CRUDE OIL FORECAST, MARKETS AND TRANSPORTATION

Transcription

1 2017 CRUDE OIL FORECAST, MARKETS AND TRANSPORTATION

2 EXECUTIVE2017 Crude Oil Forecast, Markets and Transportation SUMMARY 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. 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. 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 MILLION B/D

3 ADDITIONAL CAPACITY NEEDED EXISTING PIPELINE CAPACITY 39% PRICES AND INVESTMENT Crude oil prices dropped from more than US$100 per barrel in 2014, due 2016 SUPPLY OF WESTERN CANADIAN CRUDE OIL WILL GROW 39 PER CENT BY 2030 TO 5.4 MILLION BARRELS PER DAY (B/D) to a global oversupply of oil. Prices have recovered somewhat since early 2016 to almost US$50 per barrel in May 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 CAPITAL INVESTMENT IN THE OIL SANDS $34 BILLION $15 BILLION producers is expected to increase by 70 per cent compared to 2016, but would still be 40 per cent lower than in 2014.

4 3 Canadian and U.S. Crude Oil Pipelines and Refineries have recovered somewhat since early 2016 to almost US$50 per barrel in May CAPP estimates oil sands will decline for the third OR IL OB EX XO NM Suncor NY EX UT EASTERN CANADA MARKETS BORGER/MCKEE WRB Valero CAPP forecasts an additional 1.5 million b/d of supplies coming from Western Canada by The combined regional opportunities in Slaughter Artesia Big Canada, the U.S. and globally can reasonably be expected to absorb Spring these incremental supplies. NEW MEXICO/W. TEXAS PE R lower than in GE TE ES S T COAS ID GULF Crane M IA TYLER N EX Delek...75 BR PR S SU PE ond U CENT PA White Rose NJ PENNSYLVANIA Monroe Energy (Trainer) Phil. Energy Solutions (Phil.) AR MISSISSIPPI Chevron (Pascagoula) Ergon (Vicksburg)...25 LOUISIANA Calumet (Shreveport) LA 10.1 MILLION B/D IS EQUAL TO MORE THAN 90 PER CENT Three Rivers TN EX XO N MO BIL Port Arthur/ Nederland/ Beaumont OF THE WORLD DEMAND INCREASE FROM 2015 TO AL MS WV MD VA DE PORT ARTHUR/BEAUMONT ExxonMobil Valero Total * * 4.90* 4.40** USEC to Montréal (Portland/Montréal) 0.50 St. James to Wood River (Capline/Capwood) 1.30 NEW JERSEY Phillips 66 (Bayway) PBF (Paulsboro) Axeon SP (Paulsboro) DELAWARE PBF (Delaware City) PIPELINE TOLLS FOR HEAVY OIL (US$ 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) USGC (Keystone/Gulf Coast Ext.) 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 GA FL LAKE CHARLES CITGO Phillips Calcasieu NC SC St. James Lake Charles OHIO BP-Husky (Toledo) PBF (Toledo) Marathon (Canton)...93 Husky (Lima) Marathon (Catlettsburg) PADD I ALABAMA Hunt (Tuscaloosa)...40 Shell (Saraland)...85 PIPELINE TOLLS FOR LIGHT OIL (US$ PER BARREL) Edmonton to Burnaby (Trans Mountain) Anacortes (Trans Mountain/Puget) Sarnia (Enbridge) Montréal (Enbridge) Chicago (Enbridge) Cushing (Enbridge) Wood River (Enbridge/Mustang/Capwood) USGC (Enbridge/Seaway) Hardisty to Guernsey (Express/Platte) Wood River (Express/Platte) Wood River (Keystone) USGC (Keystone/Gulf Coast Ext.) Philadelphia NEWELL, WV Ergon WOOD RIVER WRB ROBINSON Marathon MT VERNON Countrymark...28 MEMPHIS Valero EL DORADO Delek...80 X E THE COMBINED DEMAND GROWTH FROMTX CHINA AND INDIA OFHO-HO HOUSTON/TEXAS CITY PRSI (Pasadena) THREE RIVERS Marathon (Galveston) Valero Shell (Deer Park) CORPUS CHRISTI ExxonMobil CITGO SWEENY LyondellBasell Flint Phillips SOURCE: IEA World275 Energy Outlook 2016, NewMarathon Policies Scenario Valero... Valero (2) KY MO GA Diam RION HollyFrontier (Artesia) Alon (Big Spring) Tesoro (Gallup)...25 Tesoro (El Paso) WARREN United MA CT RI D EA RH EA H SP OUT S OK PADD III NY Newell OH is forecast to contribute up to 307,000 b/d of production by 2024 NM but then decline steadily. AZ NH Westover IN L VT 9 Marathon IFF Phillips 66 (Ponca City) HollyFrontier (Tulsa) Coffeyville Res. (Wynnewood)...70 Valero (Ardmore)...86 D BRI INE L GE DETROIT Flanagan ME MON TREA MI S is projected to be 5 per an COcent from 2017 to 2020, then slow to KS average annual growth rate OKLAHOMA of 2 per cent through BAKERSFIELD Kern Oil San Joaquin Montréal EN CHICAGO BP ExxonMobil PDV IL PRE SS THE ANNUAL AVERAGE GROWTHWHIN CANADA SUPPLY ITE WESTERN CL CRAN but would still be 40 per cent PADD II IA PO ADA BILLION HollyFrontier (El Dorado) Coffeyville Res. (Coffeyville) per cent of this DENVER/COMMERCE growth. CITY US BILLION $15 KANSAS NE CHS (McPherson)...85 WESTERN CANADA HEAVY OIL SANDS SUPPLY provides 95 CT CA $ SALT LAKE CITY Big West Chevron HollyFrontier Tesoro WI SCAN by 70 per cent compared to 2016, MN Saint John MONTRÉAL/QUÉBEC Suncor Valero SARNIA Imperial Shell Suncor NANTICOKE Imperial SD NORTH DAKOTA Tesoro (Mandan)...74 Tesoro (Dickinson)...20 WYOMING Sinclair (Casper)...25 Sinclair Oil (Sinclair)...85 )...18 HollyFrontier (Cheyenne)...52 SUPERIOR Calumet...45 TRAN 2014 ND Dickinson SEAWAY TWIN producers is expected to increase NEWFOUNDLAND & LABRADOR Silver Range (Come by Chance) SAINT JOHN Irving S IC PACIF CAPITAL INVESTMENT IN THE OIL SANDS LOS ANGELES Alon USA...70 Tesoro (Carson/Wilmington) Chevron PBF Phillips Valero , ,850 Hibernia Hebron Terra Nova Western Canadian crude oil supply accounts for the bulk of ST. PAUL WYand is forecast to grow Flint Hills DA from 3.9 million Canadian crude oil supply KO TA Tesoro A C NV b/d in 2016 to 5.4 million b/d in CE S CHEVRON Drilling by conventional crude oil ID PADD IV PRODUCTION AND SUPPLY CA long term FOR INFORMATION CONTACT: (403) / CAPP.CA Come by Chance U.S. producers may not have to face similar policies to those in Canada. BILLINGS Additionally, policies that may be pursued MT CHS (Laurel)...56 protectionist Phillips by the current U.S. administration are also a cause for concern. ExxonMobil...60 PADD V ELL to continuing uncertainty in the Western Canada Eastern Canada Total Canada FALLS 3. GREAT POTENTIAL DIVERGENT POLICIES FROM U.S. COMPETITORS. Calumet...25 SH dramatic change to projects due 61 3, Developing resources responsibly to help achieve key regulatory, Complex MOOSE JAW and needs to be social and environmental outcomes, is important Moose Jaw asphalt plant...19 done in a manner that does not unnecessarily burden industry WA and risk more jobs. PUGET SOUND BP (Cherry Pt) Phillips 66 (Ferndale) Shell (Anacortes) Tesoro (Anacortes) TrailStone (Tacoma)...42 SAN FRANCISCO Chevron (sold to Parkland Fuels) Phillips Shell Tesoro Valero KIANTONE consecutive year, which reflects a 2. CUMULATIVE IMPACTS OF GOVERNMENT REGINA POLICY CHANGES. VANCOUVER Chevron KEYSTONE 2017 producer capital spending for Husky asphalt plant...29 increasingly more stringent and costly, resulting in reduced Husky Upgrader...82 HU attractiveness for investment. SK Y ETC OP WILL GROW 39 PER CENT BY 2030 TO 5.4 MILLION BARRELS PER DAY (B/D). Shell UNCERTAINTY. Canada s policies and regulations are becoming LLOYDMINSTER British Columbia Alberta Saskatchewan Manitoba Northwest Territories KEYSTONE SUPPLY OF WESTERN CANADIAN CRUDE OIL Suncor San Francisco miles Los Angeles - 1,100 miles KOCH Wood River to a global oversupply of oil. Prices EDMONTON Key industry challenges are tempering long-term growth prospects. Imperial NA CANADIAN CRUDE OIL PRODUCTION 000 m3/d 000 b/d CA 2016 than US$100 per barrel in 2014, due PRINCE GEORGE Husky WA S 39% Crude oil prices dropped from more KEY COMPETITVENESS CHALLENGES FACING CANADA S OIL INDUSTRY VANCOUVER TO: Japan - 4,300 miles Taiwan - 5,600 miles S.Korea - 4,600 miles China - 5,100 miles W EXISTING PIPELINE CAPACITY PRICES AND INVESTMENT UPGRADERS Syncrude (Fort McMurray) Suncor (Fort McMurray) Shell (Scotford) CNRL (Horizon) RAINBO ADDITIONAL CAPACITY NEEDED ENBRIDGE NW MISSISSIPPI RIVER ExxonMobil (Baton Rouge) PBF (Chalmette) Marathon (Garyville) Shell (Convent) Shell (Norco) Valero (Norco) Valero (Meraux) Phillips 66 (Belle Chasse) Alon (Krotz Springs)...74 Placid (Port Allen)...60 Crude Refining Capacities as at June 1, 2017 (thousand barrels per day) PADD Petroleum Administration for Defense District Major Existing Crude Oil Pipelines carrying Canadian crude oil Selected Other Crude Oil Pipelines

5 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. Vancouver TRANS MOUNTAIN EXPANSION PROJECT ADDITIONAL CAPACITY: 590,000 b/d POTENTIAL MARKETS: Asia and California STATUS: Approved November 29, 2016 with 157 conditions by the federal government. Pipeline Proposals Edmonton Hardisty Winnipeg Baker Superior Steele City Patoka Cushing Port Arthur Lévis Montréal Trans Mountain Expansion Project Existing Pipeline Infrastructure to Gulf Coast TransCanada Keystone XL TransCanada Energy East Saint John Enbridge Line 3 Replacement TRANSCANADA ENERGY EAST ADDITIONAL CAPACITY: 1,100,000 b/d POTENTIAL MARKETS: Eastern Canada, U.S. East Coast, Europe, Africa and Asia STATUS: NEB hearing pending. TRANSCANADA KEYSTONE XL ADDITIONAL CAPACITY: 830,000 b/d POTENTIAL MARKETS: Heavy oil refineries along Gulf Coast STATUS: U.S. Presidential permit received on March 24, ENBRIDGE LINE 3 REPLACEMENT ADDITIONAL CAPACITY: 370,000 b/d POTENTIAL MARKETS: Central and Eastern Canada, U.S. Midwest and Gulf Coast STATUS: Approved November 29, 2016 with 89 conditions by the federal government. 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. Crude Oil Forecast, Markets & Transportation i

6 TABLE OF CONTENTS EXECUTIVE SUMMARY LIST OF FIGURES AND TABLES IFC iii 1 INTRODUCTION 1 2 CRUDE OIL PRODUCTION & SUPPLY FORECAST Production & Supply Forecast Methodology Canadian Production Eastern Canada Production Western Canada Production Western Canada Supply Crude Oil Production & Supply Summary 12 3 CRUDE OIL MARKETS Canada United States International Markets Summary 22 4 TRANSPORTATION Crude Oil Pipelines Exiting Western Canada Oil Pipelines to the U.S. Midwest Oil Pipelines to the U.S. Gulf Coast Oil Pipelines to the West Coast of Canada Oil Pipelines to Eastern Canada Diluent Pipelines Crude Oil by Rail Transportation Summary 38 GLOSSARY 39 APPENDIX A.1: CAPP Canadian Crude Oil Production Forecast APPENDIX A.2: CAPP Western Canadian Crude Oil Supply Forecast APPENDIX B: Acronyms, Abbreviations, Units and Conversion Factors 44 APPENDIX C: Map of Canadian and U.S. Crude Oil Pipelines and Refineries 45 ii CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

7 LIST OF FIGURES AND TABLES FIGURES Figure 1.1 World Total Primary Energy Demand, Figure 1.2 Capital Investment in Oil Sands 2 Figure 2.1 Canadian Oil Sands & Conventional Production 4 Figure 2.2 Newfoundland & Labrador Production 6 Figure 2.3 Western Canada Conventional Production 7 Figure 2.4 Oil Sands Regions 8 Figure 2.5 Western Canada Oil Sands Production 9 Figure 2.6 Western Canada Oil Sands & Conventional Supply 11 Figure 3.1 Canada and U.S.: 2016 Crude Oil Receipts by Source 13 Figure PADD I: Foreign Sourced Supply by Type and Domestic Crude Oil 16 Figure PADD II: Foreign Sourced Supply by Type and Domestic Crude Oil 18 Figure PADD III: Foreign Sourced Supply by Type and Domestic Crude Oil 19 Figure PADD IV: Foreign Sourced Supply by Type and Domestic Crude Oil 19 Figure PADD V: Foreign Sourced Supply by Type and Domestic Crude Oil 20 Figure 3.7 Global Net Oil Imports: 2015 to Figure 4.1 Existing and Proposed Canadian & U.S. Crude Oil Pipelines 23 Figure 4.2 Canadian Fuel Oil and Crude Petroleum Moved by Rail: Car Loadings & Tonnage 37 Figure 4.4 Existing Takeaway Capacity from Western Canada vs. Supply Forecast 38 TABLES Table 2.1 Canadian Crude Oil Production 4 Table 2.2 Atlantic Canada Projects and Recent Discoveries 5 Table 2.3 Western Canada Crude Oil Production 6 Table 2.4 Oil Sands Production 8 Table 2.5 Western Canada Crude Oil Supply 11 Table 3.1 Refineries in Western Canada by Province 14 Table 3.2 Refineries in Eastern Canada by Province 15 Table 3.3 Rail Offloading Terminals in Eastern Canada and PADD I 17 Table 3.4 Refinery Upgrade Projects in PADD II 18 Table 3.5 Rail Offloading Terminals in Western Canada & PADD V 21 Table 3.6 Total Oil Demand in Major Asian Countries 22 Table 4.1 Major Existing Crude Oil Pipelines Exiting Western Canada 24 Table 4.2 Proposed Crude Oil Pipelines Exiting Western Canada 25 Table 4.3 Enbridge Mainline System: Upstream Superior 26 Table 4.4 Summary of Crude Oil Pipelines to the U.S. Midwest 29 Table 4.5 Summary of Crude Oil Pipelines to the U.S. Gulf Coast 30 Table 4.6 Summary of Crude Oil Pipelines to the West Coast of Canada 33 Table 4.7 Summary of Crude Oil Pipelines to Eastern Canada 36 Table 4.8 Summary of Diluent Pipelines 36 Table 4.9 Rail Uploading Terminals in Western Canada 37 Crude Oil Forecast, Markets & Transportation iii

8 1 INTRODUCTION 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 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. 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 Hydro 2% Nuclear 5% Natural Gas 21% Other Renewables 1% Bioenergy 10% Coal 29% Oil 31% Source: IEA, World Energy Outlook CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

9 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 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$50 per barrel. Conventional producers in Canada are expected to respond with a 70 per cent increase in drilling of conventional oil wells in 2017 compared to 2016 but would still be almost 40 per cent lower when compared to FIGURE C$ billions E = estimate F = forecast CAPITAL INVESTMENT IN OIL SANDS E F 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 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 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 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. Crude Oil Forecast, Markets & Transportation 2

10 2 CRUDE OIL PRODUCTION & SUPPLY FORECAST 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. 2.1 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 to move 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. 3 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

11 FIGURE 2.1 CANADIAN OIL SANDS & CONVENTIONAL PRODUCTION million barrels per day 6 Actual Forecast June 2016 Forecast Eastern Canada Oil Sands 2 1 Conventional Heavy Conventional Light Pentanes/Condensate 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. 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 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. TABLE 2.1 CANADIAN CRUDE OIL PRODUCTION million b/d Eastern Canada Western Canada Total Canada* *Total may not add up due to rounding. Crude Oil Forecast, Markets & Transportation 4

12 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 In addition, first oil from a fourth major oil field, Hebron, is expected in late 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 Hibernia Hibernia South Extension Year Discovered First Oil Cumulative Production to December 31, 2016 (million barrels) Estimated Recoverable Reserves (million barrels) 1979 Nov ,002 (61% of reserves) 1,644 Terra Nova 1984 Jan (77% of reserves) 506 White Rose North Amethyst South White Rose Extension North Amethyst Hibernia West White Rose 1984 Nov 2005 May 2010 Mid 2015 Sep (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 to 600 (light oil) Source: Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) 5 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

13 FIGURE 2.2 NEWFOUNDLAND AND LABRADOR PRODUCTION thousand barrels per day 400 Actual Forecast White Rose North Amethyst June 2016 Forecast 200 Terra Nova Hibernia 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 Conventional (including pentanes/ condensate) Oil sands (bitumen & upgraded) Total Western Canada *Total may not add up due to rounding 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 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 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 Crude Oil Forecast, Markets & Transportation 6

14 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, 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. FIGURE 2.3 WESTERN CANADA CONVENTIONAL PRODUCTION 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 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. million barrels per day 1.6 Actual Forecast 1.4 June 2016 Forecast Alberta BC & NWT Saskatchewan Manitoba Pentanes/Condensate CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

15 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 OIL SANDS 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 Peace River Athabasca Deposit Fort McMurray 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. Peace River Deposit Edmonton Calgary Cold Lake Deposit Lloydminster TABLE 2.4 OIL SANDS PRODUCTION million b/d Mining In situ Total* *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. 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 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. Crude Oil Forecast, Markets & Transportation 8

16 FIGURE 2.5 WESTERN CANADA OIL SANDS PRODUCTION million barrels per day 6 Actual Forecast 5 4 June 2016 Forecast 3 2 In Situ 1 Mining 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 affiliated 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. 9 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

17 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 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, Natural gas produced and consumed on site by conventional oil and gas producers will be exempt from the carbon levy until January 1, 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 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 Upgraded Light supply increases by 163,000 b/d from 631,000 b/d to reach 794,000 b/d in 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. Crude Oil Forecast, Markets & Transportation 10

18 FIGURE 2.6 WESTERN CANADA OIL SANDS & CONVENTIO NAL SUPPLY million barrels per day 6 Actual Forecast June 2016 Forecast Oil Sands Heavy * Upgraded Light Conventional Heavy Conventional Light * Oil Sands Heavy includes some volumes of upgraded heavy sour crude oil and bitumen blended with diluent or ugpraded crude oil 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 WESTERN CANADA CRUDE OIL SUPPLY million b/d Light Heavy Total Supply* *Total may not add up due to rounding. 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. 11 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

19 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 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 Long-term oil sands production growth is being affected by: o o o Indications of possible U.S. protectionist policies. Federal and provincial climate change policies, which impose constraints on the ability to reduce capital and operating costs. Divergent environmental policies between Canada and the U.S. 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 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 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 Long-term activity and growth is significantly lower compared to the outlook compiled in 2014 when oil prices were over US$100 per barrel. Crude Oil Forecast, Markets & Transportation 12

20 3 CRUDE OIL MARKETS 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 FIGURE 3.1 CANADA AND U.S.: 2016 CRUDE OIL RECEIPTS BY SOURCE Other Western Canada 5 AB, BC, SK [553] QC+ Atlantic Canada [704] ON [330] PADD V [2,349] PADD IV [598] Other Atlantic Canada 36 PADD II [3,622] PADD I - East Coast [1,108] PADD III - Gulf Coast [8,527] [2016 total refinery receipts] thousand barrels per day U.S. - Alaska only U.S. (excluding Alaska) Other Imports Atlantic Canada Western Canada Sources: CAPP, CA Energy Commission, EIA, Statistics Canada 13 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

21 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 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 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 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 Owner REFINERIES IN WESTERN CANADA BY PROVINCE Location ALBERTA Crude Oil Processing Capacity (b/d) Imperial Strathcona 191,000 Husky Lloydminster 29,000 Suncor Edmonton 142,000 Shell Scotford 100,000 North West Redwater Partnership Alberta Subtotal: (4 refineries + 1 in construction) Chevron (sale to Parkland Fuels announced in April to be finalized by end 2017) Sturgeon County +50,000 (expected in late 2017) BRITISH COLUMBIA 462, ,000 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 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. Crude Oil Forecast, Markets & Transportation 14