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2017 CRUDE OIL FORECAST, MARKETS AND TRANSPORTATION

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Page 1: Crude Oil Forecast, Markets and Transportation … · CAPP’s annual Crude Oil Forecast, Markets and Transportation ... including low commodity prices, ... Crude oil prices dropped

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

Page 2: Crude Oil Forecast, Markets and Transportation … · CAPP’s annual Crude Oil Forecast, Markets and Transportation ... including low commodity prices, ... Crude oil prices dropped

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

Page 3: Crude Oil Forecast, Markets and Transportation … · CAPP’s annual Crude Oil Forecast, Markets and Transportation ... including low commodity prices, ... Crude oil prices dropped

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

Page 4: Crude Oil Forecast, Markets and Transportation … · CAPP’s annual Crude Oil Forecast, Markets and Transportation ... including low commodity prices, ... Crude oil prices dropped

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

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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.

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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

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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

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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

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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.

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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

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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

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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)

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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

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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

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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.

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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

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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.

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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

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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.

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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

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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.

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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

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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

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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

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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.

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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

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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.

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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

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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.

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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

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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)

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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

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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

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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

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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.

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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.

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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).

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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.

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41 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

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Crude Oil Forecast, Markets & Transportation 42

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03,

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43 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

APPE

NDIX

A.2

CAPP

WES

TERN

CAN

ADIA

N CR

UDE

OIL

SUPP

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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

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158

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155

156

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456

856

557

258

158

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vy to

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258

245

234

227

222

219

224

218

215

212

211

210

TOTA

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185

581

279

778

678

578

678

578

678

979

179

580

281

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5

OIL

SAND

SUp

grad

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(Syn

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787

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777

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769

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759

751

754

802

798

794

Oil S

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.

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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)

Page 52: Crude Oil Forecast, Markets and Transportation … · CAPP’s annual Crude Oil Forecast, Markets and Transportation ... including low commodity prices, ... Crude oil prices dropped

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

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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

Page 54: Crude Oil Forecast, Markets and Transportation … · CAPP’s annual Crude Oil Forecast, Markets and Transportation ... including low commodity prices, ... Crude oil prices dropped

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