implications for the economic health of Canada as a whole.
• Available crude oil supplies to all markets was 3.9 million b/d in 2016.
• The estimated available pipeline capacity for Canadian crude oil on the major pipeline systems originating in Alberta and exiting Western Canada is 3.3 million b/d.
• Western Canadian crude oil also supplies refineries in Alberta and Saskatchewan using regional pipelines and trucks.
• Rail provides the means of transportation for supplies that exceed the major pipeline capacity exiting Western Canada and the demand of Alberta and Saskatchewan refineries.
• Additional pipeline capacity is urgently needed and a variety of pipeline options will: provide producers with market diversification; ensure continued service required by existing shippers; and improve operational flexibility.
• New crude oil pipeline projects are being developed at a very slow pace given the long approval process they face.
The Canadian federal government’s approval of the Trans Mountain Expansion and Enbridge Line 3 projects, as well as a Presidential permit from the U.S. Department of State for Keystone XL, have been encouraging steps forward. Construction, and the placement of these projects into service is urgently needed.
FIGURE 4.4 EXISTING TAKEAWAY CAPACITY FROM WESTERN CANADA VS. SUPPLY FORECAST
0
1.0
2.0
3.0
4.0
5.0
6.0
203020292028202720262025202420232022202120202019201820172016
million barrels per day
Western Canadian Refineries
ExpressTrans Mountain
Enbridge Mainline
Rangeland & Milk River
2017 Western Canadian supply
Capacity shown can be reduced by any extraordinary and temporary operating and physical constraints.
Notes:1) Enbridge capacity adjusted by operational downtime and capacity for RPP and U.S. Bakken crude oil.2) Keystone: adjustment to 95% of nameplate capacity for maintenance downtime.3) Express: contract capacity only due to downstream Platte pipeline constraints.4) Trans Mountain: RPP capacity requirements subtracted from nameplate capacity.5) Rangeland & Milk River: throughput estimated @ 107,000 b/d, which is the maximum realized annual crude oil throughput since 2010.6) Western Canadian re�neries: Re�nery intake in Alberta and Saskatchewan; excludes BC (85% of 616,000 b/d capacity).
Keystone
39 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
GLOSSARYAsphalt plant A facility that processes crude oil into various types and grades of asphalt, ranging from
dust-abatement road oils to highway-grade asphalt, to roofing tar.
API Gravity A specific gravity scale developed by the American Petroleum Institute (API) for measuring the relative density or viscosity of various petroleum liquids.
Barrel A standard oil barrel is approximately equal to 35 Imperial gallons (42 U.S. gallons) or approximately 159 litres.
Bitumen A heavy, viscous oil that must be processed extensively to convert it into a crude oil before it can be used by refineries to produce gasoline and other petroleum products.
Coker The processing unit in which bitumen is cracked into lighter fractions and withdrawn to start the conversion of bitumen into upgraded crude oil.
Condensate A mixture of mainly pentanes and heavier hydrocarbons. U.S. condensate is divided into two broad categories. The first is lease condensate produced at or near the wellhead (either natural gas or crude oil). The second category is plant condensate, also known as NGLs, natural gasoline, pentanes plus or C5+, that remain suspended in natural gas at the wellhead and is removed at a gas processing plant. For purposes of this report, both categories are included in the term ”condensate.” Both categories of condensate are substantially similar in composition but the U.S. EIA arbitrarily defines lease condensate as crude oil and plant condensate as an NGL (pentanes plus). Furthermore, Department of Commerce - Bureau of Industry and Security (BIS) regulations also define lease condensate as crude oil.
Crude oil (conventional) A mixture of pentanes and heavier hydrocarbons that is recovered or is recoverable at a well from an underground reservoir. It is liquid at the conditions under which its volumes is measured or estimated and includes all other hydrocarbon mixtures so recovered or recoverable except raw gas, condensate, or bitumen.
Crude oil (heavy) Crude oil is deemed, in this report, to be heavy crude oil if it has an API of 27º or less. No differentiation is made between sweet and sour crude oil that falls in the heavy category because heavy crude oil is generally sour.
Crude oil (medium) Crude oil is deemed, in this report, to be medium crude oil if it has an API greater than 27º but less than 30º. No differentiation is made between sweet and sour crude oil that falls in the medium category because medium crude oil is generally sour.
Crude oil (synthetic) A mixture of hydrocarbons, similar to crude oil, derived by upgrading bitumen from the oil sands.
Density The mass of matter per unit volume.
DilBit Bitumen that has been reduced in viscosity through addition of a diluent (or solvent) such as condensate or naphtha.
Diluent Lighter viscosity petroleum products that are used to dilute bitumen for transportation in pipelines.
Extraction A process unique to the oil sands industry, in which bitumen is separated from its source (oil sands).
Crude Oil Forecast, Markets & Transportation 40
Feedstock In this report, feedstock refers to the raw material supplied to a refinery or oil sands upgrader.
Integrated mining A combined mining and upgrading operation where oil sands are mined from open pits. project The bitumen is then separated from the sand and upgraded by a refining process.
In situ recovery The process of recovering crude bitumen from oil sands by drilling.
Merchant upgrader Processing facilities that are not linked to any specific extraction project but is designed to accept raw bitumen on a contract basis from producers.
Oil Condensate, crude oil, or a constituent of raw gas, condensate, or crude oil that is recovered in processing and is liquid at the conditions under which its volume is measured or estimated.
Oil sands Refers to a mixture of sand and other rock materials containing crude bitumen or the crude bitumen contained in those sands.
Oil sands deposit A natural reservoir containing or appearing to contain an accumulation of oil sands separated or appearing to be separated from any other such accumulation. The AER has designated three areas in Alberta as oil sands areas.
Oil Sands Heavy In this report, Oil Sands Heavy includes upgraded heavy sour crude oil, and bitumen to which light oil fractions (i.e. diluent or upgraded crude oil) have been added in order to reduce its viscosity and density to meet pipeline specifications.
Open season A period of time designated by a pipeline company to determine shipper interest on a proposed project. Potential customers can indicate their interest/support by signing a transportation services agreement for capacity on the pipeline.
Pentanes plus A mixture mainly of pentanes and heavier hydrocarbons that ordinarily may contain some butanes and is obtained from the processing of raw gas, condensate or crude oil.
PADD Petroleum Administration for Defense District that defines a market area for crude oil in the U.S.
Refined petroleum End products in the refining process (e.g., gasoline). Products
Specification Defined properties of a crude oil or refined petroleum product.
SynBit A blend of bitumen and synthetic crude oil that has similar properties to medium sour crude oil.
Train (manifest) Manifest trains carry multiple cargoes and make multiple stops. These are small group or single car load.
Train (unit) Unit trains carry a single cargo and deliver a single shipment to one destination, lowering the cost and shortening the trip.
Upgrading The process that converts bitumen or heavy crude oil into a product with a lower density and viscosity.
West Texas Intermediate WTI is a light sweet crude oil, produced in the United States, which is the benchmark grade of crude oil for North American price quotations.
41 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
APPE
NDIX
A.1
CA
PP C
ANAD
IAN
CRUD
E OI
L PR
ODUC
TION
FOR
ECAS
T 20
17 –
203
0
thou
sand
bar
rels
per
day
Ac
tual
Fo
reca
stEA
STER
N CA
NADA
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
O
ntar
io1
11
11
11
11
11
11
11
A
tlant
ic P
rovi
nces
121
219
423
126
427
826
727
929
730
628
625
222
721
119
718
5E.
CAN
ADA
CONV
ENTI
ONAL
213
195
232
265
279
268
280
298
307
287
253
228
212
198
186
WES
TERN
CAN
ADA
CONV
ENTI
ONAL
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Ligh
t & M
ediu
m
Alb
erta
327
311
297
291
294
303
313
317
318
312
315
318
322
326
332
B
ritis
h Co
lum
bia
2322
2120
1918
1716
1515
1413
1312
11
Sas
katc
hew
an 1,
222
621
219
419
519
720
020
120
320
721
221
822
423
023
623
8
Man
itoba
4035
3331
3029
2828
2727
2625
2524
24
Nor
thw
est T
errit
orie
s.9
66
65
55
54
44
44
44
Ligh
t & M
ediu
m62
558
555
154
354
555
556
456
857
256
957
658
559
360
360
9
Heav
y
Alb
erta
11
811
411
311
110
510
095
9086
9085
8177
7370
S
aska
tche
wan
2,23
323
522
922
521
921
421
221
321
421
521
521
621
822
022
3He
avy
350
349
342
336
324
314
307
303
300
305
300
297
295
293
293
PENT
ANES
/CON
DENS
ATE
261
298
325
340
352
356
360
364
363
364
365
362
362
363
361
W. C
ANAD
A CO
NVEN
TION
AL
(incl
. con
dens
ates
)1,
237
1,23
21,
219
1,21
91,
221
1,22
61,
231
1,23
41,
235
1,23
81,
241
1,24
41,
250
1,25
91,
262
Note
s:
1. A
tlant
ic C
anad
a pr
oduc
tion
incl
udes
New
foun
dlan
d &
Labr
ador
pro
duct
ion
and
negl
igib
le v
olum
es fr
om N
ew B
runs
wic
k. C
onde
nsat
es/p
enta
nes
from
Nov
a Sc
otia
and
New
Bru
nsw
ick
are
also
add
ed.
2. C
APP
allo
cate
s Sa
skat
chew
an A
rea
III M
ediu
m c
rude
as
heav
y cr
ude.
Als
o 17
% o
f Are
a IV
is >
900
kg/
m3 .
Crude Oil Forecast, Markets & Transportation 42
Tota
ls m
ay n
ot a
dd u
p du
e to
roun
ding
.
Note
s:
** R
aw b
itum
en n
umbe
rs a
re p
rovi
ded
at th
e bo
ttom
of t
he ta
ble
and
do n
ot re
flect
upg
radi
ng. T
he o
il sa
nds
prod
uctio
n nu
mbe
rs a
t the
top
of th
e ta
ble
(as
hist
oric
ally
pub
lishe
d) a
re a
com
bina
tion
of u
pgra
ded
crud
e oi
l and
bitu
men
and
ther
efor
e in
corp
orat
e yi
eld
loss
es fr
om in
tegr
ated
upg
rade
r pro
ject
s. P
rodu
ctio
n fro
m o
ff-si
te u
pgra
ding
pro
ject
s ar
e in
clud
ed in
the
prod
uctio
n nu
mbe
rs a
s bi
tum
en.
WES
TERN
CAN
ADA
OIL
SAND
S (B
ITUM
EN &
UP
GRAD
ED C
RUDE
OIL
)
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Min
ing
1,0
28
1,1
76
1,3
65
1,3
92
1,4
06
1,4
17
1,4
20
1,4
24
1,4
27
1,4
28
1,4
28
1,4
07
1,4
09
1,4
55
1,50
6In
situ
1,3
72
1,5
14
1,6
19
1,6
68
1,7
15
1,7
46
1,7
78
1,8
30
1,8
69
1,9
25
1,9
92
2,0
26
2,0
60
2,1
20
2,1
64
TOTA
L OI
L SA
NDS
2,4
00
2,6
90
2,9
84
3,0
60
3,1
22
3,1
64
3,1
99
3,2
54
3,2
96
3,3
53
3,4
20
3,4
33
3,4
69
3,5
75
3,6
69
W. C
anad
a Oi
l Pro
duct
ion
3,63
73,
923
4,20
34,
278
4,34
34,
389
4,43
04,
488
4,53
14,
591
4,66
24,
677
4,71
94,
834
4,93
2E.
Can
ada
Oil P
rodu
ctio
n21
319
523
226
527
926
828
029
830
728
725
322
821
219
818
6TO
TAL
CANA
DIAN
OIL
PR
ODUC
TION
3,85
04,
118
4,43
54,
543
4,62
24,
657
4,71
04,
786
4,83
84,
878
4,91
54,
905
4,93
15,
032
5,11
8
OIL
SAND
S RA
W B
ITUM
EN**
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Min
ing
1,14
71,
338
1,52
61,
555
1,57
01,
582
1,58
61,
590
1,59
51,
595
1,59
51,
581
1,59
71,
644
1,69
8In
situ
1,39
11,
540
1,64
01,
688
1,73
51,
766
1,79
61,
848
1,88
51,
941
2,00
92,
049
2,08
42,
145
2,18
8TO
TAL
OIL
SAND
S RA
W B
ITUM
EN2,
538
2,87
83,
166
3,24
33,
305
3,34
73,
382
3,43
83,
480
3,53
73,
604
3,63
13,
681
3,79
03,
886
43 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
APPE
NDIX
A.2
CAPP
WES
TERN
CAN
ADIA
N CR
UDE
OIL
SUPP
LY F
OREC
AST
2017
-203
0
Blen
ded
Supp
ly to
Tru
nk P
ipel
ines
and
Mar
kets
thou
sand
bar
rels
per
day
A
ctua
l
Fore
cast
CONV
ENTI
ONAL
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Tota
l Lig
ht a
nd M
ediu
m62
158
154
753
954
155
156
056
456
856
557
258
158
959
960
5Ne
t Hea
vy to
Mar
ket
280
273
265
258
245
234
227
222
219
224
218
215
212
211
210
TOTA
L CO
NVEN
TION
AL90
185
581
279
778
678
578
678
578
678
979
179
580
281
081
5
OIL
SAND
SUp
grad
ed L
ight
(Syn
thet
ic)1
631
719
785
787
777
777
773
769
765
759
751
754
802
798
794
Oil S
ands
Hea
vy 2
2,38
32,
628
2,92
43,
022
3,11
13,
167
3,21
63,
293
3,35
03,
428
3,52
03,
525
3,54
33,
696
3,83
6TO
TAL
OIL
SAND
S AN
D UP
GRAD
ERS
3,01
43,
347
3,71
03,
809
3,88
93,
943
3,98
94,
061
4,11
64,
186
4,27
04,
279
4,34
54,
494
4,63
0
Tota
l Lig
ht S
uppl
y1,
253
1,30
01,
333
1,32
61,
318
1,32
81,
333
1,33
21,
333
1,32
41,
323
1,33
51,
391
1,39
71,
399
Tota
l Hea
vy S
uppl
y2,
662
2,90
23,
190
3,28
03,
356
3,40
13,
443
3,51
43,
569
3,65
13,
738
3,74
03,
755
3,90
74,
046
WES
TERN
CAN
ADA
OIL
SUPP
LY3,
915
4,20
24,
522
4,60
64,
675
4,72
84,
776
4,84
74,
902
4,97
55,
061
5,07
45,
147
5,30
45,
445
Note
s:
1. In
clud
es u
pgra
ded
conv
entio
nal.
2. In
clud
es: a
) im
porte
d co
nden
sate
b) m
anuf
actu
red
dilu
ent f
rom
upg
rade
rs a
nd c
) upg
rade
d he
avy
volu
mes
com
ing
from
upg
rade
rs.
.
Crude Oil Forecast, Markets & Transportation 44
Acronyms API American Petroleum Institute
AER Alberta Energy Regulator
CAPP Canadian Association of Petroleum Producers
EIA Energy Information Administration
FERC Federal Energy Regulatory Commission
IEA International Energy Agency
NEB National Energy Board
PADD Petroleum Administration for Defense District
RPP refined petroleum products
U.S. United States
WTI West Texas Intermediate
U.S. State AbbreviationsAL Alabama
AK Alaska
AZ Arizona
AR Arkansas
CA California
CO Colorado
CT Connecticut
DE Delaware
FL Florida
GA Georgia
ID Idaho
IL Illinois
IN Indiana
IA Iowa
KS Kansas
KY Kentucky
LA Louisiana
ME Maine
MD Maryland
MA Massachusetts
MI Michigan
MN Minnesota
MS Mississippi
MO Missouri
MT Montana
NE Nebraska
NV Nevada
NH New Hampshire
NJ New Jersey
NM New Mexico
NY New York
NC North Carolina
ND North Dakota
OH Ohio
OK Oklahoma
OR Oregon
PA Pennsylvania
SC South Carolina
SD South Dakota
TN Tennessee
TX Texas
UT Utah
VT Vermont
VA Virginia
VI Virgin Islands
WA Washington
WV West Virginia
WI Wisconsin
WY Wyoming
APPENDIX BACRONYMS, ABBREVIATIONS, UNITS AND CONVERSION FACTORS
Canadian Provincial AbbreviationsAB Alberta
BC British Columbia
MB Manitoba
NB New Brunswick
NL Newfoundland & Labrador
NWT Northwest Territories
ON Ontario
QC Québec
SK Saskatchewan
Unitsb/d barrels per day
Conversion Factor1 cubic metre = 6.293 barrels (oil)
45 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS
APPENDIX C CANADIAN AND U.S. CRUDE OIL PIPELINES AND REFINERIES
PADD V
PADD IV
PADD II
PADD III
WA
OR
MT
CO
IANE
NM
ID
UT
NV
CA
AZ
TX
OK
ND
MN
SD
KS
WY
MO
AR
LA
VANCOUVER TO:
Japan - 4,300 miles
Taiwan - 5,600 miles
S.Korea - 4,600 miles
China - 5,100 miles
San Francisco - 800 miles
Los Angeles - 1,100 miles
Port Arthur/Nederland/Beaumont
Artesia
BigSpring
Slaughter
ThreeRivers
Crane
CENTURION
WA
SCA
NA
SPEARHEAD
SOUTH
PONY EXPRESSWHITE CLIFFS
TR
AN
SC
AN
AD
A G
ULF
CO
AS
T
SE
AW
AY
TW
IN
PEGASUS
LakeCharles
SHELL C
HE
VR
ON
PAC
IFIC
EXXONMOBIL
BRIDGETEX
PERMIAN EXPRESS
CRANEHO-HOC
AC
TUS
EXXON
MO
BILK
EY
ST
ON
E
KE
YS
TO
NE
HUSKY
RA
INB
OW
ENBRIDGE NW
PUGET SOUND
BP (Cherry Pt) .............234
Phillips 66 (Ferndale) ...101
Shell (Anacortes)..........137
Tesoro (Anacortes) .......120
TrailStone (Tacoma) .......42
BAKERSFIELD
Kern Oil .....................26
San Joaquin...............14
GREAT FALLS
Calumet ......................25
BILLINGS
CHS (Laurel) ................56
Phillips 66....................60
ExxonMobil ..................60
LOS ANGELES
Alon USA .. . . . . . . . . . . . . . . . . . . . . . . .70
Tesoro (Carson/Wilmington) ... 380
Chevron ................................ 291
PBF ...................................... 155
Phillips 66 ............................ 139
Valero .................................... 85
EDMONTON
Imperial .........................191
Suncor...........................142
Shell ............................. .100
LLOYDMINSTER
Husky asphalt plant .........29
Husky Upgrader...............82
REGINA
Complex ......................................135
MOOSE JAW
Moose Jaw asphalt plant ...............19
WYOMING
Sinclair (Casper) ............................25
Sinclair Oil (Sinclair).......................85
) ..................18
HollyFrontier (Cheyenne) ................52
HOUSTON/TEXAS CITY
PRSI (Pasadena) ........... 100
Marathon (Galveston).... 459
Shell (Deer Park)........... 312
ExxonMobil ................... 561
LyondellBasell .............. 268
Marathon ....................... 86
Valero (2) ................80+225
THREE RIVERS
Valero ............................. 89
CORPUS CHRISTI
CITGO ........................... 157
Flint .............................. 300
Valero ........................... 275
SWEENY
Phillips 66..................... 247
PORT ARTHUR/BEAUMONT
ExxonMobil ...................
Valero ...........................
Total .............................
TYLER
Delek.....................75
OKLAHOMA
Phillips 66 (Ponca City) .........................203
HollyFrontier (Tulsa) .............................125
Coffeyville Res. (Wynnewood) .................70
Valero (Ardmore).....................................86
KANSAS
NEW MEXICO/W. TEXAS
HollyFrontier (Artesia) ...........................100
Alon (Big Spring). ....................................73
BORGER/MCKEE
WRB ............................ 146
Valero .......................... 195
DENVER/COMMERCE CITY
Suncor........................... 98
SALT LAKE CITY
Big West ............. 35
Chevron.............. 53
HollyFrontier ....... 45
Tesoro ................ 63
ST. PAUL
Flint Hills .............339
SUPERIOR
Calume
UPGRADERS
Syncrude (Fort McMurray)................. 465
Suncor (Fort McMurray) .................... 438
Shell (Scotford) ................................. 240
CNRL (Horizon) ................................. 210
PRINCE GEORGE
Husky.............. 12
Tesoro (Gallup)........................................25
Tesoro (El Paso)................................... .135
Tesoro .................102
Canadian and U.S. Crude Oil Pipelines and Refineries - 2017
Dickinson
NORTH DAKOTA
Tesoro (Mandan) ........74
Tesoro (Dickinson) .....20
CHS (McPherson)....................................85
HollyFrontier (El Dorado) ......................135
Coffeyville Res. (Coffeyville) ..................115
re
viR
do
oW
HC
OK
LOUISIANA
Calumet (Shreveport
DAKOTA ACCESS
Diamond
SAN FRANCISCO
Chevron ........................................257
Phillips 66......................................120
Shell ..............................................144
Tesoro ...........................................166
Valero ............................................145
KANSAS
VANCOUVER
Chevron (sold to Parkland Fuels) ......55
20302016
EXISTING PIPELINE CAPACITY 39%
2017
2014
$34BILLION $15
BILLION
ADDITIONAL CAPACITY NEEDED PRICES AND INVESTMENT
Crude oil prices dropped from more
than US$100 per barrel in 2014, due
to a global oversupply of oil. Prices
have recovered somewhat since
early 2016 to almost US$50 per
barrel in May 2017. CAPP estimates
2017 producer capital spending for
oil sands will decline for the third
consecutive year, which reflects a
dramatic change to projects due
to continuing uncertainty in the
long term.
Drilling by conventional crude oil
producers is expected to increase
by 70 per cent compared to 2016,
but would still be 40 per cent
lower than in 2014.
3KEY COMPETITVENESS CHALLENGES FACING CANADA’S OIL INDUSTRY
PRODUCTION AND SUPPLY
Western Canadian crude oil supply accounts for the bulk of Canadian crude oil supply and is forecast to grow from 3.9 million b/d in 2016 to 5.4 million b/d in 2030.
• WESTERN CANADA HEAVY OIL SANDS SUPPLY provides 95 per cent of this growth.
• THE ANNUAL AVERAGE GROWTH IN WESTERN CANADA SUPPLY is projected to be 5 per cent from 2017 to 2020, then slow to an average annual growth rate of 2 per cent through 2030.
• EASTERN CANADA is forecast to contribute up to 307,000 b/d of production by 2024 but then decline steadily.
MARKETS
CAPP forecasts an additional 1.5 million b/d of supplies coming from Western Canada by 2030. The combined regional opportunities in Canada, the U.S. and globally can reasonably be expected to absorb these incremental supplies.
SUPPLY OF WESTERN CANADIAN CRUDE OIL
WILL GROW 39 PER CENT BY 2030 TO 5.4 MILLION BARRELS PER DAY (B/D).
CAPITAL INVESTMENT IN THE OIL SANDS
THE COMBINED DEMAND GROWTH FROM CHINA AND INDIA OF
10.1 MILLION B/D IS EQUAL TO MORE THAN 90 PER CENT
OF THE WORLD DEMAND INCREASE FROM 2015 TO 2040.
Key industry challenges are tempering long-term growth prospects.
1. UNCERTAINTY. Canada’s policies and regulations are becoming increasingly more stringent and costly, resulting in reduced attractiveness for investment.
2. CUMULATIVE IMPACTS OF GOVERNMENT POLICY CHANGES. Developing resources responsibly to help achieve key regulatory, social and environmental outcomes, is important and needs be done in a manner that does not unnecessarily burden industry and risk more jobs.
3. POTENTIAL DIVERGENT POLICIES FROM U.S. COMPETITORS. U.S. producers may not have to face similar policies to those in Canada. Additionally, protectionist policies that may be pursued by the current U.S. administration are also a cause for concern.
SOURCE: IEA World Energy Outlook 2016, New Policies Scenario
FOR INFORMATION CONTACT: (403) 267-1141 / CAPP.CA
PADD V
PADD IV
PADD II
PADD III PADD I
PADD
WA
ORMT
CO
IA
WI
IN
NE
NM
GA
MS
ID
UT
NVCA
AZ
TX
OK
NDMN
SD
KS
WY
NC
KY
SC
IL
MI
MO
AR
AL
OH
TN
LA
VAWVDE
MD
PA
NY
NH
MA
CT
VT
ME
NJ
RI
VANCOUVER TO:Japan - 4,300 milesTaiwan - 5,600 milesS.Korea - 4,600 milesChina - 5,100 miles
San Francisco - 800 milesLos Angeles - 1,100 miles
2016 CANADIAN CRUDE OIL PRODUCTION 000 m3/d 000 b/d
British Columbia 10 61Alberta 457 3,066Saskatchewan 73 461Manitoba 6 40Northwest Territories 1 9
Western Canada 578 3,637Eastern Canada 34 213Total Canada 612 3,850
Major Existing Crude Oil Pipelines carryingCanadian crude oil
Selected Other Crude Oil Pipelines
Crude Refining Capacities as at June 1, 2017(thousand barrels per day)
Petroleum Administration for Defense District
Flanagan PhiladelphiaNewell
Port Arthur/Nederland/Beaumont
ArtesiaBigSpring
Slaughter
ThreeRivers
Crane
FL
CENTURION
WAS
CANA
SPEARHEAD
SOUTH
PONY EXPRESSWHITE CLIFFS
TRANSCAN
ADA G
ULF CO
AST
SEAWAY TW
IN
ENBRIDGE LINE 9
NAI
KTO
NE
PEGASUS
Come by Chance
LakeCharles
St.James
SHELL CHEVRO
NPACIFIC
EXXONMOBIL
BRIDGETEX
PERMIAN EXPRESSCRANE
HO-HOCACTUS
EXXONMOBIL
KEYSTON
E
KEYSTON
E
HUSKY
RAINBO
W
ENBRIDGE NW
Saint John
Montréal
Westover
MONTREAL
VANCOUVERChevron........... 55
PUGET SOUNDBP (Cherry Pt) .............234Phillips 66 (Ferndale) ...101Shell (Anacortes)..........137Tesoro (Anacortes) .......120TrailStone (Tacoma) .......42
BAKERSFIELDKern Oil .....................26San Joaquin...............14
GREAT FALLSCalumet ......................25
BILLINGSCHS (Laurel) ................56Phillips 66....................60ExxonMobil ..................60
LOS ANGELESAlon USA .. . . . . . . . . . . . . . . . . . . . . . . .70Tesoro (Carson/Wilmington) ... 380Chevron ................................ 291PBF ...................................... 155Phillips 66 ............................ 139Valero .................................... 85
EDMONTONImperial .........................191Suncor...........................142Shell ............................. .100LLOYDMINSTERHusky asphalt plant .........29Husky Upgrader...............82
REGINA
Complex ......................................135MOOSE JAWMoose Jaw asphalt plant ...............19
WYOMINGSinclair (Casper) ............................25Sinclair Oil (Sinclair).......................85
) ..................18HollyFrontier (Cheyenne) ................52
OHIOBP-Husky (Toledo)........................160PBF (Toledo).................................170Marathon (Canton) .........................93Husky (Lima)................................160Marathon (Catlettsburg) ...............273
MISSISSIPPI RIVERExxonMobil (Baton Rouge) ...........503PBF (Chalmette)...........................189Marathon (Garyville).....................543Shell (Convent).............................235Shell (Norco) ................................229Valero (Norco) ..............................215Valero (Meraux)............................125Phillips 66 (Belle Chasse).............247Alon (Krotz Springs) .......................74Placid (Port Allen)...........................60
HOUSTON/TEXAS CITYPRSI (Pasadena) ........... 100Marathon (Galveston).... 459Shell (Deer Park)........... 312ExxonMobil ................... 561LyondellBasell .............. 268Marathon ....................... 86Valero (2) ................80+225
ALABAMAHunt (Tuscaloosa) ..........................40Shell (Saraland) .............................85
THREE RIVERSValero ............................. 89CORPUS CHRISTICITGO ........................... 157Flint .............................. 300Valero ........................... 275
SWEENYPhillips 66..................... 247
LAKE CHARLESCITGO ............................. 425Phillips 66....................... 249Calcasieu.......................... 75
PORT ARTHUR/BEAUMONTExxonMobil ....................363
.578Valero ............................335Total ..............................226
SAINT JOHNIrving ...................300
NEW JERSEYPhillips 66 (Bayway)........ 241PBF (Paulsboro) .............. 168Axeon SP (Paulsboro) ........ 74DELAWAREPBF (Delaware City) ........ 190
MEMPHISValero ..................180EL DORADODelek.....................80
TYLERDelek.....................75
DETROITMarathon.......... 132
OKLAHOMAPhillips 66 (Ponca City) .........................203HollyFrontier (Tulsa) .............................125Coffeyville Res. (Wynnewood) .................70Valero (Ardmore).....................................86
KANSAS
NEW MEXICO/W. TEXASHollyFrontier (Artesia) ...........................100Alon (Big Spring). ....................................73
BORGER/MCKEEWRB ............................ 146Valero .......................... 195
DENVER/COMMERCE CITYSuncor........................... 98
SALT LAKE CITYBig West ............. 35Chevron.............. 53HollyFrontier ....... 45Tesoro ................ 63
ST. PAULFlint Hills .............339
SUPERIORCalumet............45
CHICAGOBP ..........................430ExxonMobil ..............236PDV ........................180
SARNIAImperial ............... 119Shell ...................... 73Suncor................... 85NANTICOKEImperial ............... 113
MONTRÉAL/QUÉBECSuncor.................... 137Valero ..................... 230
PENNSYLVANIAMonroe Energy (Trainer)................ 195Phil. Energy Solutions (Phil.).......... 335
WARRENUnited .......... 70
NEWELL, WVErgon............ 23
UPGRADERSSyncrude (Fort McMurray)................. 465Suncor (Fort McMurray) .................... 438Shell (Scotford) ................................. 240CNRL (Horizon) ................................. 210
WOOD RIVERWRB .................................314ROBINSONMarathon..........................231MT VERNONCountrymark.......................28
NEWFOUNDLAND & LABRADORSilver Range (Come by Chance) .......... 115
PRINCE GEORGEHusky.............. 12
Hibernia White Rose
Terra NovaHebron
PIPELINE TOLLS FOR LIGHT OIL (US$ PER BARREL)
Edmonton to Burnaby (Trans Mountain) 2.00 Anacortes (Trans Mountain/Puget) 2.30 Sarnia (Enbridge) 4.50 Montréal (Enbridge) 6.10 Chicago (Enbridge) 4.10 Cushing (Enbridge) 5.25*-6.50 Wood River (Enbridge/Mustang/Capwood) 5.25 USGC (Enbridge/Seaway) 6.30† - 8.85§
Hardisty to Guernsey (Express/Platte) 3.20* Wood River (Express/Platte) 4.90* Wood River (Keystone) 4.40**-5.30 USGC (Keystone/Gulf Coast Ext.) 7.15§ -11.55
USEC to Montréal (Portland/Montréal) 0.50
St. James to Wood River (Capline/Capwood) 1.30
PIPELINE TOLLS FOR HEAVY OIL (US$ PER BARREL)
Hardisty to: Chicago (Enbridge) 4.30 Cushing (Enbridge) 5.45*-6.70 Cushing (Keystone) 6.10**-6.85 Wood River (Enbridge/Mustang/Capwood) 5.85 Wood River (Keystone) 5.05**-6.00 Wood River (Express/Platte) 5.50* USGC (Enbridge/Seaway) 7.00† - 9.05§
USGC (Keystone/Gulf Coast Ext.) 7.80§ - 12.55
Notes 1) Assumed exchange rate = 0.73 US$ / 1C$ (May 2017 average) 2) Tolls rounded to nearest 5 cents 3) Tolls in effect July 1, 2017
* 10-year committed toll**20-year committed toll†First Open Season,15-year, 50,000+ b/d committed volumes§ International Joint Tariff
Tesoro (Gallup)........................................25Tesoro (El Paso)................................... .135
Tesoro .................102
Canadian and U.S. Crude Oil Pipelines and Refineries - 2017
Dickinson
NORTH DAKOTATesoro (Mandan) ........74Tesoro (Dickinson) .....20
CHS (McPherson)....................................85HollyFrontier (El Dorado) ......................135Coffeyville Res. (Coffeyville) ..................115
reviR dooW
HCOK
LOUISIANACalumet (Shreveport) ........ 60
MISSISSIPPIChevron (Pascagoula) ..................330Ergon (Vicksburg)...........................25
DAKOTA ACCESS
ETCO
P
Diamond
SAN FRANCISCOChevron (sold to Parkland Fuels) ....257Phillips 66......................................120Shell ..............................................144Tesoro ...........................................166Valero ............................................145
KANSAS
EXECUTIVE2017SUMMARY
Crude Oil Forecast, Markets and Transportation
CAPP’s annual Crude Oil Forecast, Markets and Transportation report provides a long-term outlook (2017 to 2030) for total Canadian crude oil production and western Canadian crude oil supply, plus key information on markets both existing and potential, and an updated synopsis of the transportation projects that could connect projected supply to various markets.
Canada’s crude oil supply is forecast to grow by 5 per cent per year to 2020 then slow to 2 per cent growth per year to 2030, due to many market uncertainties. The success of Canada’s energy future relies on the ability to overcome these challenges, including low commodity prices, pipeline capacity, industry competitiveness, regulatory uncertainty, and access to new markets.
WESTERN CANADIAN CRUDE OIL SUPPLY IS GROWING BY 1.5 MILLION B/D
Disclaimer: This publication was prepared by the Canadian Association of Petroleum Producers (CAPP). While it is believed that the information contained herein is reliable under conditions and subject to the limitations set out, CAPP does not guarantee the accuracy or completeness of the information. The use of this report or any information contained will be at the user’s sole risk, regardless of any fault or negligence of CAPP.
© Material may be reproduced for public non-commercial use provided due diligence is exercised in ensuring accuracy of information reproduced; CAPP is identified as the source; and reproduction is not represented as an official version of the information reproduced nor has any affiliation.
2016 20301.5MILLION
B/D
2017
CRUDE OIL FORECAST,MARKETS AND TRANSPORTATION
CAPP.CA 2017-0009
The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP’s member companies produce about 80 per cent of Canada’s natural gas and crude oil. CAPP’s associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP’s members and associate members are an important part of a national industry with revenues from oil and natural gas production of about $120 billion a year.
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