Enbridge Pipelines Inc. Edmonton to Hardisty Pipeline Project Chapter 10 – Economics
1 10. ECONOMICS
2 The Edmonton to Hardisty Pipeline Project is designed to be part of the 3 integrated Enbridge Mainline System. The Enbridge Mainline is comprised of a 4 network of pipelines that connect oil supply from Western Canada1 to markets in 5 Eastern Canada and the US Midwest. For this reason, this section of the 6 Application broadly discusses Western Canadian crude oil supply and markets.
7 10.1. Supply
8 10.1.1. Reserves
9 In July 2012, the NEB released its Canadian Energy Overview briefing note2. In 10 it, the NEB summarizes remaining Canadian oil and bitumen reserves (Table 10- 11 1). Canada ranks third behind only Saudi Arabia and Venezuela with estimated 12 remaining established reserves of 27.4 billion m3 (173 billion bbl)3. 13 Approximately 98 percent of Canada’s remaining established reserves are 14 located in Alberta’s oil sands. Remaining established oil sands reserves are 15 approximately 26.9 billion m3 (169.2 billion barrels). The NEB estimates that 16 cumulative production of Alberta’s oil sands as of 31 December 2010 was 17 approximately 1.2 billion m3 (8.1 billion barrels). Approximately 95 percent of 18 Alberta’s oil sands have yet to be developed. 19 20 Table 10-1: NEB Estimates of Canadian Crude Oil and Bitumen Reserves4 21 Conventional Crude Oil Thousand Cubic Metres Thousand Barrels
British Columbia 19,000 119,506
Alberta 237,000 1,490,683
Saskatchewan 116,000 729,617
Manitoba 8,000 50,318
Ontario 2,000 12,580
Newfoundland Grand Banks 146,000 918,311
Mainland NWT & Yukon 11,000 69,188
1 Western Canada includes BC, Alberta, Saskatchewan, Manitoba, and NWT 2 NEB Canadian Energy Overview 2011( http://www.neb-one.gc.ca/clf- nsi/rnrgynfmtn/nrgyrprt/nrgyvrvw/cndnnrgyvrvw2011/cndnnrgyvrvw2011-eng.pdf ) 3 Oil & Gas Journal, December 6, 2010 4 At 31 December 2010
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Total Conventional 539,000 3,390,202
Oil Sands Thousand Cubic Metres Thousand Barrels
Mineable 5,389,000 33,895,732
In Situ 21,509,000 135,287,308
Total – Oil Sands 26,898,000 169,183,040
Total Remaining Established 27,437,000 172,573,242 Reserves
1
2 Source: NEB
3 10.1.2. Supply Forecast:
4 Figure 10-1 depicts the 2012 Canadian Association of Petroleum Producers 5 (“CAPP”) forecast for Western Canadian oil supply. CAPP’s Crude Oil Forecast, 6 Markets & Pipelines report is attached as Appendix 10-1. The forecast points to 7 significant growth in Western Canadian oil supply. By 2020, CAPP expects that 8 Western Canadian oil supply will approach 795,000 m3/d (5.0 million bbl/d). 9 CAPP expects that supply will grow annually by 33,100 m3/d (208,000 bbl/d) over 10 the forecast period. By 2030, the CAPP Western Canadian oil supply forecast 11 exceeds 1.08 million m3/d (6.8 million bbl/d). 12 13 CAPP expects that oil sands production in the form of heavy crude oil blends and 14 synthetic crude oil will drive incremental oil supply from Canada. The CAPP 15 forecast assumes that supply from oil sands grows from 336,000 m3/d (2.1 million 16 bbl/d) in 2012 to 939,400 m3/d (5.9 million bbl/d) in 2030. Moreover, CAPP 17 expects oil sands heavy supply to more than triple from 208,000 m3/d (1.3 million 18 bbl/d) in 2012 to 767,900 m3/d (4.8 million bbl/d) in 2030. 19 20
21
22
23
24
25
26
27
28
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1 Figure 10-1: CAPP Western Canadian Oil Supply Forecast
CAPP 2012 Forecast 8,000 7,000 CAPP Oil Sands Heavy 6,000 5,000 CAPP Upgraded Light (Synthetic) 4,000
3,000 CAPP Net Conventional Heavy
Thousandbbl/d 2,000 1,000 CAPP Conventional Light &
0 Medium
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2 2012 3 Source: CAPP 4 5 Alberta’s Energy Resources and Conservation Board (“ERCB”) also anticipates 6 increased supply from the oil sands5. Figure 10-2 from the ERCB’s ST98 Report 7 points to raw bitumen production in excess of 550,000 m3/d (3.5 million bbl/d) by 8 2021. It is clear from both CAPP and the ERCB that long term growth in Western 9 Canadian oil supply will come from oil sands development. 10 11 Figure 10-2: ERCB ST98 Report – Alberta Raw Bitumen Production
12
5 ERCB ST98 report Alberta’s Energy Reserves 2011 and Supply/Demand Outlook 2012-2021 http://www.ercb.ca/sts/ST98/ST98-2012.pdf
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1 Source: 2012 ERCB ST98 report
2 10.2. Transportation Matters
3 10.2.1. Pipeline Capacity – Edmonton and Hardisty Hubs
4 5 Edmonton and Hardisty are major transportation hubs for Western Canadian crude oil. Feeder 6 pipeline systems gather and transport crude oil to Edmonton and Hardisty for onward delivery to 7 downstream markets or to meet local Edmonton refinery demand. According to the ERCB, there 8 is currently over 500,000 m3/d (3.2 million bbl/d) of upgraded and non-upgraded bitumen 9 pipeline capacity delivering primarily to the Edmonton and Hardisty hubs.6 Current oil sands 10 pipeline capacity targeting the Edmonton hub is approximately 312,000 m3/d (2.0 million bbl/d)7.
11 Industry has advanced a number of pipeline projects to accommodate the expected increases in 12 oil sands supply. These projects are in various stages of development and tend to direct more 13 volumes towards the Edmonton hub as opposed to Hardisty. Table 10-2 summarizes the 14 publically known pipeline projects that are in various stages of development.
15 Table 10-2: Oil Sands Pipeline Projects Directed to Edmonton or Hardisty
Proponent(s) Pipeline Status Incremental In Service Hub Capacity: thousand Date m3/d (thousand bbl/d)
Enbridge Pipelines Waupisoo In Construction 31.8 Q4 2012 Edmonton (Athabasca) Inc.8 Expansion (200)9
Enbridge Pipelines Woodland Approved 63.6 2014 Edmonton (Athabasca) Inc.10 Pipeline (400) Extension
Access Pipeline Access Application 31.8 2015 Sturgeon Inc.11 Terminal
6 ERCB ST98 report Alberta’s Energy Reserves 2011 and Supply/Demand Outlook 2012-2021 http://www.ercb.ca/sts/ST98/ST98-2012.pdf; 7 Cold Lake West capacity plus other ERCB identified pipelines 8 ERCB License 48997 9 The ERCB ST98 report indicated initial Waupisoo capacity of 55,600 thousand m3/d (350 thousand bbl/d). The incremental 200 thousand bbl/d is the difference between the target capacity of 550 thousand bbl/d and 350 thousand bbl/d 10 Decision 2012 ABERCB 009 http://www.ercb.ca/decisions/2012/2012-ABERCB-009.pdf
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(200) (Edmonton)
Inter Pipeline Cold Lake In Progress 18.3 2013 Edmonton Fund12 West Leg (115)
TransCanada Grand Announced 143 2017 Edmonton Corporation/ Rapids Pipeline (900) 13 PetroChina Project
Enbridge Pipelines Athabasca In Construction 31.8 2013 Hardisty (Athabasca) Inc.14 Capacity (200) Expansion
Enbridge Pipelines Athabasca Application 71.5 2015 Hardisty (Athabasca) Inc.15 Twinning (450)
Inter Pipeline Cold Lake Announced 85.9 unknown Hardisty Fund16 South Leg Mainline (540) Twinning
Total Edmonton 145.5 (excluding announced (915) projects)
Total Hardisty 103.3 (excluding announced (650) projects)
1
11 ERCB Application No. 1724272 12 Inter Pipeline Fund's Annual Information Form dated February 16, 2012 filed with SEDAR. 13 http://www.transcanada.com/6129.html
14 ERCB License 31611 15 ERCB Application No. 1724271 16 Inter Pipeline Fund Announces $2.1 Billion Integrated Oil Sands Development Program http://interpipelinefund.mwnewsroom.com/press-releases/inter-pipeline-fund-announces-2-1-billion-integra-tsx- ipl-un-201207310808875001
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1 10.2.2. Oil Sands Supply at Edmonton and Throughputs
2 The list above demonstrates that, in general, producers tend to favor directing incremental oil 3 sands volumes to Edmonton as opposed to Hardisty. Excluding “Announced” pipeline projects, 4 approximately 58 percent of incremental pipeline capacity is directed towards Edmonton (60 5 percent when announced projects are included). CAPP forecasts that oil sands supply will grow 6 by approximately 120 thousand m3/d (757 thousand bbl/d) between 2011 and 201517; the year 7 that the Edmonton to Hardisty pipeline will be operational. Much of that incremental volume 8 growth will be aggregated at the Edmonton and Hardisty hubs. Applying the incremental 9 pipeline capacity ratio above to the incremental oil sands supply growth results in approximately 10 70 thousand m3/d (439 thousand bbl/d) of incremental crude oil that could be directed to the 11 Edmonton hub in 2015. As oil sands supply grows, the volume directed to Edmonton can also 12 be expected to grow. Accordingly, supply will be available to the pipeline at Edmonton and it will 13 be used and useful.
14 10.2.3. Pipeline Capacity ex-Edmonton and ex-Hardisty
15 From the Edmonton hub, crude oil is shipped on three main pipeline systems: Kinder Morgan’s 16 Trans Mountain system for west coast delivery; the Rangeland pipeline for PADD IV delivery; 17 and, eastward on the Enbridge Mainline System for access to Eastern Canada, PADD II, and 18 PADD I.
19 From the Hardisty hub, crude oil is shipped on four main systems: Kinder Morgan’s 20 Express/Platte system for PADD IV and PADD II access; the Bow River and Plains’ Milk River 21 system for PADD IV access; TransCanada’s Keystone system for PADD II access; and, the 22 Enbridge Mainline System for access to Eastern Canada, PADD II, and PADD I.
23 A summary of the current pipeline takeaway capacity from Edmonton and Hardisty can be seen 24 in Table 10-3.
25 Table 10-3: Current Capacity and Destination of Pipelines Exiting Edmonton and Hardisty18
From Edmonton
Pipeline Destination Capacity (thousand m3/d)
Enbridge Mainline Eastern Canada, PADD II, PADD I 296.4
Kinder Morgan Trans Mountain BC, US PADD V, offshore west coast 47.7
Plains Rangeland Pipeline PADD IV 13.5
17 CAPP’s “Total Oil Sands and Upgraders” forecast volumes represent oil sands supply. Coventional crude oil is expected to grow marginally and then decline to current levels by 2025. 18 ERCB ST98
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Total From Edmonton 357.6
From Hardisty
Pipeline Destination Capacity (thousand m3/d)
Enbridge Mainline Eastern Canada, PADD II, PADD I 296.4
Alberta Clipper Eastern Canada and PADD II 71.5
Keystone PADD II, Cushing 93.8
Bow River/Milk River PADD IV 18*
Kinder Morgan Express PADD IV 44.9
Total From Hardisty 524.6
1 Source: ERCB ST98, Enbridge
2 *Note: The capacity reflected is the Milk River export pipeline capacity at the border.
3 Trans Canada’s Keystone XL pipeline is not captured in Table 11-2. It has an initial projected 4 ex-Alberta takeaway capacity of 111,000 m3/d (700,000 bbl/d) from Hardisty to the US Gulf 5 Coast – one of the largest refining centers in the world. The in-service date for Keystone XL ex- 6 Hardisty is targeted for 201519. The Enbridge Mainline also has connections to various pipelines 7 downstream in Canada and the US giving Canadian producers access to, Saskatchewan, 8 Ontario, Cushing, PADD II, and PADD III refineries.
9 The proposed Edmonton to Hardisty Pipeline Project does not result in an overall increase in 10 Enbridge Mainline system capacity. The purpose of the Project is to better align Mainline 11 delivery capability with upstream oil sands pipeline developments.
12 10.3. Markets
13 Any destination downstream from Edmonton can be considered a market to absorb the volumes 14 shipped on the proposed Enbridge to Hardisty Pipeline Project. These destinations include 15 locations on the Enbridge Mainline, extended markets connected to the Enbridge Mainline and 16 markets served by pipelines exiting Hardisty.
17 Enbridge commissioned the services of Muse Stancil to provide an independent assessment of 18 the heavy crude oil market and the need for additional inbound heavy crude oil pipeline capacity 19 at Hardisty. A copy of the Muse Stancil report is attached as Appendix 10-2.
19 Keystone XL Pipeline Project http://www.transcanada.com/keystone.html
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1 Muse Stancil assessed the demand for Canadian heavy crude oil at Hardisty (based on the 2 CAPP 2012 supply forecast) against the inbound heavy crude oil pipeline capacity. To conduct 3 the analysis and determine demand, Muse Stancil employed its Crude Optimization Model to 4 estimate the distribution of Canadian heavy crude oil.
5 The Muse Stancil report concludes that incremental heavy crude oil pipeline capacity into the 6 Hardisty hub will be needed by 2015. The incremental pipeline capacity provided by the 7 Edmonton to Hardisty pipeline satisfies that need and will allow incremental heavy crude oil 8 volumes access to the large refining market connected to Hardisty. The heavy crude oil 9 volumes to be shipped on the Edmonton to Hardisty pipeline will be absorbed by the market 10 connected to the Hardisty Hub.
11 10.4. Financing
12 The total cost of the Project, inclusive of interest during construction, is estimated to be CAD 13 $814.8 Million, as outlined in Tables 2-2 and 2-3. The abandonment cost estimate based upon 14 Enbridge’s proposed methodology is approximately $23 Million. Based upon some preliminary 15 financial assumptions, Enbridge estimates that the toll impact on the LMCI toll will be 16 approximately $0.0015/bbl. Given the immaterial impact on tolls, Enbridge does not propose to 17 adjust its abandonment cost estimate. Pursuant to the NEB’s RH-2-2008 Decision, Enbridge’s 18 abandonment cost estimates will be subject to regular review (at least every five years) and 19 updated accordingly. The combined impact of all of Enbridge’s projects, including the Project, 20 will be included in that periodic update and filing.
21 The Project will be owned by Enbridge Pipelines Inc., a wholly-owned subsidiary of Enbridge 22 Inc. Enbridge Pipelines Inc. will ultimately fund the Project with funds from an existing bank 23 credit facility, internally generated cash flows, term debt from the Canadian capital markets, as 24 well as from equity contributions from Enbridge Inc. A copy of the Enbridge Pipelines Inc. 2011 25 Audited Financial Statements and Management Discussion and Analysis is attached as 26 Appendix 10-3. Attached as Appendix 10-4 is the Enbridge Pipelines Inc. Third Quarter Report 27 for the period ending September 30, 2012 (comprised of the Financial Statements and 28 Management Discussion and Analysis).
29 Enbridge Pipelines Inc. is rated A- by Standard and Poor’s Ratings Services (“S&P”) and A by 30 Dominion Bond Ratings Service (“DBRS”). Appendix 10-5 provides the S&P rating report for 31 Enbridge Pipelines Inc., dated December 15, 2011 and Appendix 10-6 provides the DBRS rating 32 report for Enbridge Pipelines Inc., dated December 6, 2011.
33 10.5. Conclusion
34 The incremental pipeline capacity provided by the Project is needed and will be used and useful. 35 CAPP expects, that oil sands production will drive growth in Western Canadian oil supply. The 36 proposed Project enables Enbridge to accommodate incremental volumes of oil sands supply. 37 Without such integration, insufficient pipeline capacity will exist to transport growing volumes of
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1 oil sands crude to be delivered to the Edmonton hub. Downstream markets connected to the 2 Hardisty Terminal have sufficient capacity to absorb the volumes to be shipped.
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Crude Oil Forecast, Markets & Pipelines
June 2012
CrudeCrude OilOil Forecast,Forecast, MarketsMarkets & PipPipelineselines 1 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
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 the 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 as any affiliation.
2 CANADIANCANADIAN AASSOCIATIONSSOCIATION OOFF PEPETROLEUMTROLEUM PRPRODUCERSODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. EXECUTIVE SUMMARY
CAPP annually publishes a long-term outlook for Canadian crude oil production. This year, our forecast has been extended by five years to 2030. Growth in conventional oil production is even stronger than was expected last year, however, oil sands remain the dominant component of future production. This longer term outlook predicts total Canadian production will exceed 6 million b/d at the end of this period. Western Canadian crude oil producers need to find new markets for their expanding production. Eastern Canada, which currently imports over half of its oil from offshore foreign suppliers, is a prime candidate. Other market opportunities include increasing the share of the U.S. markets that have been traditionally served, as well as accessing new U.S. markets, particularly those located on the U.S. Gulf Coast. Beyond the confines of North America, growing economies in Asia represent a market that producers are actively pursuing. As a result of strong growth in both U.S. and Canadian oil production, pipeline capacity is expected to be tight in the next few years, requiring the need for timely expansions to provide market access. A number of pipeline projects are being proposed to connect the growing supply with the anticipated market demand. Canadian Crude Oil Production Oil Sands The main driver for future growth continues to be oil sands and Supply development, which is higher than previously forecast due CAPP’s 2012 outlook for western Canadian crude to the addition of several new projects reflecting growing oil production predicts continued strong growth for producer confidence. the forecast period. Overall, compared to CAPP’s Atlantic Canada 2011 forecast, the total Canadian outlook is higher by 885,000 b/d in 2025. Production from offshore Atlantic Canada accounted for 9 per cent of Canada’s production in 2011 and is expected Conventional to average around 220,000 b/d over the next decade. The The degree of resurgence in conventional production start-up up of the Hebron project in 2017 helps to offset is even greater than we predicted last year. In 2011, production declines from the existing projects. conventional production, including pentanes, from western Canadian Crude Oil Production Canada grew for the first time in many years, surpassing previous expectations and is expected to grow until at million b/d 2011 2015 2020 2025 2030 least 2017. Total Canadian 3.0 3.8 4.7 5.6 6.2 (including oil sands) Eastern Canada 0.3 0.2 0.2 0.2 0.1 Canadian Oil Sands & Conventional Production Western Canada Conventional 1.1 1.3 1.3 1.2 1.1 thousand barrels per day Oil sands 1.6 2.3 3.2 4.2 5.0 8,000 Actual Forecast 7,000 Eastern Canada 6,000
5,000 June 2011 Forecast Oil Sands Growth 4,000
3,000 Oil Sands Operating & In Construction 2,000
1,000 Conventional Heavy Pentanes Conventional Light 0 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 Crude Oil Forecast, Markets & Pipelines i Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Crude Oil Markets Coast, western Canadian producers could supply at least 1.1 million b/d into this market by 2020. Foreign imports The production of crude oil in Canada far exceeds our account for the majority of the Gulf Coast’s heavy crude oil domestic needs. Western Canadian producers require feedstock today so heavy crude oil from western Canada access to new markets for their steadily growing is well suited to meet this market’s requirements thereby production. displacing imports from traditional suppliers such as Venezuela and Mexico. Eastern Canada The demand for western Canadian crude oil in the U.S. Refineries located in Ontario, Québec and Atlantic Canada Midwest, Canada’s largest traditional market, is expected currently import over half of their crude oil requirements to rise by almost 470,000 b/d. However, the flow of crude from offshore foreign suppliers. There is an opportunity oil into this region currently far exceeds its ability to for producers in western Canada to serve this market and process it and there exists insufficient takeaway capacity reduce Canada’s exposure to volatile world oil markets. to transport these growing supplies beyond the Cushing, United States Oklahoma pipeline and storage hub. Refineries in California and Washington are expected to increase imports of Growing domestic U.S. crude oil production will increase foreign sourced crude oil given declining production from competition for western Canadian crude oil in various Alaska. Western Canadian producers can compete for this U.S. markets. Nonetheless, the U.S. Gulf Coast still market opportunity. represents a significant market opportunity for Canadian supplies given the huge refining complex that is in place. Based on the contractual commitments underpinning pipeline projects that would provide capacity to the Gulf
2011 Canada and U.S. Crude Oil Demand by Market Region thousand barrels per day
AB, BC, SK [577] Atlantic Canada [411]
PADD V - excl CA [731] ON, QC [681] PADD IV PADD II - North [544] (ND, SD,MN, WI) [439] PADD V - CA [1,614] PADD I - East Coast [1,097]
PADD II - South (KS, OK) [741] PADD II - East (MI, IL, IN, OH, KY, TN) [2,191] U.S. - Alaska only U.S. (excl Alaska) Other Imports E. Canada W. Canada
PADD III - Gulf Coast [2011 total refinery demand] Source: EIA, Statistics Canada [7,475] ii CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Asia A number of pipeline proposals to the Gulf Coast have Asia represents a large new market and China, in particular, recently been announced that will increase access by 2014 continues to emerge as a significant potential market. In via connections to existing infrastructure and new projects. In 2011, it imported some 5.7 million b/d of oil. addition to looking for increased penetration to U.S. markets, western Canadian crude oil producers are also seeking much greater market diversification through increased Crude Oil Pipelines and connectivity to Eastern Canada and world markets. This would be achieved by more pipeline capacity to the west Expansions coast, where crude oil could be shipped to the burgeoning Growing conventional oil, including tight oil, and oil sands economies of Asia. There is also much interest in improving production has created an urgent need for additional connectivity to western Canadian supplies for all Canadians. transportation infrastructure. New pipelines, expansions to As such, a number of projects to increase pipeline access existing infrastructure and increased transportation by rail are from western Canada to eastern Canadian markets are being all required to meet this need for capacity. Pipelines continue contemplated. to be the dominant mode of transportation for crude oil but it takes time for pipeline infrastructure to be built or expanded. In the short-term, crude oil transport by rail will increase sharply due to the ability to use rail capacity relatively quickly and in small increments as needed and utilizing the rail infrastructure already in place.
Canadian & U.S. Crude Oil Pipelines - All Proposals
Kitimat Enbridge Gateway
Trans Mountain Edmonton
Hardisty Burnaby Alberta Clipper Expansion Anacortes Bakken Expansion Kinder Morgan TM Expansion (TMX) Cromer
Southern Access Expansion Express Clearbrook TransCanada Superior Montréal Keystone XL Enbridge Line 9 Reversal St. Paul Portland Enbridge Guernsey Sarnia Salt Lake City Platte Flanagan Chicago TransCanada Keystone BP Lima Spearhead North Expansion Spearhead South Wood Patoka River Flanagan South Mustang Canadian and U.S. Oil Pipelines Centurion Pipeline Cushing Mid Valley Enbridge Pipelines and connections Capline to the U.S. Midwest and E. Canada ExxonMobil Pegasus El Paso Seaway Reversal Kinder Morgan Express & Twin Line Kinder Morgan Trans Mountain TransCanada Gulf Coast Crane TransCanada Keystone Port Arthur Proposed pipelines to the West Coast Magellan Houston to New Orleans El Paso (former Longhorn) Houston Existing / Proposed pipelines to PADD II - partial conversion Freeport St. James Expansion/Reversal to existing pipeline Shell Ho-Ho
Crude Oil Forecast, Markets & Pipelines iii Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. TABLE OF CONTENTS
EXECUTIVE SUMMARY i LIST OF FIGURES AND TABLES v
1 INTRODUCTION 1 1.1 Production and Supply Forecast Methodology 2 1.2 Market Demand Outlook Methodology 2
2 OIL PRODUCTION AND SUPPLY FORECAST 3 2.1 Canadian Crude Oil Production 3 2.2 Western Canadian Crude Oil Production 4 2.2.1 Conventional Crude Oil Production 5 2.2.2 Oil Sands 6 2.3 Western Canadian Crude Oil Supply 8 2.5 Crude Oil Production and Supply Summary 9
3 CRUDE OIL MARKETS 10 3.1 Canada 11 3.1.1 Western Canada 12 3.1.2 Ontario 12 3.1.3 Québec 12 3.2 United States 13 3.2.1 PADD I (East Coast) 13 3.2.2 PADD II (Midwest) 14 3.2.3 PADD III (Gulf Coast) 17 3.2.4 PADD IV (Rockies) 17 3.2.5 PADD V (West Coast) 18 3.3 Asia 20 3.5 Markets Summary 20
4 CRUDE OIL PIPELINES 21 4.1 Existing Oil Pipelines Exiting Western Canada 22 4.2 Oil Pipelines to the U.S. Midwest 24 4.3 Oil Pipelines to the U.S. Gulf Coast 25 4.4 Projects Dedicated to Divert U.S. Crude Oil from the Cushing Bottleneck 26 4.5 Oil Pipelines to the West Coast 27 4.6 Eastern Access 28 4.7 Diluent Pipelines 28 4.8 An Alternative Mode of Transport: Rail 29 4.9 Projects to Transport North Dakota Production 31 4.10 Pipeline Summary 31
GLOSSARY 33 APPENDIX A: Acronyms, Abbreviations, Units and Conversion Factors 35 APPENDIX B: CAPP Canadian Crude Oil Production and Supply Forecast 2012 – 2030 37 APPENDIX C: Crude Oil Pipelines and Refineries 39
iv CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. LIST OF FIGURES AND TABLES
Figures Figure 2.1 Canadian Oil Sands & Conventional Production 4 Figure 2.2 Western Canada Conventional Production (Light, Medium, Condensates) 6 Figure 2.3 Oil Sands Regions 6 Figure 2.4 Western Canada Oil Sands & Conventional Production 7 Figure 2.5 Western Canada Oil Sands & Conventional Supply 8
Figure 3.1 Canada and U.S. Market Demand for Crude Oil in 2011 by Source 10 Figure 3.2 Market Demand for Western Canadian Crude Oil: Actual 2011 and 2020 Additional 11 Figure 3.3 Western Canada: Forecast Western Canadian Crude Oil Receipts 12 Figure 3.4 Ontario: Forecast Western Canadian Crude Oil Receipts 12 Figure 3.5 2011 PADD I: Foreign Sourced Supply by Type and Domestic Crude Oil 13 Figure 3.6 2011 PADD II: Foreign Sourced Supply by Type and Domestic Crude Oil 14 Figure 3.7 PADD II (North): Forecast Western Canadian Crude Oil Receipts 15 Figure 3.8 PADD II (East): Forecast Western Canadian Crude Oil Receipts 15 Figure 3.9 PADD II (South): Forecast Western Canadian Crude Oil Receipts 16 Figure 3.10 2011 PADD III: Foreign Sourced Supply by Type and Domestic Crude Oil 17 Figure 3.11 PADD IV: Forecast Western Canadian Crude Oil Receipts 18 Figure 3.12 2011 PADD V: Foreign Sourced Supply by Type and Domestic Crude Oil 18 Figure 3.13 Washington: Forecast Western Canadian Crude Oil Receipts 19 Figure 3.14 2011 PADD V (California): Foreign Sourced Supply by Type and Domestic Crude Oil 19 Figure 3.15 Net Oil Imports: Asia 2010 to 2030 20
Figure 4.1 Canadian & U.S. Crude Oil Pipelines - All Proposals 21 Figure 4.2 CP Rail Network 29 Figure 4.3 CN Rail Network 30 Figure 4.4 WCSB Takeaway Capacity vs Supply Forecast 32 Tables Table 2.1 Canadian Crude Oil Production 3 Table 2.2 Western Canadian Crude Oil Production 4 Table 2.3 Foreign Direct Investment in Oil Sands: 2009-2012 5 Table 2.4 Oil Sands: Raw Bitumen Production 7 Table 2.5 Western Canadian Crude Oil Supply 9
Table 3.1 Summary of Refinery Closures/Expansions in PADD I 14 Table 3.2 Summary of Major Announced Refinery Upgrades in Eastern PADD II 16 Table 3.3 Summary of Major Announced Refinery Upgrades in PADD III 17 Table 3.4 Total Oil Demand in Major Asian Countries 20
Table 4.1 Major Existing Crude Oil Pipelines and Proposals Exiting the WCSB 22 Table 4.2 Summary of Crude Oil Pipelines to the U.S. Midwest 24 Table 4.3 Summary of Crude Oil Pipelines to the U.S. Gulf Coast 25 Table 4.4 Summary of Crude Oil Pipelines to the West Coast 27 Table 4.5 Summary of Diluent Pipelines 28 Table 4.6 Summary of Existing and Proposed Projects to Transport Production from North Dakota 31
Crude Oil Forecast, Markets & Pipelines v Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. 1 INTRODUCTION
CAPP annually publishes a long-term outlook for Canadian crude oil production. This year our forecast has been extended by five years to 2030. The decisions producers make to increase investment in order to grow supply are not made in a vacuum. Producers want to know what the market opportunities are for any increased supply and whether there will be sufficient infrastructure to provide market access. Hence, this report also provides a demand outlook for western Canadian crude oil that has also been extended out by five years, to 2020. In addition, the report includes a discussion on the existing and developing transportation options that will be required to enable the efficient flow of crude oil from supply regions to end-use markets.
The purpose of this report is to provide industry Production from offshore Atlantic Canada, which in 2011 stakeholders and government agencies with a benchmark accounted for 9 per cent of total Canadian production, is from which to compare their own outlooks of Canadian expected to decline by 21 per cent in 2012. Production crude oil supply. Through its examination of evolving will remain relatively stable, averaging around 220,000 b/d industry trends, this report is intended to contribute to until 2022, supported by production from satellite fields stakeholders’ market analysis and facilitate decision- and the Hebron project starting up in 2017. In 2024, making in an industry that faces complex issues. Other production falls to just over 170,000 b/d and declines interested parties may value the report as a reference steadily thereafter. document that reflects the latest emerging developments. The forecasted higher growth in supply for western This report captures a number of interesting Canadian crude oil has resulted in increased awareness developments. Top of this list is the revitalization of regarding the potential for pipeline constraints. The conventional crude oil production taking place in a largest market for western Canadian crude has number of western Canadian plays. In 2011, conventional traditionally been the U.S. Midwest but future production production, including pentanes, from western Canada growth requires Canadian producers to look to extend grew for the first time in many years, significantly their reach and serve new markets. Avoiding constraints surpassing previous expectations. It is now expected in transportation capacity to markets is essential to a to grow until at least 2017. Oil sands development is well-functioning crude oil market and the potential for also higher than previously forecast due to the addition such constraints is currently one of the oil industry’s major of a number of new projects. By 2025, the combined concerns. western Canadian production from both conventional and unconventional crude oil development in this forecast is Growth in western Canadian and U.S. Mid-continent about 885,000 b/d higher than last year. CAPP’s estimate crude oil supply, which has taken place in the last few of industry capital spending for oil sands development is years, has already resulted in a market characterized by $20 billion for 2012 compared to an estimated $19 billion tight pipeline capacity that has seen the emergence of a spent in 2011. number of bottlenecks. Most notable is the oversupply situation at the Cushing, Oklahoma pipeline and storage hub. In this case, pipeline capacity has been added to
1 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
transport crude from areas with growing production 1.2 Market Demand Outlook into Cushing while there has been no commensurate takeaway capacity from the hub added to date to take Methodology these crude oil supplies to refineries located outside of CAPP did not make any risk adjustments to the data the Mid-continent. As a result, the price of crude oil in submitted by refiners beyond checking it for potential the Mid-continent has been depressed relative to global errors. Certain assumptions were also made based crude oil prices. For example, in the past year the price on discussions with refiners and the review of publicly of West Texas Intermediate (WTI), a benchmark Mid- available information. continent crude oil, has sold at a discount at times well over $20 per barrel compared to North Sea Brent, which The CAPP survey categorizes western Canadian crude oil is a light crude oil of similar quality that is sold on world into four main types as follows: markets. 1. Conventional Light Sweet (greater than 27° API and less than or equal to 0.5% sulphur) including 1.1 Production and Supply condensates and pentanes plus;
Forecast Methodology 2. Heavy (equal to or less than 27° API) including conventional heavy, synthetic sour and crude oil CAPP’s oil sands forecast is derived from its survey of oil blends such as DilBit, SynBit and DilSynBit; sands producers who were asked for the following data: 3. Conventional Medium Sour (greater than 27° API a) expected production by project and phase; and greater than 0.5% sulphur); and b) upgraded light crude oil that would be produced; 4. Light Sweet Synthetic c) amount of synthetic crude oil used as diluent For the purposes of the historical data in this section required to move the volumes to market; and of the report, the following crude types and definitions d) amount of condensate used as diluent to move apply: the volumes to market. • Sweet: crude oil with a sulphur content of less The survey results were then risked accordingly based than or equal to 0.5% on each project’s current development stage. The overall • Sour: crude oil with a sulphur content of greater forecast was then verified for reasonableness against than 0.5% historical trends. There were no constraints put on the forecast due to availability of condensate or pipeline • Light: crude oil with an API of at least 30° capacity. • Medium: crude oil with an API of greater than 27° CAPP also surveyed Saskatchewan conventional oil but less than 30° producers regarding their annual drilling outlook by well type (horizontal or vertical), as well as their anticipated • Heavy: crude oil with an API of 27° or less initial production rates and declines. These survey results were subsequently incorporated with CAPP’s internal No differentiation is made between sweet and sour crude analysis of historical trends, recent announcements and oil that falls into the heavy category because heavy crude discussions with industry stakeholders in order to develop oil is generally assumed to be sour. CAPP’s latest conventional forecast.
Crude Oil Forecast, Markets & Pipelines 2 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. CRUDE OIL PRODUCTION 2 AND SUPPLY FORECAST
With over 174 billion barrels of proven crude oil reserves, Canada holds the world’s third largest reserves after Saudi Arabia and Venezuela. Also according to the Oil and Gas Journal, in 2011, Canada ranked as the sixth largest crude oil producing country in the world, with combined production of over 3 million b/d of crude oil, bitumen, upgraded light oil, condensate and pentanes plus. In this report, CAPP has extended its production and supply outlook to 2030.
2.1 Canadian Crude Oil Production Table 2.1 Canadian Crude Oil Production In 2011, about 9 per cent of Canada’s crude oil production, million b/d 2011 2015 2020 2025 2030 or 273,000 b/d, can be attributed to Eastern Canada, Total* Canadian 3.02 3.85 4.70 5.62 6.24 almost all of which was sourced from offshore Atlantic (including oil sands) Canada with some small volumes from Ontario. Most Eastern Canada 0.27 0.22 0.22 0.16 0.09 of Canada’s production, or over 2.7 million b/d, was Western Canada 2.74 3.63 4.49 5.46 6.16 produced in western Canada. Of this amount, 41 per cent *Totals may not add up due to rounding. was conventional production and 59 per cent was derived from the oil sands areas. Table 2.1 shows the forecast for Following a 3 per cent decline in 2011 due to maintenance total Canadian production divided between Eastern and work and well shut-in at Terra Nova, Newfoundland Western Canada. offshore production is forecast to decline by 21 per cent in 2012 due to the natural decline in production from Hibernia Atlantic Canada’s oil resources are located off the shores and Terra Nova, and scheduled maintenance at both Terra of Newfoundland and Labrador and current production Nova and White Rose. Production from the Hebron field, results from developments in three main fields – Hibernia, which will be Newfoundland’s fourth standalone offshore oil Terra Nova, and White Rose. Recovery from satellite project, is expected to start in 2017. Most of this oil will be fields is expected to slow the exhibited natural decline around 20° API. This production accounts for the growth in of production from these fields. The North Amethyst field production from 2017 to 2018. Costs to construct Hebron started producing in 2010 and is the first satellite field are estimated to be around $8.3 billion. Federal and development at White Rose. First oil flowed in September provincial regulators conditionally approved development 2011 from the West White Rose area, a second satellite of the project on May 31, 2012. field, which is considered to be potentially the largest of the White Rose expansions. Oil started flowing in June The remainder of this report will focus on western Canada 2011 from the Hibernia Southern Extension development. as it is the primary source of future Canadian growth. The The Hibernia Southern Extension development added 223 degree of resurgence in conventional production has been million barrels of new reserves. even greater than we predicted last year. New drilling and completion methods have contributed to the increase of conventional crude oil production as producers have perfected hydraulic fracturing techniques coupled with horizontal drilling technologies.
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Figure 2.1 Canadian Oil Sands & Conventional Production thousand barrels per day 8,000 Actual Forecast 7,000 Eastern Canada 6,000
5,000 June 2011 Forecast Oil Sands Growth 4,000
3,000 Oil Sands Operating & In Construction 2,000
1,000 Conventional Heavy Pentanes Conventional Light 0 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Despite the resurgence of conventional production, The new long-term forecast calls for a reversal of the however, supplies from the oil sands will continue to ongoing decline in conventional crude oil production comprise the bulk of the anticipated future increases in witnessed over the past decade or more, and instead overall crude oil production. Figure 2.1 shows the Canadian shows growth in the near term. A vibrant drilling forecast production forecast. The oil sands projects that are already drives production growth until around 2017 when the currently operating or are in construction account for the impact of well production declines is expected to temper growth until 2015 or 2016. the overall growth rate.
Compared to the 2011 forecast, oil sands production is 2.2 Western Canadian Crude Oil higher by about 100,000 b/d for most of the forecast period due to the acceleration of some projects before becoming Production higher by about 480,000 b/d by 2025 due to the inclusion For western Canada, relative to the 2011 report, higher of additional projects. production is forecast in both conventional and oil sands In the last three years, there has been a significant number areas (Table 2.2). The bulk of this output originates from of direct investments made in the oil sands by Asian the Western Canada Sedimentary Basin, which covers companies. Producers turn to overseas partners to provide most of the province of Alberta, northeast British Columbia, capital to speed up development and to share in the risk southern Saskatchewan, and parts of Manitoba and the and rewards of these projects (Table 2.3). Northwest Territories.
Table 2.2 Western Canadian Crude Oil Production
million b/d 2011 2015 2020 2025 2030 Total 2.74 3.63 4.48 5.46 6.16 Conventional 1.13 1.33 1.32 1.25 1.14 (including condensate) Oil sands 1.61 2.30 3.16 4.21 5.02
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Table 2.3 Foreign Direct Investment in Oil Sands: 2009-2012
Close Date Investor Project Cost (Million $)* 2012 Jan PetroChina 40% stake in AOSC Mackay River $680 2011 Nov CNOOC Purchased OPTI’s 35 % stake in the Nexen operated US$2,100 Long Lake Project 2011 Jan PTT Exploration & Prod Purchased 40% stake in Kai Kos Dehseh from Statoil US$ 2,280 2010 Nov Korea Investment Corp Private placement 7.7 million common shares in $100 OSUM 2010 Aug Korea Investment Corp Private placement 2.5 million common shares in $76.2 Laricina 2010 Jun Sinopec Purchased 9% of Syncrude from ConocoPhillips US$ 4,650 2010 Jun China Investment Corp 45% JV with Pennwest $817 2010 Feb PetroChina Purchased 60% of MacKay River and Dover $1,900 2009 Dec Korea National Oil Co Acquisition of Harvest Energy Trust $1.8B + assumption of $2.3B debt 2009 Jul China Investment Corp Private placement for 101.3 million Class B $1,740 subordinate voting shares of Teck Resources, (approx 17.2% equity and 6.7% voting interest). Teck Resources owns a number of oil sands assets including a 20% interest in the Fort Hills mining project and the Frontier leases 2009 Apr Sinopec 10% interest in Northern Lights (now 50/50 Total/ Sinopec) * Cost stated in Canadian dollars unless otherwise specified 2.2.1 Conventional Crude Oil In Alberta, the combination of hydraulic fracturing and horizontal drilling is being used in an increasing number Production of oil plays. The most advanced plays are the Cardium in west-central Alberta, the Beaverhill Lake Carbonates Although much of Canada’s rise in importance in the global near Swan Hills, the Viking in east-central Alberta and at energy scene can be attributed to the emergence of oil Redwater, north of Edmonton. Emerging plays include the sands, a significant portion of Canada’s oil production still Alberta Bakken in the southern reaches of the province and comes from conventional production. in oil prone regions in the Duverney and Montney shale Conventional production is forecast to grow from gas plays. High drilling activity in these areas will offset 1.1 million b/d in 2011 to 1.3 million b/d by 2020, thereby the steep decline in Alberta conventional production that reversing a long term trend of continual decline. The would otherwise be expected. previous outlook for conventional crude oil declines has Russia’s largest oil company has formed a Canadian been eclipsed by the emergence of drilling for conventional subsidiary, RN Cardium Oil Inc., and picked up a non- oil that takes advantage of new production and completion operated 30 per cent equity stake in ExxonMobil’s technologies. A high level of drilling is expected to drive Harmattan tight oil play near Olds, Alberta. The investment production growth until around 2017 when the impact of is believed to be the first by a Russian firm in Canada’s oil well production declines temper the overall growth rate. and gas industry, and could help to speed up development Current estimates of the ultimate potential production activity in the Cardium play. recoverable from conventional reserves may still be conservative as these technologies are still in their early Production from Saskatchewan only grew by 2 per cent stages. Most of the conventional production comes from in 2011, however, this growth is considered to under- Alberta and Saskatchewan and is expected to be light represent production levels that would have occurred crude oil (Figure 2.2). absent poor weather and other extraordinary conditions.
5 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Figure 2.2 Western Canada Conventional Production (Light, Medium, Condensates) 2000-2015 thousand barrels per day 800 Actual (Monthly) Forecast (Annual) 700 Alberta 600
500
400
300 Saskatchewan 200
100 BC & NWT Manitoba 0 2015201420132012201120102009200820072006200520042003200220012000 2.2.2 Oil Sands Canada’s oil sands deposits are divided into three major regions in northern Alberta. The regions are referred Production from oil sands currently comprises 59 per cent to as the Athabasca, Cold Lake and Peace River of western Canada’s total crude oil production. In this deposits (Figure 2.3). The Alberta Energy Resources and forecast, oil sands production rises from 1.6 million b/d Conservation Board (ERCB) estimated at year-end 2010, in 2011 to almost double at 3.1 million b/d by 2020 and that these areas contain remaining established reserves of 4.2 million b/d by 2025 and 5.0 million b/d by the end of 169 billion barrels. the forecast period in 2030. If the only projects to proceed Figure 2.3 Oil Sands Regions were the ones in operation or currently under construction, oil sands production would still increase by 54 per cent to 2.5 million b/d by 2020 and then remain relatively flat for the rest of the forecast. Please refer to Appendix B.1 for a Athabasca detailed production data table. Deposit
Compared to CAPP’s 2011 outlook, the latest oil sands Fort McMurray Area of forecast is very similar but is higher near the end. In 2025, Peace River Potential this latest forecast is higher by 480,000 b/d. With the 5-year extension of the forecast period, more projects have been included in the outlook. The higher forecast in Peace River Deposit Cold Lake 2025 compared to CAPP’s 2011 outlook can be attributed Deposit to some acceleration project time lines and the inclusion of additional projects that are now considered more likely Edmonton Lloydminster to proceed due to increased industry confidence and the emergence of joint venture partnerships.
Calgary
Crude Oil Forecast, Markets & Pipelines 6 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Figure 2.4 Western Canada Oil Sands & Conventional Production
thousand barrels per day 8,000 Actual Forecast 7,000
6,000
5,000 June 2011 Forecast In Situ 4,000
3,000 Mining 2,000
1,000 Conventional Heavy Pentanes Conventional Light 0 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Of the remaining established reserves in Alberta, Table 2.4 Oil Sands: Raw Bitumen Production 135 billion barrels, or 80 per cent, is considered recoverable by in situ methods and 34 billion barrels or million b/d 2011 2015 2020 2025 2030 20 per cent can be recovered by surface mining. In situ Total 1.74 2.48 3.39 4.50 5.33 recovery includes both primary methods, which are similar Mining 0.89 1.21 1.52 1.93 2.17 to those used to recover conventional production, as well In Situ 0.85 1.27 1.87 2.57 3.16 as other methods whereby steam, water or other solvents are injected into the reservoir to reduce the viscosity of the Recovery of raw bitumen using in situ methods is set bitumen, allowing it to flow to a vertical or horizontal well to surpass production from mining methods by 2015, a bore. year earlier than forecast in the 2011 report. Of the in situ projects currently in operation, only the Long Lake project In 2011, 51 per cent of the total raw bitumen produced operated by Nexen Inc. is coupled with an upgrading from oil sands deposits was mined. Traditionally, mined facility. Production from the Suncor Firebag and MacKay bitumen is transformed into upgraded light crude oil as River projects are upgraded at Suncor’s integrated mining part of an overall integrated operation. However, with its facilities depending on spare capacity at the upgraders startup in 2012, the Imperial Kearl Lake mining project will and market conditions. Otherwise, the majority of in situ be the first mining project to deliver diluted bitumen into bitumen production is not upgraded prior to reaching the market as it does not have an affiliated upgrader. There markets. Recently, producers have been transporting will be additional upgrading capacity being built as a result undiluted bitumen in rail cars; the bitumen is later blended of the North West Upgrader, which is slated to come on- with condensate at facilities nearby the end market, prior to line in 2014. This facility is owned by North West Redwater delivery to the refiners. Partnership, a 50/50 joint venture between North West Upgrading and Canadian Natural Resources Limited, and would be able to upgrade some of the growing volumes of diluted bitumen available from both in situ and mining projects.
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Existing mines with integrated upgrading projects in with upgraded light crude oil (also known as “SynBit”) and operation are listed below: bitumen diluted with condensate (also known as “DilBit”). An example of DilBit would be Cold Lake crude oil, which • Suncor Steepbank and Millennium Mine; has a density of about 930 kg/m3 (21° API) and a sulphur content of 3.6%. Blending for DilBit differs slightly by • Syncrude Mildred Lake Mine and Aurora Mine; project but requires approximately a 70:30 bitumen to • Athabasca Oil Sands Project (AOSP); condensate ratio while the blending ratio for SynBit is approximately 50:50. • Shell Jackpine Mine; and As previously mentioned, bitumen is so viscous that it • Canadian Natural Resources Horizon Project. needs to be diluted with a lighter hydrocarbon, to create a type of crude oil that meets pipeline specifications for density and viscosity. The main source of diluent is 2.3 Western Canadian Crude condensate that is recovered from processing natural Oil Supply gas in western Canada, however; the needs of growing bitumen production has exceeded this supply. In 2011, an In order to be transported by pipeline and meet refinery average of almost 140,000 b/d of imported condensates, specifications, the production discussed in the previous diluents from upgraders and quantities of butane, section may be upgraded or blended to create a variety of supplemented the condensate supply. This latest forecast crude oil types. It is these volumes that comprise the crude is not constrained by the availability of condensate imports oil supply that is delivered to markets. as new sources of condensate are assumed to be available to meet market requirements. Refer to Section 4.7 for In this report, CAPP categorizes the various crude oil types additional details on existing and proposed diluent pipeline that comprise western Canadian crude oil supply into four projects. main categories: Conventional Light, Conventional Heavy, Upgraded Light and Oil Sands Heavy. Oil Sands Heavy includes upgraded heavy sour crude oil, bitumen diluted
Figure 2.5 Western Canada Oil Sands & Conventional Supply
thousand barrels per day 8,000 Actual Forecast 7,000
6,000
5,000 June 2011 Forecast Oil Sands Heavy * 4,000
3,000
2,000 Upgraded Light 1,000 Conventional Heavy Conventional Light 0 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
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A factor that could reduce estimated diluent demand would 2.5 Crude Oil Production and be an increase in the number of undiluted bitumen barrels that would be transported by rail and later blended with Supply Summary condensate at facilities located in destination markets. Compared to the 2011 outlook, western Canadian Table 2.5 shows the projections for total western Canadian conventional production is higher by 388,000 b/d by 2025. crude oil supply. Refer to Appendix B.2 for detailed This higher forecast is supported by higher production, data. Light crude oil supply is projected to grow from mostly from Alberta and Saskatchewan, resulting from 1.3 million b/d in 2011 to 1.9 million b/d in 2020 and then increased drilling of horizontal wells that have higher remains relatively flat thereafter since little new upgrading initial production rates than traditional vertical wells. Oil capacity is currently expected to be built. Heavy crude oil sands production is higher by 478,000 b/d resulting from supply is projected to grow from 1.6 million b/d in 2011 accelerated project time lines and the addition of new to 3.0 million b/d in 2020 to more than triple the current projects that industry has reported in the survey. volume in 2030, when it reaches 5.1 million b/d. Production from offshore Atlantic Canada will remain Table 2.5 Western Canadian Crude Oil Supply relatively stable for most of the forecast and averages around 220,000 b/d until 2022, supported by production million b/d 2011 2015 2020 2025 2030 from satellite fields and the Hebron project starting up in Total 2.92 3.89 4.95 6.18 6.87 2017. In 2024, production falls to just over 170,000 b/d and Light 1.31 1.80 1.91 1.95 1.77 declines steadily thereafter. Heavy 1.61 2.09 3.04 4.23 5.10 Overall, compared to CAPP’s 2011 forecast, total Canadian outlook is higher by 885,000 b/d by 2025. The Upgraded Light crude oil supply includes the light crude oil volumes produced from:
• Upgraders that process conventional heavy oil, e.g., the Husky Upgrader at Lloydminster and the CCRL Upgrader in Regina;
• Integrated mining and upgrading projects, e.g. Suncor, Syncrude and Canadian Natural Resources operations;
• Integrated in situ projects, e.g., the Nexen Long Lake project;
• Off site upgraders, e.g., the Athabasca Oil Sands Project; and
• the North West Partnership North West Upgrader
Compared to the 2011 forecast, the overall light crude oil supply is higher due to increased conventional production. The Oil Sands Heavy category is forecast to increase from 1.3 million b/d in 2011 to 3.9 million b/d in 2025 and up to 4.8 million b/d at the end of the forecast period in 2030.
9 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. 3 CRUDE OIL MARKETS
The production of crude oil in Canada far exceeds its domestic refining capacity. This chapter discusses the outlook for the consumption of Canadian crude oil in both markets that have been traditionally served by this supply and new markets that may also be potentially served as more transportation infrastructure is developed. Figure 3.1 shows the demand for crude oil in the major refining regions in Canada and the U.S. The U.S. Gulf Coast provides the most significant opportunity for Canadian supplies for market diversification in North America. In 2011, the U.S. Gulf Coast imported some 4.8 million b/d from non-Canadian sources. Figure 3.1 Canada and U.S. Market Demand for Crude Oil in 2011 by Source thousand barrels per day
AB, BC, SK [577] Atlantic Canada [411]
PADD V - excl CA [731] ON, QC [681] PADD IV PADD II - North [544] (ND, SD,MN, WI) [439] PADD V - CA [1,614] PADD I - East Coast [1,097]
PADD II - South (KS, OK) [741] PADD II - East (MI, IL, IN, OH, KY, TN) [2,191] U.S. - Alaska only U.S. (excl Alaska) Other Imports E. Canada W. Canada
PADD III - Gulf Coast [2011 total refinery demand] Source: EIA, Statistics Canada [7,475]
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In 2011, western Canada supplied 2.9 million b/d to In 2011, Canadian refineries processed 878,000 b/d various markets. Domestic demand for western Canadian of western Canadian crude; 111,000 b/d of crude oil crude oil was 878,000 b/d and the remaining supply produced in eastern Canada; and 680,000 b/d of foreign of over 2.0 million b/d, or 70 per cent, was exported imports. The Canadian demand for western Canadian (Figure 3.2). PADD II which comprises the U.S. Midwest is crude oil is expected to increase to 978,000 b/d by the largest regional market for western Canadian crude oil. 2020 with planned refinery expansions and future transportation infrastructure developments. 3.1 Canada Only about 60 per cent of the crude oil processed in Canada is sourced from domestic production since refineries in eastern Canada have limited access to western Canadian crude oil supplies. The current oil pipeline network exiting western Canada is connected to refineries in western Canada and Ontario. According to Statistics Canada, Québec processed small volumes of western Canadian crude oil in 2011. This would be the first year since 1999 that this has occurred. With no direct pipeline access, these volumes were either delivered by rail or truck.
Figure 3.2 Market Demand for Western Canadian Crude Oil: Actual 2011 and 2020 Additional thousand barrels per day
632 Supply 2011 - 2,918 577 [+56] 2020 - 4,946 Non-US 795 35 [unknown]
301 [+37] PADD IV PADD II PADD V 630 3,775 3,261 1,142 234 [+10] 1,436 [+466] 178 [+65] 59 [+11] 2012 Total Refining Capacity PADD I 9,078 PADD III 2011 Actual 2020 Potential Demand Additional Demand 112 [+1,158] Sources: CAPP, EIA, NEB, Statistics Canada Note: 2011 demand exceeds available supply by 14,000 b/d likely due to factors such as inventory adjustment and data discrepancies in information collection.
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3.1.1 Western Canada as Imperial’s refinery in Nanticoke, Ontario would be able to receive greater volumes of western Canadian crude oil. The eight refineries located in western Canada exclusively Ultimately, the refineries will select their feedstock from process western Canadian crude oil. These refineries have a variety of sources based on both availability and price a total refining capacity 632,000 b/d. In 2011, they refined (Figure 3.4). some 576,600 b/d of crude oil and this volume is expected to increase to 632,800 b/d by 2020 (Figure 3.3). Future According to Statistics Canada, Ontario refineries received additional western Canadian crude oil receipts are related 351,700 b/d of crude oil in 2011 from the following to expansion plans for the Consumers’ Co-operative sources: Western Canada (298,300 b/d or 84.8 per cent); refinery, located in Regina, Saskatchewan and the Eastern Canada (1,400 b/d or 0.4 per cent); North Sea start-up of the North West Redwater Partnership North (18,000 b/d or 5.1 per cent); United States and Mexico West Upgrader. The Moose Jaw refinery in Moose Jaw, (14,000 b/d or 4.0 per cent); and other foreign sources Saskatchewan produces mostly asphalt while the other (20,000 b/d or 5.7 per cent). refineries manufacture a wide range of petroleum products. Figure 3.4 Ontario: Forecast Western Canadian Crude Oil Receipts Figure 3.3 Western Canada: Forecast Western Canadian Crude Oil Receipts 400 Total refining capacity = 393 thousand barrels per day 700 Total refining capacity = 632 thousand barrels per day 350 600 300 500 250 400 200 300 150 100 200 50 100 0 0 2020201920182017201620152014201320122011 2020201920182017201620152014201320122011 Light Synthetic Light Synthetic Conventional Light Sweet Conventional Light Sweet Conventional Medium Sour Conventional Medium Sour Heavy Heavy Source: 2012 CAPP Refinery Survey Source: 2012 CAPP Refinery Survey 3.1.1 Ontario 3.1.3 Québec There are four refineries located in Ontario (excluding the The refineries in Québec process crude originating from Nova Chemical refinery and petrochemical complex in both Atlantic Canada and foreign sources. However, Sarnia) with a total refining capacity of 393,000 b/d. They Statistics Canada reported average crude oil receipts from primarily process western Canadian crude oil but also western Canada for June and July in 2011 of 16,000 b/d. refine some imported crude oil and some volumes from Québec has two refineries with a combined capacity of Atlantic Canada. The supply from the latter two sources 402,000 b/d. These refineries are configured to process arrive on the Atlantic seaboard by tanker and are then mostly light crude oil. If Enbridge’s Line 9 Re-reversal transported through the Portland-to-Montréal Pipeline proposal obtains regulatory approval to flow east all the before being transported on the Enbridge Montréal-to- way to Montréal as proposed in Enbridge’s second project Sarnia Pipeline (Line 9). Enbridge has applied to the NEB on Line 9, these refineries would have access to the to re-reverse the direction of the Line 9 segment from growing light oil production from western Canada and the Sarnia to Westover, Ontario to flow eastward. Refer to U.S. Bakken in Montana and North Dakota. Section 4.5 for details on oil pipelines to Eastern Canada. If approved, there could be some increase in receipts of western Canadian crude oil in the region from 2013 onward
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Once crude oil reaches Montréal, companies could barge The U.S. Department of Energy divides the 50 states in oil from there to Québec City, and potentially even ship it the U.S. into five Petroleum Administration for Defense by rail to Saint John, New Brunswick. Districts or PADDs (Appendix C). The PADDs were originally delineated during World War II for oil allocation Suncor has reported that it continues to assess the purposes and remain the convention for describing U.S. feasibility of building a coker at its Montréal refinery. If this market regions. project is ultimately developed, there would be increased demand for heavy crude oil in this region.
The Atlantic refineries represent a possible additional outlet 3.2.1 PADD I (East Coast) for western Canadian crude oil but the transportation cost PADD I is located along the east coast of the United States for these refineries to access these supplies would be a with refineries in Delaware, Georgia, New Jersey, major consideration given the lack of infrastructure. These Pennsylvania, and West Virginia. There are nine refineries refineries have a total refining capacity of 497,000 b/d with a total refining capacity of 1.1 million b/d. As shown in and currently source crude oil from a number of global Table 3.1, a number of refineries have closed in the past suppliers. In May 2012, Imperial announced that its few years. Dartmouth refinery will be put up for sale and potentially converted to an oil terminal or permanently shutdown, In 2011, imports of foreign crude oil by refineries in PADD I thereby decreasing the refining capacity in this market. A totaled 1.1 million b/d, which is virtually unchanged from final decision will be made in May 2013. 2010. About 66 per cent of these volumes were light sweet crude oil (Figure 3.5). Two refineries located in Pennsylvania were idled in the latter part of 2011. Since then, the Phillips 3.2 United States 66 refinery in Trainer was purchased by Delta Air Lines with the transaction to close in the first half of 2012; however, a The United States is the world’s largest oil market with re-startup schedule has not yet been announced. Since a total refining capacity of almost 18 million b/d. Since these refineries processed light and medium crude oil, 2004, Canada has been the largest exporter of crude oil lower imported volumes of light crude oil in 2012 versus to the U.S. The U.S. demand for western Canadian crude 2011 can be expected. Higher imports of heavy crude oil oil supply is expected to reach 3.7 million b/d in 2020 are anticipated since PBF Energy’s Delaware City refinery, assuming the proposed infrastructure receives regulatory which processes primarily heavy oil, started up again in approval to connect growing western Canadian supplies to October 2011. The refinery had previously been idled since the large U.S. Gulf Coast market. November 2009.
In 2011, Canada exported over 2.2 million b/d to the Figure 3.5 2011 PADD I: Foreign Sourced Supply by U.S., which was 12 per cent more than in 2010 and was Type and Domestic Crude Oil equivalent to almost 25 per cent of total U.S. imports.
Of these volumes, 2.0 million b/d was sourced from Total refining capacity = 1,142 thousand barrels per day western Canada. The next largest sources of imports Domestic crude to the U.S. were Saudi Arabia, Mexico and Venezuela. 58 Western Canadian production could continue to capture 119 an even larger share of U.S. imports as it replaces volumes currently supplied by these countries. A number of factors Heavy in the near term are expected to reduce supplies available to the U.S. from these sources. These include: declining Light/Medium 233 production, increased domestic consumption and the Sour diversion of supplies to Asia. Light Sweet*
687
* Includes small volumes of Medium Sweet Source: EIA
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Table 3.1 Summary of Refinery Closures/Expansions in PADD 1
Current Capacity Scheduled Operator Location (thousand b/d) In-Service Description Sunoco Eagle Point, NJ 150 (loss) Feb 2010 Closed; asphalt refinery Western Yorktown, NJ 70 (loss) Sep 2010 Closed; asphalt refinery Refining Phillips 66 Trainer, PA 185 (loss) Idled since Idled. Purchased by Delta Air Lines in April 2012; Sep 2011 transaction to close 1H 2012. PBF Energy Delaware City, 190 Oct 2011 PBF purchased the refinery in an idled state from DE Valero in June 2010 and restarted it in Oct 2011. The refinery had been idled since Nov 2009. Sunoco Marcus Hook, 175 (loss) Idled since Idled. For Sale with the intention to permanently PA Dec 2011 close if no buyer by July 2012. Sunoco was purchased by Energy Transfer in April 2012 but under the agreement Sunoco will continue its plans to exit the refining business. PBF Energy Delaware City, 2014/2015 $1B project consisting of construction of a mild DE hydrocracker and hydrogen plant. Sunoco Philadelphia, PA 330 (potential Jul 2012 Operating but Sunoco announced that if no buyer loss) found by July 2012, it would close. The EIA noted that the closed and idled capacity on the 3.2.2 PADD II (Midwest) east coast can be replaced with increased refining capacity in other regions. However, there are transportation PADD II has a total refining capacity of 3.7 million b/d and constraints that may hinder the delivery of refined products in 2011, received almost 1.5 million b/d of foreign sourced to east coast markets that currently rely on local refining crude oil, about 67 per cent of which were heavy crude capacity. Ultra-low sulphur diesel fuel will be the most oil volumes (Figure 3.6). Crude oil from western Canada challenging product to replace as there are few alternative totaled over 1.4 million b/d, making Canada the primary supply sources outside of the U.S. Gulf Coast. source of supplies. In 2011, most of the growth in western Canadian production was delivered to this market. Transportation constraints may also hamper the movement of products through Pennsylvania and into western New Figure 3.6 2011 PADD II: Foreign Sourced Supply by York, areas that are currently supplied by pipelines Type and Domestic Crude Oil originating in the Philadelphia area refinery complex. The industry may not be able to overcome all of the logistical Total refining capacity = 3,775 thousand barrels per day challenges in the Northeast for a year or more, as infrastructure changes will be necessary to accommodate the changing product flows. 1,013 With a full year of net refining capacity lost due to refinery closures, an overall decline in imports and total volumes Heavy processed in PADD I can be expected. PADD I imported
223,800 b/d of crude oil from Canada. About 58,600 b/d 1,851 Domestic Crude was sourced from western Canada and was primarily delivered to the United refinery in Warren, Pennsylvania. 195 Light/ NuStar Energy has reported its intention to process Light Medium Sour 5,000 b/d to 10,000 b/d of Canadian crude oil at its asphalt Sweet* refinery in 2012. This oil would be transported by rail. 313
* Includes small volumes of Medium Sweet Source: EIA
Crude Oil Forecast, Markets & Pipelines 14 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
PADD II can be further divided into the Northern, Eastern, Figure 3.7 PADD II (North): Forecast Western Canadian and Southern PADD II states. The primary market hubs Crude Oil Receipts within PADD II are located at Clearbrook, Minnesota for the Northern PADD II states; Wood River-Patoka, Illinois area 500 Total refining capacity = 497 thousand barrels per day for the Eastern PADD II states; and Cushing, Oklahoma for 450 the Southern PADD II states. The following subsections will 400 discuss these markets in greater detail. 350 300 The Midwest region is currently Canada’s largest market 250 due to its close proximity, large size and established 200 pipeline network. However, this historically attractive 150 market has become saturated as evidenced by the large 100 buildup of inventories from growing domestic production 50 0 and imports from western Canada. A number of refineries 2020201920182017201620152014201320122011 have announced projects designed to increase the heavy Light Synthetic oil processing capability but there has been some delay in Conventional Light Sweet Conventional Medium Sour their startup due to the growing availability of light volumes Heavy from domestic production. Source: 2012 CAPP Refinery Survey Northern PADD II Eastern PADD II
Northern PADD II consists of North Dakota, South Eastern PADD II consists of Michigan, Illinois, Indiana, Dakota, Minnesota and Wisconsin. There is one refinery Kentucky, Tennessee and Ohio and has 13 refineries in both North Dakota and Wisconsin and two refineries with a total refining capacity of 2.5 million b/d. In 2011 in Minnesota. These four refineries have a total refining western Canadian crude oil accounted for 1.1 million b/d or capacity of 497,000 b/d. In 2011, foreign imports into 93 per cent of the total foreign imports into the region. northern PADD II were 295,700 b/d, all sourced from western Canada. Imports of western Canadian crude oil There are several refining expansion projects that will are expected to grow moderately to 342,300 b/d by 2020 be starting up in the next two years that are designed to (Figure 3.7). Growth in Canadian crude oil processed will process heavy crude oil sourced primarily from western be limited by the growing availability of crude oil from U.S. Canada (Figure 3.8). Table 3.2 summarizes the recent domestic production. Tesoro announced plans to expand and upcoming refinery upgrades announced for Eastern crude capacity at its Mandan, North Dakota refinery to PADD II. 68,000 b/d by the end of 2013 to handle increased crude oil Figure 3.8 PADD II (East): Forecast Western Canadian volumes available from the U.S. Bakken play. Crude Oil Receipts
2,000 Total refining capacity = 2,471 thousand barrels per day 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 2020201920182017201620152014201320122011
Light Synthetic Conventional Light Sweet Conventional Medium Sour Heavy
Source: 2012 CAPP Refinery Survey
15 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Table 3.2 Summary of Major Announced Refinery Upgrades in Eastern PADD II
Current Capacity Scheduled Operator Location (thousand b/d) In-Service Description WRB Refining Roxana, IL 306 2011 Add a 65,000 b/d coker; increase total crude oil refining capacity by 50,000 b/d; increase heavy oil refining capacity to 240,000 b/d. BP Whiting, IN 400 Late 2012 to mid Construction of 70,000 b/d new coker and a 2013 new crude distillation unit. Marathon Detroit, MI 102 Mid 2012 Increase heavy oil processing capacity by 80,000 b/d and increase total crude oil refining capacity to 115,000 b/d. Husky Lima, OH 160 1H 2013 Increase capacity to 170,000 b/d; 105,000 b/d would be heavy crude capacity. New 20,000 b/d kerosene hydrotreater.
Southern PADD II Figure 3.9 PADD II (South): Forecast Western Canadian Crude Oil Receipts Southern PADD II has seven refineries, located in Kansas and Oklahoma that account for a combined refining 200 Total refining capacity = 807 thousand barrels per day capacity of 807,000 b/d. Cushing, Oklahoma is a hub that 180 traditionally received crude oil predominately from pipelines 160 140 transporting offshore crude oil delivered by tanker to the 120 U.S. Gulf Coast. This crude oil is then distributed by a 100 number of pipelines exiting the hub which serve refineries 80 throughout the PADD II and PADD III regions. However, 60 pipeline infrastructure has recently been constructed to 40 transport growing western Canadian and U.S. 20 0 Mid-continent crude oil volumes to the hub. These crude 2020201920182017201620152014201320122011 oil supplies are building up in storage in the region due to Light Synthetic the lack of connectivity to markets, particularly those Conventional Light Sweet located on the Gulf Coast. A number of pipeline projects Conventional Medium Sour Heavy are expected to come into service that will remove some of these bottlenecks. The most recent project of note would Source: 2012 CAPP Refinery Survey be the reversed Seaway pipeline that started operating in May 2012 and increases takeaway capacity from Cushing and transports crude oil volumes to the Gulf Coast.
Crude Oil Forecast, Markets & Pipelines 16 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
3.2.3 PADD III (Gulf Coast) Figure 3.10 2011 PADD III: Foreign Sourced Supply by Type and Domestic Crude Oil
PADD III is comprised of Alabama, Arkansas, Louisiana, Total refining capacity = 9,078 thousand barrels per day Mississippi, New Mexico and Texas. The refineries in this market have a total refining capacity of 9.1 million b/d, of which a significant portion has heavy crude oil processing capabilities. 2,549 2,380 In 2011, PADD III imported 4.9 million b/d of crude oil from foreign sources, of which 2.4 million b/d was heavy crude Domestic Heavy Crude oil (Figure 3.10). The top five sources of these imports are as follows: Mexico (22 per cent), Saudi Arabia (17 per cent), Venezuela (16 per cent), Nigeria (9 per cent), and Columbia (6 per cent). Deliveries of western Canadian crude oil to Light Light/Medium this market totaled 112,000 b/d, almost all of which was Sweet* Sour transported through the ExxonMobil Pegasus pipeline. 1,664 About 79 per cent of the heavy oil imports in the region are 881 from Mexico, Venezuela and Columbia. * Includes small volumes of Medium Sweet Source: EIA
th Mexico is the 7 largest crude oil producer in the world. Total exports from Venezuela have also been declining However, the 2.96 million b/d of production in 2011 due to both production declines and increased exports to represented the seventh straight year of declining China. production. Mexico’s production from its once prolific Cantarell and Ku Maloob Zaap oil fields are undergoing A number of pipeline projects will extend the reach of steep declines. Mexico’s state-owned company, Pemex, western Canadian producers into the Gulf Coast market in is struggling to stabilize output from projects located in the next few years. By 2020, CAPP has estimated that this the deep waters of the Gulf of Mexico. Recent increases market could receive at least an additional 1.1 million b/d in Mexico’s own refining capacity has led to a decline based on contractual commitments on the Keystone XL in exports, most of which have traditionally gone to the and Flanagan South pipelines. United States. Mexico’s Minatitlan refinery’s processing Table 3.3 summarizes the recently completed major capacity was expanded by 110,000 b/d in 2011. refinery upgrades and future upgrades announced for the region. Table 3.3 Summary of Major Announced Refinery Upgrades in PADD III
Current Capacity Scheduled Operator Location (thousand b/d) In-Service Description Hunt Refining Tuscaloosa, AL 72 Dec 2010 Increased capacity from 52,000 b/d to 72,000 b/d. Delayed coker was expanded to double in size to 32,000 b/d. Total Port Arthur, TX 232 Mar 2011 Increased capacity from 175,000 b/d to 232,000 b/d. Project included a 50,000 b/d coker; a 55,000 b/d vacuum distillation unit and a 64,000 b/d distillate hydrotreater. Motiva Port Arthur, TX 285 2012 Addition of new single-train distillation unit with Enterprises capacity of 325,000 b/d that would increase total capacity to over 600,000 b/d. New 95,000 b/d delayed coker; 85,000 b/d catalytic reformer, 75,000 b/d. Valero McKee, TX 170 2014 Increase capacity by 25,000 b/d. Expansion will process WTI and locally produced crude oil.
17 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
3.2.4 PADD IV (Rockies) 3.2.5 PADD V (West Coast) PADD IV includes the states of Idaho, Montana, Wyoming, PADD V includes the states of Alaska, Washington, Oregon, Utah, and Colorado. It has 14 refineries spread out in every California, Nevada, Arizona and Hawaii. The majority of state except Idaho. PADD IV has a total refining capacity of PADD V is geographically divided from the rest of the United 630,300 b/d with foreign imports being exclusively supplied States by the Rocky Mountains. It has very good access to from western Canada. tankers, and is located in close proximity to production from Alaska and California. Nonetheless, this market still depends In 2011, PADD IV processed 234,200 b/d of Canadian on foreign imports for a large portion of its requirements crude oil representing about 43 per cent of its feedstock (Figure 3.12). requirements. Throughout the forecast period, western Canadian crude oil receipts are forecast to remain relatively For the purposes of the remainder of this report, the PADD V flat (Figure 3.11). The U.S. shale production is light oil market region will focus only on Washington and California, and would not compete directly with the heavy crude oil as these states represent both the current demand and imports available from western Canada. In January 2012, future prospects for western Canadian crude oil. the Sinclair refinery in Sinclair, Wyoming was expanded Figure 3.12 2011 PADD V: Foreign Sourced Supply by from 60,000 b/d to 80,000 b/d. A coker unit and sulphur Type and Domestic Crude Oil plants were added to the facility.
Total refining capacity = 3,261 Figure 3.11 PADD IV: Forecast Western Canadian thousand barrels per day Crude Oil Receipts
387 552 600 Total refining capacity = 630 thousand barrels per day
500 Domestic Heavy Alaska 400
300 Light/Medium 546 Sour 200 Other Domestic 100 Light Sweet* 0 639 2020201920182017201620152014201320122011 221 Light Sweet* *Includes small volumes of Medium Sweet * Includes small volumes of Medium Sweet Light/Medium Sour Source: EIA Heavy Source: 2012 CAPP Refinery Survey
Crude Oil Forecast, Markets & Pipelines 18 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Washington California
There are five refineries in Washington that have a California has 17 refineries with a total refining capacity of combined capacity of 629,000 b/d. As production from 2.1 million b/d. Most of the refineries are located near the Alaska, the primary source of feedstock, has been coast in the Los Angeles area and in the San Francisco Bay declining since 2002, Washington refineries are growing area. These refineries account for almost 95 per cent of the more dependent on foreign imports from Canada and other refining capacity in the state. There is no direct pipeline to countries. In 2011, these refineries imported 245,800 b/d California from producing regions outside of California. of crude oil from foreign sources. The top three sources Therefore, as Alaskan crude oil declines an opportunity were Canada (58 per cent), Russia (21 per cent), and Oman arises to process more crude oil from Canada. Western (7 per cent). Canadian crude oil would first have to be transported either on the Trans Mountain pipeline to the Westridge dock or by Tesoro is building capacity to receive 30,000 b/d of North rail to the west coast where it would be loaded on to Dakota crude oil by rail at its refinery located in Anacortes tankers. The Enbridge Gateway and Trans Mountain by September 2012. The company is also planning to Pipeline Expansion projects represent an opportunity for apply for permits that would double the capacity to greater future access to this market. 60,000 b/d. In 2011, receipts of western Canadian crude oil were 147,600 b/d. Given the limited pipeline capacity In 2011, California refineries imported 789,700 b/d of crude available to the west coast, the use of rail could provide oil from foreign sources (Figure 3.14). The top three source some additional access to this market in the near term. countries were Saudi Arabia (29 per cent); Ecuador CAPP’s refinery survey of this market indicates a higher (22 per cent); and Iraq (16 per cent). Canada only demand in 2017, which corresponds to the timing of the accounted for 4 per cent of total foreign imports. startup of announced pipeline projects to the west coast. Figure 3.14 2011 PADD V (California): Foreign Sourced Figure 3.13 Washington: Forecast Western Canadian Supply by Type and Domestic Crude Oil
Crude Oil Receipts Total refining capacity = 2,102 thousand barrels per day
195 348 600 Total refining capacity = 629 thousand barrels per day Domestic 500 Alaska Heavy 400
300 Other Light/ 200 Domestic Medium Sour 100 415 629 0 2020201920182017201620152014201320122011 Light Synthetic Conventional Light Sweet 27 Light Conventional Medium Sour Sweet* Heavy Source: 2012 CAPP Refinery Survey * Includes small volumes of Medium Sweet Source: EIA and the California Energy Commission
19 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
3.3 Asia 3.5 Markets Summary Asia is the world’s fastest growing energy market and The refineries on the U.S. Gulf Coast still represent an China and Japan are the second and 3rd largest oil markets attractive market for Canadian crude oil supplies. Despite in the world. World oil demand remains strong despite a increasing U.S. domestic production, growing western slowdown in the U.S. and European economies because of Canadian crude oil supplies can still establish a larger increased demand in the Middle East and Asia. Japanese market share in this region as pipeline infrastructure is demand for crude oil as a source of power generation has developed. Foreign imports account for the majority of also increased somewhat in order to make up for some of the feedstock requirement today but heavy crude oil from the lost nuclear generating capacity as a result of the western Canada is well suited to displace a portion of Fukushima Daiichi nuclear disaster. the imports from Venezuela and Mexico. Based on the contractual commitments that have been obtained to The outlook for China’s demand for heavy crude oil is underpin pipeline projects that would provide capacity improving, which is attributable to several modernizing to the Gulf Coast, western Canadian producers could projects in the last few years that have added new coking supply at least 1.1 million b/d into this market by 2020. capacity. This has enabled Brazil to emerge as a growing The demand for western Canadian crude oil in the U.S. supplier of medium heavy crude oil to this market without Midwest is expected to rise by almost 470,000 b/d. The directly competing with the established Middle East current flow of crude oil into this region far exceeds its producers, who are suppliers of light sour crude oil. ability to process it and there is insufficient takeaway capacity to move these growing supplies beyond the Canadian synthetic crude oil is suitable for Japanese Cushing hub. Refineries in California and Washington refineries but would compete with sour grades imported are expected to import increasing volumes of foreign from the Middle East. Table 3.4 shows oil demand from sourced crude given declining production from Alaska and 2009 to 2012 in the major Asian markets. The International western Canadian producers can compete for this market Energy Agency (IEA) forecasts that oil demand from China opportunity. and India will grow in 2012 by 4 per cent and 3 per cent, respectively. With growing North American supplies being forecast in conjunction with a flat outlook for crude oil demand in the However, there is currently limited pipeline capacity U.S., producers are seeking to establish relationships with available for the transportation of western Canadian crude Asian refineries in order to diversify their export markets. oil to the west coast. The earliest that Canadian crude oil China continues to emerge as a significant market, producers would be able to increase their market share in importing 5.7 million b/d of oil in 2011. Asia is in 2017, if a new pipeline project to the west coast is approved. Figure 3.15 Net Oil Imports: Asia 2010 to 2030 Table 3.4 Total Oil Demand in Major Asian Countries
million b/d 2009 2010 2011 2012 15,000 thousand barrels per day China 8.06 9.07 9.51 9.90 2010 2020 12,000 India 3.26 3.34 3.47 3.59 2030 Japan 4.39 4.45 4.48 4.52 9,000 Korea 2.19 2.25 2.23 2.24
6,000 Source: IEA Oil Market Report, May 2012
3,000
0 China India Japan South Korea
Source: EIA 2012 Annual Energy Outlook, Early Release
Crude Oil Forecast, Markets & Pipelines 20 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. 4 CRUDE OIL PIPELINES
Western Canadian crude oil is virtually landlocked and as such has very limited connectivity to world markets. Growing conventional, oil shale and oil sands production has created an urgent need for additional transportation infrastructure. Steps are being taken to address this need through a number of project proposals including new pipelines, expansions or modifications to existing infrastructure and increased transportation by rail. Pipelines will, however; continue to be the dominant mode of transportation for crude oil but it will take a few years for pipeline infrastructure to be built. In the short-term, crude oil transport by rail will increase sharply due to the ability to add rail capacity relatively quickly and in small increments as needed and utilizing the rail infrastructure already in place.
Figure 4.1 Canadian and U.S. Crude Oil Pipelines - All Proposals
Kitimat Enbridge Gateway
Trans Mountain Edmonton
Hardisty Burnaby Alberta Clipper Expansion Anacortes Bakken Expansion Kinder Morgan TM Expansion (TMX) Cromer
Southern Access Expansion Express Clearbrook TransCanada Superior Montréal Keystone XL Enbridge Line 9 Reversal St. Paul Portland Enbridge Guernsey Sarnia Salt Lake City Platte Flanagan Chicago TransCanada Keystone BP Lima Spearhead North Expansion Spearhead South Wood Patoka River Flanagan South Mustang Canadian and U.S. Oil Pipelines Centurion Pipeline Cushing Mid Valley Enbridge Pipelines and connections Capline to the U.S. Midwest and E. Canada ExxonMobil Pegasus El Paso Seaway Reversal Kinder Morgan Express & Twin Line Kinder Morgan Trans Mountain TransCanada Gulf Coast Crane TransCanada Keystone Port Arthur Proposed pipelines to the West Coast Magellan Houston to New Orleans El Paso (former Longhorn) Houston Existing / Proposed pipelines to PADD III - partial conversion Freeport St. James Expansion/Reversal to existing pipeline Shell Ho-Ho
21 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Higher than expected production from Alberta and Table 4.1 Major Existing Crude Oil Pipelines and Saskatchewan conventional oil developments; the growth Proposals Exiting the WCSB in North Dakota Bakken production, and new U.S. shale (Niobrara, Eagle Ford, etc.) production have added to the Annual challenges to be resolved regarding the transportation of Pipeline Crude Type Capacity growing oil sands production. (thousand b/d) Light 1,081 Tight pipeline capacity as a result of these growing Enbridge Heavy 1,246 supplies has been one of the major reasons for the discounted prices received by Canadian and Mid-continent AB Clipper Heavy +120 (in 2014) crude oil producers, whose production is priced off of WTI Expansion and not Brent, which is the global benchmark. Enbridge +525 (in 2017) Gateway The existing pipeline network provides access to a number of markets for western Canadian crude oil including: Express Light/heavy (35/65) 280 western Canadian refineries; Ontario, the U.S. Midwest; Trans Mountain Light/heavy (80/20) 300 PADD IV; and the West Coast. There is very limited access to the U.S. Gulf Coast. The major pipeline proposals TM Expansion +450 (in 2017) currently being assessed are primarily expansions into the U.S. Gulf Coast and for exports off Canada’s west Keystone Light/heavy (25/75) 591 coast. Figure 4.1 shows all existing pipelines and active Keystone XL Light/heavy +830 (in 2015) proposals. Total Existing Capacity 3,498 4.1 Existing Crude Oil Pipelines Crude oil production from Montana and North Dakota Exiting Western Canada enters the Enbridge Mainline system through Enbridge’s There are four major pipelines that are directly connected North Dakota pipeline, which has a capacity of 210,000 b/d to the Canadian supply hubs at Edmonton and and is connected at Clearbrook, Minnesota. The Bakken Hardisty, Alberta: Enbridge Mainline, Kinder Morgan Expansion project, which entails connecting production Trans Mountain Pipeline, Kinder Morgan Express Pipeline, received at Berthold, North Dakota for delivery to the and TransCanada Keystone Pipeline. Cumulatively, these Enbridge Mainline at Cromer, Manitoba was approved by pipelines provide a total annual average pipeline capacity the NEB in December 2011. The incremental capacity of out of western Canada of 3.5 million b/d. Proposals have 145,000 b/d is expected to be in-service in 2013 and is been announced that would increase this capacity in designed to accommodate some of the escalating crude oil 2014 and 2015 (Table 4.1). Existing capacity is currently production from the Bakken play. constrained somewhat by the available takeaway capacity of connecting downstream pipelines. Capacity was further Enbridge Mainline Expansions - Alberta impacted in 2011 and early 2012 by short-term disruptions Clipper and Southern Access and pressure restrictions. The Alberta Clipper forms part of the Enbridge Mainline capacity exiting western Canada. It is a 36-inch pipeline Enbridge Pipelines extending from Hardisty, Alberta to Superior, Wisconsin with a capacity of 450,000 b/d that can be expanded to an ultimate capacity of 800,000 b/d with the addition of The Enbridge Mainline is a multi-pipeline system that pumping stations. Enbridge has announced that it will be delivers crude oil and other refined products from western expanding the Alberta Clipper pipeline by 120,000 b/d in Canada, Montana and North Dakota to markets in western 2014. Canada, the U.S. Midwest and Ontario. It further extends its reach into additional markets through connections with a number of pipelines, namely the Minnesota Pipeline at Clearbrook, Minnesota and Spearhead South at Flanagan, Illinois. The receipt capacity of the Mainline system originating in western Canada is 2.3 million b/d.
Crude Oil Forecast, Markets & Pipelines 22 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
The Southern Access Pipeline originates downstream of Kinder Morgan Express-Platte Pipelines the Alberta Clipper at Superior, Wisconsin and runs to Flanagan, Illinois. It has a current capacity of 400,000 b/d, The Express Pipeline system is a batch-mode, common which can be expanded up to 1.2 million b/d. Enbridge has carrier pipeline system comprised of the Express Pipeline announced that it will expand the line by 160,000 b/d in and the Platte Pipeline that connects Canadian and 2014. U.S. crude oil producers to refineries in PADD IV and the U.S. Midwest. The Express Pipeline is a 24-inch These Mainline expansions are required to support access diameter pipeline that originates at Hardisty, Alberta and to the U.S. Gulf Coast, ultimately through a connection to terminates at the Casper, Wyoming facilities on the Platte the Seaway Pipeline. Pipeline. Approximately 231,000 b/d out of the pipeline’s total capacity of 280,000 b/d has been secured by firm Kinder Morgan Trans Mountain Pipeline contracts from 2012 through to 2015. The Platte Pipeline is a 20-inch diameter pipeline that runs The Trans Mountain system originates in Edmonton, from Casper, Wyoming to refineries and interconnecting Alberta and transports crude oil and petroleum products to pipelines in the Wood River, Illinois area. The Platte Pipeline delivery points in British Columbia. These delivery points has capacity of 150,000 b/d from Casper, Wyoming and include the Westridge dock for offshore exports to final approximately 140,000 b/d downstream of Guernsey, destinations that include California, Asia and the U.S. Gulf Wyoming. Coast, as well as to a pipeline that provides deliveries to refineries in Washington State. Express currently has capacity on its system that can’t be used due to insufficient downstream capacity available on In December 2011, the NEB approved Kinder Morgan’s the Platte Pipeline. The Canadian portion of throughput application to convert 54,000 b/d of common carrier exiting Guernsey in 2011 was 43 per cent versus capacity to firm service and change the land dock 60 per cent in 2010. allocation on the system. Consequently, since February 2011, of the current pipeline capacity of 300,000 b/d (assuming 20 per cent of the volumes being transported TransCanada Keystone and Cushing are heavy crude oil), 221,000 b/d is allocated to refinery Extension and terminal locations in British Columbia and Washington The existing Keystone pipeline system runs from State and 79,000 b/d is allocated to Westridge dock Hardisty, Alberta to terminals in Wood River and Patoka, shippers. The capacity designated to the dock is further Illinois and has been in operation since June 2010. The divided between 54,000 b/d underpinned by firm contracts Keystone Cushing Extension, which runs from Steele City, and the remainder available for spot shippers. Nebraska to Cushing, Oklahoma has been in-service since There was high apportionment on the pipeline throughout February 2011. The system can deliver a total capacity of 2011; indicating strong demand by both land and dock 591,000 b/d, to either Wood River or Cushing depending shippers. The situation was magnified by pressure on market requirements. Originally Keystone was restrictions on the pipeline between April 2011 and March underpinned by 375,000 b/d of contracted capacity while 2012. Strong demand for this pipeline space is expected the Cushing Extension was underpinned by an additional to continue until there is additional capacity available 155,000 b/d of contracts. to transport crude oil to the west coast for export. Two proposals currently exist. Refer to Section 4.5 for more details on oil pipelines to the West Coast. As an indication of high potential demand by offshore markets, a record volume of 143,000 b/d was delivered off the dock in April 2010.
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TransCanada Keystone XL 4.2 Oil Pipelines to the U.S. On May 4, 2012, TransCanada filed a new Presidential Midwest Permit application for Keystone XL. This application will be supplemented later in 2012 with a revised routing in The U.S. Midwest is the largest market for western Nebraska once the Nebraska alternative route selection Canadian crude oil. The major market hubs in the U.S. project is completed. If approved, TransCanada is planning Midwest where crude oil can be stored and transported to for construction to start in the first quarter of 2013 with market are found at Wood River and Patoka in Illinois and a targeted in-service date of late 2014 or early 2015. at Cushing, Oklahoma. Table 4.2 summarizes the pipelines Keystone XL would originate at Hardisty, Alberta and end delivering Canadian-sourced crude oil to the Midwest. at Steele City, Nebraska. If the project is approved, its capacity of 830,000 b/d would contribute to the available Minnesota Pipeline System pipeline capacity exiting western Canada. The Minnesota Pipeline system is connected to the TransCanada concluded a successful open season in Enbridge system at Clearbrook, Minnesota, which enables October 2011 that secured contracts totaling 65,000 b/d it to deliver crude oil from Canada to the Northern Tier of capacity for its Bakken Marketlink project from Baker, refinery located in St. Paul Park and the Flint Hills refinery Montana, to Cushing. The project will enable receipts of in Rosemont. This is the primary route for Canadian crude up to 100,000 b/d of crude oil from the Williston Basin, oil destined for the Minnesota refineries. The system has a primarily from the Bakken play, using capacity on the capacity of 465,000 b/d and can be further expanded by northern leg of Keystone XL. More than 500,000 b/d of 185,000 b/d. capacity on Keystone XL has been contracted for an average term of 18 years. Koch Wood River Pipeline The Minnesota refineries are connected to western Canadian crude oil supplies via connections to the Enbridge system as well as via deliveries from the Express system to Wood River where it then transits on the Koch Wood River System.
Table 4.2 Summary of Crude Oil Pipelines to the U.S. Midwest
Pipeline Originating Point Destination Status Capacity (thousand b/d) Minnesota Pipeline Clearbrook, MN Minnesota refineries Operating 465 Enbridge Mainline Superior, WI various delivery Operating 1,551 points via L5, L6, L14/64, Spearhead North Spearhead North Expansion Flanagan, IL Chicago, IL, Proposed - 2014 +100 Enbridge Spearhead South Flanagan, IL Cushing, OK Operating 193 Enbridge Flanagan South Flanagan, IL Cushing, OK Proposed - 2014 +585 Enbridge Mustang Lockport, IL Patoka, IL Operating 100 Kinder Morgan Express-Platte Guernsey, WY Wood River, IL Operating 145 Trans Canada Keystone Hardisty, AB Patoka, IL Operating 591* to Patoka or Wood River Trans Canada Keystone to Cushing Steele City, NE Cushing, OK Operating 591* * Total capacity originating on the Keystone system to Patoka is up to 591,000 b/d less any volumes moved to the Cushing extension. Like- wise, capacity for volumes delivered on Keystone to Cushing is up to 591,000 b/d less any volumes delivered to Patoka
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Table 4.3 Summary of Crude Oil Pipelines to the U.S. Gulf Coast
Pipeline Originating Point Destination Status Capacity (thousand b/d) ExxonMobil Pegasus Patoka, IL Nederland, TX Operating 96 Seaway Reversal Phase 1 Cushing, OK Freeport, TX Operating - May 2012 150 Seaway Reversal Phase 2 Proposed - Early 2013 +250 Seaway Twin Line Proposed - Mid 2014 +450; expandable TransCanada Gulf Coast Cushing, OK Nederland, TX Proposed - Mid 2013 550; expandable
Spearhead Pipeline ExxonMobil Pegasus Pipeline
The Spearhead Pipeline receives crude oil from the Before the reversed Seaway Pipeline came online on Enbridge Mainline and originates at Flanagan, Illinois. May 19, 2012, the ExxonMobil Pegasus Pipeline was From there, crude oil can be transported to Griffith, the only pipeline that could deliver Canadian crude oil Indiana via Spearhead North or to Cushing, Oklahoma to the U.S. Gulf Coast. Pegasus is a 20-inch diameter on Spearhead South. Spearhead North currently has a pipeline with a capacity of 96,000 b/d that receives crude capacity of 135,000 b/d, which Enbridge plans to expand oil at Patoka, Illinois and delivers it to Nederland, Texas. to 235,000 b/d by 2014. The Spearhead South system Western Canadian crude oil, originating from Hardisty, has a capacity 193,000 b/d and will be expanded once its Alberta transits to Pegasus from one of the following three proposed twin pipeline, Flanagan South is built and begins originating routes operations. 1) The Enbridge system followed by a connection on the Enbridge’s Toledo Pipeline Expansion Mustang Pipeline, which has a capacity of 100,000 b/d;
The Enbridge Toledo Pipeline connects to the Enbridge 2) The Express/Platte system to Wood river, Illinois mainline at Stockbridge, Michigan and serves refineries at followed by a connection on the WOODPAT Pipeline, Toledo, Ohio and Detroit, Michigan. It is a 16-inch diameter which has a capacity of 250,000 b/d; or pipeline with 100,000 b/d capacity. Enbridge is proposing 3) The Keystone Pipeline, which has a current capacity of to increase the capacity along this route by building a new 591,000 b/d. 20-inch diameter pipeline that would have a capacity of 80,000 b/d. The new pipeline could be operating in early Enbridge Flanagan South Pipeline 2013. The Flanagan South Pipeline project is a 36-inch diameter pipeline that will be built parallel to the existing Enbridge 4.3 Oil Pipelines to the U.S. Gulf Spearhead South Pipeline. The pipeline will originate at Coast Flanagan, Illinois and terminate at Cushing, Oklahoma and will have an initial capacity of 585,000 b/d. The pipeline The Gulf Coast is home to the largest refinery market in could be expanded to 800,000 b/d through the addition of the world with refineries in the region being among the pump capacity. most complex in the world, enabling them to process a wide range of both light and heavy crude oil types. They are currently supplied by both U.S. domestic crude oil and foreign imports. A number of pipeline project proposals aim to serve this major market. Canadian crude, however, will be in competition with growing volumes of U.S. domestic supplies from the Mid-continent for space on these pipeline projects. Incidentally, there are several projects underway that propose to move U.S. production from new tight oil plays to the Gulf Coast and avoid the Cushing hub.
25 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Enbridge/Enterprise Seaway Pipeline The Houston Lateral Project is an additional project under development that is intended to extend the market reach of The Seaway Pipeline is jointly owned by Enbridge Inc. and Keystone to refineries in Houston, Texas. The construction Enterprise Products Partners L.P. In 2011, Enbridge of this project is planned to begin in the first quarter of purchased a 50 per cent interest from ConocoPhillips. The 2013 with the intent that the project would be operating pipeline was reversed in May 2012 and now moves crude by the first quarter of 2014. A number of options are also oil from Cushing, Oklahoma to the U.S. Gulf Coast. being explored to connect to refineries in Louisiana.
The first phase of the reversed 30-inch diameter Seaway Once in-service, the Gulf Coast Pipeline and Houston Pipeline provides a capacity of 150,000 b/d. Following the Lateral projects will become integrated with the Keystone completion of pump station additions and other Pipeline System. Crude oil production from western modifications, which are expected to be completed in the Canada will enter the system through expanded facilities first quarter of 2013, the capacity will increase to originating at Hardisty, Alberta to Steele City, Nebraska. 400,000 b/d. In addition, Enbridge and Enterprise have The crude will subsequently be transported on to Cushing, held successful open seasons which resulted in five to Oklahoma. 20 year contracts underpinning a new 30-inch diameter pipeline along the existing route of the Seaway pipeline. The initial capacity on this new Seaway Twinned pipeline 4.4 Projects Dedicated to Divert would be 450,000 b/d, which could then be further expanded with the addition of incremental pump stations in U.S. Crude Oil from the the future. By mid-2014, these expansions would more Cushing Bottleneck than double the capacity of the Seaway system to 850,000 b/d from Cushing to the Gulf Coast. A number of projects are underway that propose to divert U.S. production of crude oil to the Gulf Coast and bypass Following successful open seasons, Enbridge secured 10, the Cushing hub. 15 and 20 year commitments. Western Canadian crude oil supplies could utilize this pipeline to connect to the reversed Seaway Pipeline at Cushing, Oklahoma to reach Shell’s Houma-to-Houston (Ho-Ho) markets in the U.S. Gulf Coast. The target in-service date for this project is mid 2014. Shell Pipeline held a successful 45-day open season for its Ho-Ho Reversal project that ended April 20, 2012. The project entails reversing the existing Ho-Ho service TransCanada Gulf Coast Project and in order to connect the Houston and Port Arthur markets Houston Lateral in Texas with the Louisiana markets. This project could enable distribution of 300,000 b/d of crude oil across the In an effort to address the urgent need for pipeline region. Shell is proceeding with next steps and subject capacity to the U.S. Gulf Coast and in light of the U.S. to regulatory approval, the Ho-Ho Reversal could begin Department of State’s denial of the TransCanada Keystone service in early 2013. Pipeline, L.P. (TransCanada) Presidential Permit application for Keystone XL on January 18, 2012, TransCanada is developing the Gulf Coast segment of the project separately so that it may be in-service sooner. The 36-inch diameter, Gulf Coast Pipeline Project would originate at Cushing, Oklahoma and extend to Nederland, Texas. The Gulf Coast Pipeline project is anticipated to be in-service by mid to late 2013 with an initial capacity of 550,000 b/d that could ultimately ramp up to 830,000 b/d after Keystone XL begins operations.
Crude Oil Forecast, Markets & Pipelines 26 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Magellan Midstream’s Crane-to-Houston Kinder Morgan Trans Mountain Expansion
Pipeline The Trans Mountain Expansion project could increase capacity of the existing Trans Mountain system by Magellan is proposing to reverse and convert a portion 450,000 b/d, bringing the total capacity of the system from of its 18-inch Houston-to-El Paso pipeline (the former 300,000 to 750,000 b/d, at a projected cost of $4.1 billion. Longhorn pipeline) to crude oil service. Specifically, the Through an open season process that ended in April project entails reversing the segment from Crane, Texas to 2012, shippers have signed 20-year term commitments Houston and converting it from refined petroleum products totaling 510,000 b/d of capacity on the entire system. The service to crude oil service. The objective is to transport expansion will twin the existing pipeline, where possible and crude oil produced in Texas producing regions (Permian also involves expansion of the Westridge Marine Terminal. Basin) to refineries in the Houston area. Subject to Preceding a facilities application, Kinder Morgan intends to receiving the necessary regulatory approvals, the reversed file a commercial tolling application in 2012 to review the 18-inch diameter pipeline would begin transporting crude company’s proposed tolling structure once the expansion oil at partial capacity by early 2013, ramping to its full is operational. Kinder Morgan’s facilities application with 225,000 b/d capacity by mid-2013. the National Energy Board is anticipated in 2014, and if approved, the proposed expansion is expected to be This project would provide a direct connection to the U.S. operational by 2017. Gulf Coast and avoid the Cushing hub, potentially reducing the congestion there. Enbridge Northern Gateway
The Northern Gateway Project includes the construction 4.5 Oil Pipelines to the West of a new 36-inch diameter pipeline that could transport 525,000 b/d of crude oil westward from Bruderheim, Coast Alberta (near Edmonton, Alberta) to a deep water port at Kitimat, British Columbia. The pipeline could be expanded The Kinder Morgan Trans Mountain Pipeline is currently to an ultimate capacity of 850,000 b/d. Enbridge submitted the only pipeline route for western Canadian producers to an application to the National Energy Board at the end of transport crude oil to the west coast. Once there, the crude May 2010. The ongoing hearing on the project is scheduled oil can be loaded off the dock to reach other markets such to conclude in April 2013. Subject to regulatory approval, as California, the U.S. Gulf Coast and Asia. Forecasted startup of the pipeline is targeted for 2017. growth in western Canadian production will quickly surpass the existing transportation capacity. New additional capacity to the west coast is key in order to link western Canadian crude oil production to the world market. Both Kinder Morgan and Enbridge have pipeline projects to increase access to the west coast. Table 4.4 summarizes the existing and proposed pipeline projects that could deliver western Canadian crude oil to the West Coast.
Table 4.4 Summary of Crude Oil Pipelines to the West Coast
Pipeline Originating Point Destination Status Capacity (thousand b/d) Kinder Morgan Trans Mountain Edmonton , AB Burnaby, BC Operating 300 Kinder Morgan Trans Mountain Proposed - 2017 +450 Expansion Enbridge Northern Gateway Bruderheim, AB Kitimat, BC Proposed - 2017 +525
27 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
4.6 Eastern Access TransCanada East Coast Pipeline Project Refineries in Eastern Canada take some of their crude oil TransCanada has introduced the concept of a new pipeline requirements from Newfoundland’s offshore wells, but most system to transport about 625,000 b/d of western Canadian of the refinery feedstock is currently sourced internationally. crude oil across the country to Montréal, Québec and There is significant interest in connecting western supplies potentially further east to Saint John, New Brunswick. The to these markets. project would involve converting about 3,000 km of under- utilized natural gas pipe into oil service; while building Enbridge Line 9 Reversal approximately 375 km of new pipe from Hardisty, Alberta to the Mainline at Burstall, Saskatchewan, and from Cornwall, Enbridge Line 9 is a 30-inch diameter crude oil pipeline with Ontario, to Montréal. Another 220 km of pipe would be a capacity of 240,000 b/d. Since 1999, the pipeline has been required to reach Québec City. Tankers could then take flowing crude oil westward from Montréal, Québec to Sarnia, the crude oil to Europe or Asia. The proposal is only at Ontario, although originally the pipeline transported crude the conceptual stage and has received very limited public oil in a west to east direction when first placed in-service in discussion to date. 1975. In August 2011, Enbridge filed an application with the 4.7 Diluent Pipelines National Energy Board (NEB) for the partial re-reversal of the line between Sarnia, Ontario and Westover, Ontario. Table 4.5 summarizes the diluent pipeline proposals. These The purpose of this reversal is to allow greater volumes of projects address the potential demand by western Canadian western Canadian crude oil to be delivered to the Imperial heavy crude oil producers for additional diluent supply refinery at Nanticoke. The public hearing, conducted by needed to transport growing volumes of bitumen. the NEB to examine the application, was concluded in May 2012 and a decision is pending.
Further, Enbridge has announced a separate and distinct project for which it has secured sufficient commercial commitments to proceed with the reversal of Line 9 all the way to Montréal. An open season will be held from May 17 to June 15, 2012 to provide additional shippers with an opportunity to secure capacity on the pipeline. While subject to regulatory approval, the target in-service date for this project is in early 2014.
Table 4.5 Summary of Diluent Pipelines
Pipeline Originating Point Destination Status Capacity (thousand b/d) Enbridge Southern Lights Flanagan, IL Edmonton, AB Operating 180 Enbridge Northern Gateway Kitimat, BC Edmonton, AB Proposed - 2017 193 Kinder Morgan Cochin Kankakee County, IL Fort Saskatchewan, Open Season - 75 Conversion AB ends May 2012
Crude Oil Forecast, Markets & Pipelines 28 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Enbridge Southern Lights 4.8 An Alternative Mode of Since July 2010, the Southern Lights pipeline, which has Transport: Rail a capacity of 180,000 b/d, has been transporting diluent The rapid rise in U.S. Bakken crude oil production, the from Flanagan, Illinois (near Chicago) to Edmonton, Alberta. potential for further growth in tight oil production, as well In 2011, average throughput on the pipeline was around as the long time lines required for the construction of new 60,000 b/d. Enbridge has announced an open season period pipeline projects has led to an increased opportunity for rail ending June 22, 2012 to solicit interest for 85,000 b/d of firm as an alternative mode for transporting crude oil. In the span contracted capacity on the pipeline. In its notice to FERC, of just one year, rail exports from North Dakota have risen Enbridge added that first rights to the additional capacity from about 50,000 b/d in March 2011 to about 225,000 b/d would be given to existing customers BP and Norway’s in March 2012, according to estimates by the North Dakota Statoil, who have already secured 77,000 b/d of capacity. Pipeline Authority. The pipeline can be expanded to 330,000 b/d with minor looping and to over 400,000 b/d with full looping. Transportation of crude oil production originating from western Canada by rail is also growing but is comparatively Enbridge Northern Gateway Diluent small – around 20,000 b/d in 2011. Rail is, however, starting to provide a larger proportion of the crude oil transportation As part of its Northern Gateway crude oil pipeline project, market than it has held historically. According to Statistics Enbridge is proposing a 193,000 b/d diluent import line that Canada, about 8,823 rail cars (707,647 tonnes) were loaded would extend from Kitimat, British Columbia to Edmonton, in March 2012 transporting fuel oils and crude petroleum Alberta. The ongoing hearing on the project is scheduled to compared to 5,602 rail cars (458,696 tonnes) in March 2011. conclude in April 2013. Subject to regulatory approval, the There is much discussion focused on using rail capacity target in-service date is 2017. to reach the various markets that are not currently well Kinder Morgan Cochin Reversal Project supplied by pipeline capacity.
Kinder Morgan is holding an open season to secure Transporting crude by rail requires capital investment in transportation contracts for its Cochin Reversal Project, new loading facilities that must also have corresponding which proposes to move condensate from Kankakee unloading terminals at the destination centres. Rail car County, Illinois to existing terminal facilities near Fort supply is currently tight and it takes about a year to put new Saskatchewan, Alberta. The project requires modifying and rail cars into service. However, a major advantage to rail expanding the existing Cochin Pipeline to connect to the transport is the relatively quick startup for small additional Explorer Pipeline in Kankakee County, then reversing the volumes since an extensive rail network is already in place. product flow to move condensate northwest to Canada. Figure 4.2 is a map of the CP rail network and Figure 4.3 is Subject to shipper support and regulatory approval, the a map of the CN rail network. A greater number of unloading pipeline would be in-service in July 2014. The existing terminals have been or are being built near destination Cochin pipeline system is a 12-inch diameter multi-product markets. pipeline with the capacity to move 70,000 b/d. The Cochin Reversal project would be capable of delivering 75,000 b/d of light condensate. Figure 4.2 CP Rail Network
EDMONTON LLOYDMINSTER
SASKATOON
CALGARY REGINA VANCOUVER WINNIPEG
KINGSGATE THUNDER BAY
COUTTS SUDBURY MONTREAL DULUTH
MINNEAPOLIS/ ST. PAUL TORONTO RAPID CITY ALBANY DETROIT
CHICAGO NEW YORK PHILADELPHIA
Source: Canadian Pacific Railway KANSAS CITY
29 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Figure 4.3 CN Rail Network
Source: Canadian National Railway
The existing rail network has access to the Pacific, Atlantic and Gulf Coasts, and Eastern Canada. Test trains have been sent to California, Texas and Louisiana. Rail is being used to transport light crude and condensate. The rail industry has also proposed the option of utilizing heated rail cars to transport bitumen that could then be blended to specifications at terminals near the destination refineries.
Enbridge is proposing to enhance its North Dakota crude oil system by upgrading and expanding its current facilities located in Berthold, North Dakota to connect into a rail car loading facility south of its existing Berthold Station.
In mid 2011, G Seven Generations Ltd. unveiled a new strategy to transport crude oil from Fort McMurray, Alberta to the West Coast. Under the Unifying Nationals Railco Initiative, Alberta oil would travel by electric rail and would then be shipped to Asian markets from an existing marine terminal at Valdez, Alaska. Oil sands crude oil would be uploaded from rail cars at Delta Junction in Alaska, and then fed into an existing pipeline that terminates at Valdez.
Crude Oil Forecast, Markets & Pipelines 30 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
Table 4.6 Summary of Existing and Proposed Projects to Transport Production from North Dakota
Pipeline Originating Point Destination Status Capacity (thousand b/d) Rail Alexander, McKenzine Clearbrook, MN Open Season ended +150 County, ND Mar 2012 Tesoro West Coast Rail Bakken oil play Anacortes, WA Proposed (Sep 2012) +30 Future expansion Proposed (for TBD) +30 Enbridge North Dakota Clearbrook, MN Operating 210 Enbridge Bakken Access Berthold, ND Cromer, MB Proposed (for 2013) +145 TransCanada Bakken Marketlink Baker, MT Keystone XL Proposed (for 2015) +100 delivery points KM Pony Express/True Companies Baker, MT Cushing, OK Proposed (for 2014) +100 Belle Fourche Pipeline Oneok Bakken Crude Express PL Bakken oil play Cushing, OK Proposed (for 2015) +200
4.9 Projects to Transport North Dakota Production Production from North Dakota is sharply rising (producing a record 534,000 b/d in December 2011). Tesoro’s Mandan refinery in North Dakota is the closest market for Bakken crude but beyond this demand, producers must look for ways to transport production out of the state.
This production will compete for pipeline capacity out of western Canada. A number of projects have been proposed that would increase transportation out of this region, with the projects in turn seeking to connect downstream on the same facilities that transport Canadian crude oil production out of western Canada. The projects are summarized in Table 4.6. Kinder Morgan Pony Express/True Companies Belle Fourche
Kinder Morgan’s Pony Express subsidiary and Belle Fourche Pipeline will hold an open season for 100,000 b/d of crude service from Baker, Montana, to Ponca City and Cushing, Oklahoma. The Open Season will close on June 20, 2012. Service under a joint tariff will begin in the fourth quarter of 2014. The pipeline is anchored with a 30,000 b/d long-term commitment from a major anchor shipper.
The project will combine True Companies’ Belle Fourche system, which runs from Baker to Guernsey, Wyoming, with Kinder Morgan’s 210,000 b/d Pony Express line, which involves the conversion of a natural gas pipeline to crude oil service from Guernsey to Cushing.
31 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
4.10 Pipeline Summary Projects that increase the downstream capacity of existing pipelines have been proposed that could partially alleviate The dynamics of the North American crude oil market are tight capacity as access to markets is enhanced. However, changing as growing western Canadian and Mid-continent additional capacity exiting western Canada will need to crude oil production emerges while North American crude be built if growing production is to avoid facing chronic oil consumption is anticipated to be fairly flat. Despite the apportionment as a result of limited pipeline capacity to forecast for flat demand for crude oil, the U.S., specifically desired markets. Figure 4.4 shows the existing and proposed the Gulf Coast, remains a large, attractive market for western takeaway capacity exiting the WCSB versus forecasted Canadian producers due to the opportunity to displace crude supply. The forecasted supply volume was developed by oil supplies from international sources. A number of pipeline coupling CAPP’s latest supply forecast of Western Canadian proposals to the Gulf Coast have recently been announced production with U.S. Bakken volumes that could utilize a that will increase access by 2014 through connections to portion of the capacity that exits western Canada. existing infrastructure as well as new projects. In addition to looking for increased penetration to U.S. markets, western Transportation of crude oil by rail is growing since it has the Canadian crude oil producers are also seeking much greater advantage of quick start-up and its network extends to a market diversification through increased connectivity to world number of markets that are currently not connected through markets. This would primarily be achieved through more the pipeline network. However, pipelines will remain the pipeline capacity to the west coast, where crude oil could preferred mode of transportation for crude oil. This analysis be shipped to the burgeoning economies of Asia. There is indicates that additional pipeline capacity exiting western also significant interest in improving connectivity to western Canada will be required by 2014. Canadian supplies for all Canadians. As such, a number of projects to increase pipeline access from western Canada to eastern Canadian markets are being pursued.
Figure 4.4 WCSB Takeaway Capacity vs Supply Forecast thousand barrels per day 8,000
7,000 CAPP 2012 Supply Forecast (W. Canadian supply + U.S. Bakken movements) 6,000
5,000 Proposed ex-WCSB Oil Pipeline Capacity
4,000
3,000
2,000 Existing ex-WCSB Oil Pipeline Capacity + Western Canadian Refinery Demand 1,000
0 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Crude Oil Forecast, Markets & Pipelines 32 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
GLOSSARY
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. It may be gaseous in its reservoir state but is liquid at the conditions under which its volumes is measured or estimated.
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 their source (oil sands).
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.
33 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
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 ERCB 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.
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.
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.
Crude Oil Forecast, Markets & Pipelines 34 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. APPENDIX A ACRONYMS, ABBREVIATIONS, UNITS AND CONVERSION FACTORS
Acronyms
API American Petroleum Institute CAPP Canadian Association of Petroleum Producers EIA Energy Information Administration ERCB (Alberta) Energy Resources Conservation Board FERC Federal Energy Regulatory Commission IEA International Energy Agency NEB National Energy Board PADD Petroleum Administration for Defense District U.S. United States WCSB Western Canada Sedimentary Basin WTI West Texas Intermediate
Canadian Provincial Abbreviations
AB Alberta BC British Columbia MB Manitoba NWT Northwest Territories ON Ontario QC Québec SK Saskatchewan
Units b/d barrels per day
Conversion Factor
1 cubic metre = 6.293 barrels (oil)
35 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
U.S. State Abbreviations NM New Mexico NY New York AL Alabama NC North Carolina AK Alaska ND North Dakota AZ Arizona OH Ohio AR Arkansas OK Oklahoma CA California OR Oregon CO Colorado PA Pennsylvania CT Connecticut SC South Carolina DE Delaware SD South Dakota FL Florida TN Tennessee GA Georgia TX Texas ID Idaho UT Utah IL Illinois VT Vermont IN Indiana VA Virginia IA Iowa VI Virgin Islands KS Kansas WA Washington KY Kentucky WV West Virginia LA Louisiana WI Wisconsin ME Maine WY Wyoming MD Maryland MA Massachusetts MI Michigan MN Minnesota MS Mississippi MO Missouri MT Montana NE Nebraska NV Nevada NH New Hampshire NJ New Jersey
Crude Oil Forecast, Markets & Pipelines 36 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. 1111111111111111111 Forecast 186 188 219 227 250 265 273 277 278235 279 242 277 255 275 250 272 253 269 249 265 248 263743 245 259 844 239 256 914 237 252 1,011 1,133 236 248 1,238 232 1,361 244 1,476 229 1,565 1,690 229857 1,838759 1,975 230 892 2,141 1,007 852 232 2,277 1,162 2,402 1,196 924 233 2,539 1,214 1,033 2,660 234 1,249 1,162 2,795 1,277 1,267 234 2,896 1,342 1,389 2,994 1,442 1,503 236 3,129 1,524 1,592 1,616 1,716 238 1,674 1,865 1,691 2,002 1,808 2,170 1,927 2,307 1,944 2,432 2,018 2,570 2,094 2,691 2,119 2,827 2,170 2,929 3,024 3,155 1,616 1,745 1,931 2,195 2,358 2,481 2,638 2,780 2,934 3,158 3,389 3,619 3,843 3,999 4,240 4,497 4,635 4,846 5,023 5,143 5,326 Actuals 1,2 1,2 CONVENTIONAL 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Newfoundland & Labrador W Canada Light and Medium E Canada Light and Medium Light and Medium Conv. Total 276 574Heavy 267 277 610 Heavy Alberta Conv. 851 210 Heavy Saskatchewan Conv. 268 706 878 239 211 743 917 205 240 786 983 215 206 818 992 211 140 216 831 1,034 1,043 216 140 212 839 1,056 235 139 1,074 217 838 1,063 226 141 236 836 1,047 1,040 215 142 227 831 1,021 215 144 216 824 995 206 143 216 814 966 190 144 207 804 942 172 144 191 793 907 160 144 173 781 874 139 143 161 767 839 125 142 140 748 810 110 141 126 728 780 138 111 712 97 135 694 98 85 133 86 129 125 121 117 114 NWT 151013121211111010998877766666 Manitoba N.W.T. Ontario 32 Conventional HeavyTotal 40 CONVENTIONALTOTAL 1 41PENTANES/CONDENSATE 41 1 OIL SANDS (BITUMEN & 375 41UPGRADED CRUDE OIL) 1,226 382 1,259 Oil Sands Mining 41 1,311 144 394 Oil Sands In situ 1,374 38 OIL SANDS 142TOTAL 1,388 391 1,427 137 37 396 1,434WESTERN CANADA OIL PRODUCTION 1,444 2,556 132 393 36EASTERN CANADA OIL PRODUCTION 2,743 1,457 1,444 3,009 127 391 CANADIAN OIL PRODUCTIONTOTAL 284 1,426 3,290 35 2,840 727 124 389 1,414 273 3,487 3,017 1,391 BITUMEN** 3,634OIL SANDS RAW 772 35 3,220 121 383 1,470 215 1,363 3,797 3,530 Oil Sands Mining 1,615 862 1,331 3,942 119 3,693 381 34 242 1,776 Oil Sands In Situ 1,016 1,306 4,073 3,850 2,027 1,045 116 1,268 4,273 OIL SANDS TOTAL 379 206 4,009 2,178 33 1,061 1,233 4,486 4,159 113 2,299 375 1,093 216 1,194 4,682 4,309 2,454 1,120 33 1,163 4,871 4,500 111 370 2,597 212 1,171 1,131 5,008 4,702 2,736 1,252 5,226 109 32 4,898 367 217 2,942 1,327 5,461 5,078 3,165 107 1,400 5,567 365 236 5,199 31 3,375 1,440 5,741 5,399 104 3,581 365 1,455 227 5,891 5,622 31 3,732 1,564 5,9 93 5,707 102 362 216 3,965 1,676 6,157 5,867 4,215 30 1,680 100 6,002 359 216 4,340 1,742 6,091 4,537 1,817 355 29 207 6,243 99 4,713 1,840 4,834 354 191 1,891 29 97 5,020 351 173 28 95 161 93 140 126 92 111 98 86 Light & Medium Alberta B.C. Saskatchewan 319 350 22 413 20 443 466 20 484 19 493 18 499 499 17 499 16 498 16 494 15 489 484 14 478 13 470 13 460 446 12 432 11 420 11 408 10 1 09988 CAPP Canadian Crude Oil Production Forecast 2012 – 2030 Forecast CAPP Canadian Crude Oil Production thousand barrels per day APPENDIX B.1
37 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. . 3 thousand barrels per day 2012 – 2030 Western Canadian Crude Oil Supply Forecast 660 705 804 926 954 983 1,012 974 976 1,020 1,083 1,128 1,144 1,130 1,135 1,169 1,157 1,118 1,104 1,094 1,079 1,134 1,2961,794 1,310 2,001 1,483 2,115 1,647 2,409 1,775 2,601 1,971 2,758 2,173 2,983 2,304 3,147 2,496 3,280 2,734 3,516 2,932 3,817 3,178 4,060 3,386 4,322 3,661 4,516 3,947 4,796 4,041 5,116 4,276 5,199 4,481 5,394 4,618 5,585 4,830 5,712 5,909 Actuals 1 2 integrated upgrader projects. Production from off-site upgrading projects are included in the production numbers as bitumen. Oil Sands Heavy OIL SANDS AND TOTAL UPGRADERS Light SupplyTotal Heavy SupplyTotal WESTERN CANADA OIL SUPPLY 2,673 2,918 3,139 3,468 1,229 3,705 1,444 1,311 3,890 1,608 1,506 4,125 1,633 1,665 4,295 1,803 1,736 4,420 1,968 1,797 4,653 2,092 1,839 4,946 2,287 1,809 5,177 2,486 1,809 5,424 2,611 1,852 5,606 2,801 1,909 5,871 3,037 1,948 6,179 3,229 1,954 6,244 3,470 1,931 6,418 3,675 1,924 6,585 3,947 1,945 6,695 4,233 1,920 6,870 4,325 1,862 4,556 1,828 4,757 1,802 4,893 1,769 5,102 Blended Supply to Trunk Pipelines and Markets Blended Supply to Trunk CONVENTIONAL Light and MediumTotal Net Conventional Heavy to Market CONVENTIONALTOTAL 309OIL SANDS 312 570Upgraded Light (Synthetic) 2010 323 2011 606 879 320 2012 702 917 2013 321 1,025 739 2014 1,059 317 1,103 2015 782 1,132 316 2016 814 1,142 2017 313 1,148 827 2018 1,140 307 2019 1,137 835 1,129 305 2020 834 1,117 2021 303 1,102 2022 832 1,090 298 2023 1,076 827 1,063 2024 292 1,046 820 2025 289 1,024 2026 810 1,000 287 2027 800 982 2028 287 789 2029 962 283 2030 777 280 763 276 744 274 724 272 708 690 Notes: 1. Includes upgraded conventional. Includes: a) imported condensate b) manufactured diluent from upgraders and c) upgraded heavy volumes coming upgraders. 2. APPENDIX B.2 Notes: 1. CAPP allocates Saskatchewan Area III Medium crude as heavy crude. Also 17% of IV is > 900 kg/m 2. CAPP has revised from the June 2007 report historical light/heavy ratio for Saskatchewan starting in 2005. crude oil and bitumen therefore incorporate yield losses from Raw bitumen numbers are highlighted. The oil sands production (as historically published) a combination of upgraded **
Crude Oil Forecast, Markets & Pipelines 38 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc. APPENDIX C Crude Oil Pipelines and Refineries
ENBRIDGE NW
Upgraders Syncrude (Fort McMurray) ...... 407 Suncor (Fort McMurray)...... 428 RAINBOW Shell (Scotford)...... 155 CNRL Horizon...... 135 OPTI/Nexen Long Lake...... 72 Vancouver to: Prince George Japan - 4,300 miles Husky...... 12 Taiwan - 5,600 miles S.Korea - 4,600 miles China - 5,100 miles Edmonton San Francisco - 800 miles Imperial...... 187 Los Angeles - 1,100 miles Suncor ...... 135 Shell...... 100 Lloydminster Husky...... 28 HUSKY Vancouver Husky Upgrader...... 82 Chevron ...... 55 Regina Co-op Refinery/
Upgrader...... 100 KEYSTONE Moose Jaw Moose Jaw...... 15 Puget Sound BP (Cherry Pt)...... 225 Phillips 66 (Ferndale) 100 Shell (Anacortes)...... 145 WA Tesoro (Anacortes) ...120 US Oil (Tacoma)...... 39
Great Falls Montana Refining..... 10
Billings OR CHS (Laurel)...... 55 MT Phillips 66...... 58 ExxonMobil...... 60 KEYSTONE ID ND MN Mandan San Francisco Wyoming Tesoro ...... 58 St. Paul Chevron ...... 240 Little America (Casper) ...... 25 Flint Hills...... 320 Phillips 66...... 120 Sinclair Oil (Sinclair)...... 80 Northern Tier...... 74 Shell...... 165 Wyoming (Newcastle)...... 14 WY SD Tesoro ...... 166 Frontier (Cheyenne)...... 52 Valero...... 170
CA NV Salt Lake City Kansas Big West ...... 35 NE NCRA (McPherson)...... 85 Chevron ...... 45 Frontier (El Dorado) ...... 135 SHELL Holly...... 31 Coffeyville Res(Coffeyville) 115 IA
CHEVRON Tesoro ...... 58 CO
Denver/Commerce City KOCH (Wood River) UT Suncor ...... 98
Oklahoma
PACIFIC Phillips 66 (Ponca City) ...... 187 Bakersfield Holly (Tulsa) ...... 125 Kern Oil...... 26 Coffeyville Res. (Wynnewood)...... 70 KS EXXONMOBIL San Joaquin...... 24 Valero (Ardmore) ...... 90 SPEARHEAD SOUTH
Borger/McKee Los Angeles AZ WRB ...... 146 Alon USA ...... 94 Valero...... 170 OK BP ...... 265 Chevron ...... 285 M ExxonMobil...... 155 NM CENTURION Phillips 66...... 139 EXXON Tesoro ...... 97 Valero ...... 135 AR Artesia Slaughter Big Spring
New Mexico/W. Texas EXXONMOBIL EXXON Western Refining (El Paso)...... 128 EXXONMOBIL Holly (Artesia) ...... 100 Tyler M Alon (Big Spring)...... 70 Delek...... 60 LA
KOCH TX Lake Cha Port Arthur/ Houston/Texas City Beaumont PRSI (Pasadena) ...... 117 Three Rivers BP ...... 475 Valero...... 100 Shell (Deer Park)...... 340 Port Arthur/ Corpus Christi ExxonMobil...... 584 ExxonMobil. CITGO...... 165 Sweeny Houston Refining ...... 268 Motiva...... Flint...... 300 Phillips 66...... 247 Marathon...... 80 Valero...... Valero...... 325 Valero (2)...... 160+245 Total......
39 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
2011 Canadian Crude Oil Production 000 m3/d 000 b/d British Columbia 6 37 Alberta 354 2,225 Saskatchewan 69 431 For Information Contact: (403) 267-1141 / www.capp.ca Manitoba 6 40 Northwest Territories 2 10
Newfoundland & Labrador Western Canada 436 2,741 North Atlantic...... 115 Eastern Canada 43 273 Total Canada 479 3,017
Come by Chance
Saint John Irving...... 300 Pipeline Tolls Light Oil (US$ per barrel) Montréal/Québec Edmonton to Suncor ...... 137 Saint John Burnaby (Trans Mountain) 2.70 Ultramar...... 265 Superior Anacortes (Trans Mountain/Puget) 2.90 Calumet...... 45 Sarnia Imperial...... 121 Sarnia (Enbridge) 3.95 Montréal ME Nova...... 80 MONTREAL Halifax Chicago (Enbridge) 3.55 Shell...... 75 RREAREALAL Imperial...... 82 Wood River (Enbridge/Mustang/Capwood) 4.60 Suncor ...... 85 Nanticoke VT USGC (Enbridge/Mustang/ExxonMobil) 6.15 Imperial...... 112 USGC (Enbridge/Spearhead/Seaway) 7.05* WI NH Hardisty to Chicago Guernsey (Express/Platte ) 1.55* BP ...... 413 ExxonMobil...... 250 NY MA Wood River (Express/Platte) 1.90* PDV ...... 167 Wood River (Keystone) 4.70** CT RI MI USGC (Express/Platte/MAP/ExxonMobil) 3.75 USEC to Sarnia (Portland/Montréal/Enbridge) 4.40 A PA Pennsylvania IL Detroit Phillips 66 (Trainer) *idled*...... 185 St. James to Wood River (Capline/Capwood) 1.05 Marathon...... 106 Warren Sunoco (Marcus Hook) *idled* 175 United ...... 70 Sunoco (Philadelphia)...... 330 Flanagan Philadelphia NJ Pipeline Tolls -Heavy Oil (US$ per barrel) ID Hardisty to: MD New Jersey DE Phillips 66 (Bayway).....238 Chicago (Enbridge) 4.00 OH WV PBF (Paulsboro) ...... 180 Cushing (Enbridge/Spearhead) 5.00 VA Delaware PBF (Delaware City) .....190 Cushing (Keystone) 6.15** Ohio Cushing (Keystone) 6.55* BP-Husky (Toledo)...... 160 Wood River (Enbridge/Mustang/Capwood) 5.45 PBF (Toledo) ...... 170 WV Wood River Wood River (Keystone) 5.35** WRB ...... 306 Marathon (Canton) ...... 78 MO Husky (Lima)...... 160 Robinson Wood River (Express/Platte) 2.30* Marathon...... 206 Marathon (Catlettsburg)...... 233 USGC (Enbridge/Spearhead/Seaway) 8.00* TN Mt Vernon OBIL Countrymark...... 27 M Notes 1) Assumed exchange rate = 1US$ / 1C$ NC 2) Tolls rounded to nearest 5 cents Memphis 3) Tolls in effect July 1, 2012 Valero...... 195 R El Dorado * 10-year committed toll Lion...... 80 **20-year committed toll MS SC AL GA Mississippi Chevron(Pascagoula) 330 M OBIL Alabama Hunt (Tuscaloosa) ...... 72 Shell (Saraland) ...... 85 Mississippi River ExxonMobil (Baton Rouge)..... 503 arles Chalmette...... 192 Marathon (Garyville) ...... 490 FL Motiva (Convent)...... 235 Motiva (Norco)...... 220 Valero (Meraux)...... 135 /Beaumont Lake Charles Phillips 66 (Belle Chasse) ...... 247 ...... 365 CITGO...... 425 Alon (Krotz Springs)...... 83 Major Existing Crude Oil Pipelines carrying ...... 325 Phillips 66...... 239 Shell (St. Rose) *idled* ...... 55 Canadian crude oil ...... 310 Valero...... 250 Placid (Port Allen)...... 56 ...... 174 Selected Other Crude Oil Pipelines
Crude Oil Forecast, Markets & Pipelines 40 Appendix 10-1 Edmonton to Hardisty Pipeline Project Enbridge Pipelines Inc.
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 more than 90 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 of about $100 billion-a-year. CAPP’s mission is to enhance the economic sustainability of the Canadian upstream petroleum industry in a safe and environmentally and socially responsible manner, through constructive engagement and communication with governments, the public and stakeholders in the communities in which we operate.
Get in on the oil sands discussion Mobile Application Upstream Dialogue: The Facts on Oil Sands Available for free download to Apple and BlackBerry devices by searching “Oil Sands” in the app stores.
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Websites www.oilsandstoday.ca www.capp.ca/upstreamdialogue
Calgary Office: Ottawa Office: St. John’s Office: 2100, 350 - 7 Avenue SW 1000, 275 Slater Street 403, 235 Water Street Calgary, Alberta, Canada Ottawa, Ontario, Canada St. John’s, Newfoundland and Labrador T2P 3N9 K1P 5H9 Canada A1C 1B6 Phone: 403-267-1100 Phone: 613-288-2126 Phone: 709-724-4200 Fax: 403-261-4622 Fax: 613-236-4280 Fax: 709-724-4225
www.capp.ca • [email protected] • June 2012 • 2012-0004
41 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS MARKET PROSPECTS
FOR THE
EDMONTON TO HARDISTY
PIPELINE PROJECT
FOR
November 2012
15455 Dallas Parkway Two Allen Center 48/54 Moorgate Level 58 Republic Plaza Suite 350 Suite 1600, 1200 Smith Street London EC2R 6EJ 9 Raffles Place Addison, TX 75001-4690 Houston, TX 77002 United Kingdom Singapore 048619 Phone: 214-954-4455 Phone: 713-890-1182 Phone: 44-0-207-374-8994 Phone: 65-6832-1341 Fax: 214-954-1521 Fax: 214-954-1521 Fax: 44-0-207- 374-8995 Fax: 65-6832-1491
Page i
TABLE OF CONTENTS
Page
INTRODUCTION ...... 1
EXECUTIVE SUMMARY ...... 2
HEAVY CRUDE OIL MARKET OVERVIEW ...... 7 ONTARIO/QUEBEC ...... 8 ROCKIES ...... 9 UPPER MIDWEST ...... 9 LOWER MIDWEST ...... 10 MIDCONTINENT ...... 11 GULF COAST ...... 12
HARDISTY THROUGHPUT ANALYSIS ...... 14 CRUDE OIL SUPPLY ...... 15 CRUDE OIL TRANSPORTATION INFRASTRUCTURE AND TOLLS ...... 16 REFINERY CAPACITY ...... 21 CRUDE OIL REFINING VALUES ...... 21 CRUDE OIL AND PRODUCT PRICE FORECAST ...... 23 ANALYTICAL RESULTS ...... 24
APPENDIX TABLE I – Disposition of Heavy Crude Oil Transiting the Hardisty Hub
APPENDIX TABLE II – Hardistry Heavy Crude Oil Supply-Demand Balance
Page ii INTRODUCTION
This report evaluates the expected demand for heavy crude oil at Hardisty on all outbound crude oil pipelines, and compares that demand with the available inbound heavy crude oil pipeline supply capacity and the net Hardisty-area conventional heavy crude oil supply, to assess the need for additional inbound heavy crude oil pipeline capacity.
The Edmonton-to-Hardisty Pipeline Project (the Project) will have an initial capacity of 90,622 m3/d (570 kb/d), with a planned in-service date in the first quarter of 2015. The analysis described in this report assumes that the Project is commissioned as of January 1, 2015, and assesses the period 2015 through 2030.
This report was authored by Neil K. Earnest, President of Muse, Stancil & Co. (Muse). Other employees of Muse also assisted with the preparation of this report.
Page 1
EXECUTIVE SUMMARY
The Muse Crude Market Optimization Model has been used to develop the estimated demand for heavy crude oil at Hardisty. This model has been developed by Muse for use in a wide variety of commercial applications, including detailed forecasts of Western Canadian crude oil prices, assessment of likely Western Canadian crude consumers, and pipeline utilization studies. The Crude Market Optimization Model is a distribution model which uses advanced optimization techniques to predict the flow of crude oil to various markets. Consequently, it is well-suited for assessing the expected market demand for heavy crude oil at various points along the crude oil distribution system beween Western Canada and the refineries that process heavy crude oil.
The key assumptions embedded in the Muse Crude Market Optimization Model, include:
Enbridge Mainline – Existing capabilities plus all expansion projects sanctioned by Enbridge and disclosed in its most recent Investor Presentation. In addition to several capacity increases along the Mainline itself, the key Enbridge expansion projects are Flanagan South and the re- reversal of Enbridge Line 9B.
Northern Gateway – The Northern Gateway Project proceeds with a total capacity of 83,500 m3/d (525 kb/d). The regulatory application for Northern Gateway is targeting an August 1, 2018, commissioning date. For analytical modeling purposes, a commissioning date of January 1, 2019, has been used for Northern Gateway.
Keystone System – The Keystone XL Project is commissioned prior to January 1, 2015, at its NEB approved capacity of 111,300 m3/d (700 kb/d).
Page 2 Western Canadian Crude Oil Supply Outlook – The June 2012 CAPP crude oil supply forecast has been used, which is the most recent forecast released by CAPP.
The heavy crude oil supply available at Hardisty is the total of the inbound Oil Sands heavy crude oil pipeline capacities and the net supply of conventional heavy crude oil produced in the Hardisty area. The estimated net supply of conventional heavy crude oil in the Hardisty area equals the CAPP forecast for conventional heavy crude oil, less local refinery demand (the Gibson Moose Jaw and COOP Regina refineries), and less the volume of conventional heavy crude oil transported into the Rockies via the Milk River and Express Pipelines. The inbound Oil Sands heavy crude oil pipelines consist of the following:
Enbridge Athabasca System – In 2015, the capacity is 93,600 m3/d (589 kb/d), expanded by 71,500 m3/d (450 kb/d) in 2016 (the Athabasca Twinning Project currently in the regulatory approval phase at the ERCB). Light crude oil shipments on the Athabasca System will be between 11,400 and 27,800 m3/d (72 and 175 kb/d), leaving a net heavy crude oil inbound capacity of 137,400 to 153,700 m3/d (864 to 967 kb/d) post-2016. For the analysis, the Enbridge Athabasca System is assumed to operate at 100 percent of capacity.
Enbridge Line 4 – Heavy crude oil capacity is 126,600 m3/d (796 kb/d) and transports only Athabasca, Peace River or Cold Lake heavy crude oil blends (no conventional heavy crude oil).
IPF Cold Lake Pipeline – The IPF Cold Lake system capacity is taken to be 50,100 m3/d (315 kb/d) and transports only Athabasca or Cold Lake heavy crude oil blends.
Page 3 CNRL Echo Pipeline – The Echo Pipeline capacity is taken to be 11,900 m3/d (75 kb/d) and transports only Athabasca or Cold Lake heavy crude oil blends.
Figure 1 provides an overview of the Hardisty heavy crude oil supply-demand balance for the period 2015 through 2030.1 Two estimates of the year-by-year balance are
Figure 1 Hardisty Heavy Crude Oil Supply-Demand Balance 800
600
400
200
-
(200)
Capacity, kb/d (400)
(600)
(800)
Surplus (Deficit) Heavy Inbound Crude Oil Pipeline (1,000) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Lower Range Upper Range 20 Percent Operating Margin
provided, reflecting an estimated range of inbound heavy crude oil capacity on the Enbridge Athabasca System. The lower range of the surplus or deficit inbound pipeline capacity uses an Enbridge Athabasca System heavy crude oil capacity of 137,400 m3/d (864 kb/d), whereas the upper range uses an Athabasca System heavy crude oil capacity of 153,700 m3/d (967 kb/d). As a practical matter, the Hardisty crude oil hub cannot operate efficiently with all inbound pipelines operating at 100 percent of capacity.
1 The spike in surplus capacity in 2016 is attributable to the commissioning of the Enbridge Athabasca Twinning project, and the spike in 2019 is attributable to the start up of the Northern Gateway project, which redirects some heavy crude oil to the Pacific Basin markets that would otherwise have transited the Hardisty Hub.
Page 4 Accordingly, the excess inbound capacity required to provide a 20 percent operating margin is compared to the estimated surplus capacity (the lower and upper range) in Figure 1 so as to better represent the volume of inbound pipeline capacity that is truly surplus. The required operating margin is calculated by multiplying the total Hardisty heavy crude oil demand by 20 percent.
Figure 1 demonstrates that for the great preponderance of the life of the Project there is a critical need for additional inbound heavy crude oil pipeline capacity. In the early years of the forecast period, the surplus inbound pipeline capacity generally is less than that required to maintain a reasonable operating margin such that the Hardisty Hub operates efficiently. By about 2021, the inbound pipeline capacity is completely full and, rather than transiting the Hardisty Hub, heavy crude oil will have to be transported by rail (either to Hardisty itself or to the ultimate end-market).2 The resultant need for additional inbound heavy crude oil pipeline capacity is summarized through 2025 in Table 1. As shown, in all years but for 2016, there is a need for additional inbound
Table 1
HARDISTY HEAVY CRUDE OIL SUPPLY-DEMAND BALANCE
(Thousands of Barrels per Calendar Day, Unless Noted)
Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Surplus (Deficit) with Operating Margin Lower Range (200) 15 (227) (383) (151) (437) (528) (725) (797) (865) (1,050) Upper Range (97) 118 (124) (280) (48) (334) (425) (622) (694) (762) (947) heavy crude oil pipeline capacity to Hardisty. It should also be pointed out that an expansion of the Keystone XL pipeline to its ultimate capacity of 132,000 m3/d (830 kb/d) has not been assumed at any point during the forecast period.
It is Muse’s professional judgment that the key assumptions used to generate the analytical results presented in this report are well founded. The specific scenario
2 By about 2023, the Project will have to be expanded or other inbound pipelines constructed to maintain the desired amount of operating margin.
Page 5 considered for the Project does not represent a Best Case or a Worst Case scenario, but a scenario that is both reasonable and balanced.
Page 6 HEAVY CRUDE OIL MARKET OVERVIEW
From the Hardisty hub, six major crude oil markets are accessible: Ontario/Quebec; Rockies; Upper Midwest; Lower Midwest; Midcontinent, and; the Gulf Coast. Eastern Canada and the Upper Midwest are primarily accessible via the Enbridge Mainline. The Rockies is accessed from Hardisty with heavy crude oil via either the Kinder Morgan Express pipeline or via the Bow River/Milk River pipeline route. The rest of the markets can be accessed via both the Enbridge Mainline and the Keystone System from Hardisty. Figure 2 provides the estimated distribution
Figure 2
Disposition of Heavy Crude Transiting Hardisty 3,500
3,000
2,500
2,000
1,500
1,000 ThousandsofBarrels per Day 500
0 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Ontario/Quebec Rockies Upper Midwest Lower Midwest Mid-Continent U.S. Gulf Coast
among these markets of the heavy crude oil that transits the Hardisty Hub over the forecast period. Post-2015, Canadian heavy crude oil consumption is forecast to be comparatively static in all markets accessible via Hardisty but for the Gulf Coast. The drop in Gulf Coast consumption of Canadian heavy crude in 2019 is attributable to the commissioning of the Northern Gateway Project.
Page 7 ONTARIO/QUEBEC
Table 2 provides the current capacity of the refineries located in the Ontario/Quebec market. The United Warren refinery, located in western Pennsylvania, is also included in this market region because it receives its Canadian crude oil supplies via Ontario,
Table 2 Ontario/Quebec
Refinery m 3 /d kb/d
Nova Corruna 4,800 30.0 Imperial Nanticoke 17,800 112.0 Imperial Sarnia 19,200 120.8 Shell Sarnia 11,400 71.4 Suncor Sarnia 13,500 85.0 Suncor Montreal 20,600 129.8 Valero Levis 34,200 215.0 United Warren 10,300 65.0 Total 131,800 829.0
and has substantially the same crude oil processing economics as the Ontario refineries. Over the forecast period, the total estimated heavy crude oil demand is in the range of 20,700 to 23,800 m3/d (130 to 150 kb/d). It should be noted that the heavy crude oil category includes sour synthetics, which are consumed in the Sarnia refining center. In addition to these volumes, there is also the potential for additional Canadian heavy crude oil demand in the Atlantic Canada refineries and the U.S. East Coast asphalt refineries. Such deliveries would be made on the re-reversed Enbridge Line 9B to Montreal, and then via small tankers to the indicated refineries. The Crude Market Optimization Model indicates that about 4,800 m3/d (30 kb/d) of Canadian heavy crude oil is being delivered into these refineries towards the end of the forecast period.
Page 8 ROCKIES
Table 3 provides the calendar day refinery capacities for the Rockies. Projected Canadian heavy crude oil consumption in this market is in the range of 23,800 to 31,800 m3/d (150 to 200 kb/d). Of this volume, roughly 65 percent of the total is estimated to be various grades of Canadian conventional heavy crude oil. Such crude oil grades would not consume inbound heavy crude oil pipeline capacity to the Hardisty Hub.
Table 3
Rockies
Refinery m 3 /d kb/d
Phillips 66, XOM Billings, CENEX Laurel 28,200 177.6 Frontier Cheyenne 7,500 47.0 Montana Refining 1,600 10.0 Salt Lake City 24,000 150.9 Suncor Denver 16,200 102.0 Sinclair Rawlins, Chevron SLC 18,900 119.0 Total 96,400 606.5
UPPER MIDWEST
The Upper Midwest is a major demand center for Canadian heavy crude oil today, and is projected to remain so for the foreseeable future. Table 4 provides the calendar day refinery capacities used in the Crude Market Optimization Model for this market. The indicated refinery capacities include the ongoing expansion projects underway at the BP
Page 9 Table 4 Upper Midwest
Refinery m 3 /d kb/d
BP Whiting 59,600 375.0 BP-Husky Toledo 20,000 125.7 Calumet Superior 5,500 34.3 CITGO Lemont 26,600 167.0 ExxonMobil Joliet 37,900 238.6 Flint Hills Pine Bend 47,800 300.5 Marathon Detroit 16,900 106.0 Northern Tier Energy St. Paul 11,800 74.0 PBF Toledo 25,400 160.0 Tesoro Mandan 10,800 68.0 Total 262,300 1,649.1
Whiting, Marathon Detroit, and Tesoro Mandan refineries. It should be noted that both the BP Whiting and the Marathon Detroit projects are designed to substantially increase these refineries’ capacity to process Canadian heavy sour crude oil. Projected total Canadian heavy crude oil consumption in this market is in the range of 135,100 to 151,000 m3/d (850 to 950 kb/d).
LOWER MIDWEST
Total Canadian heavy sour crude oil runs in this market are forecast to be in the range of 35,000 to 39,700 m3/d (220 to 250 kb/d). Total refinery capacity for this region is shown in Table 5. Muse has not assumed that a refinery upgrading project to increase heavy sour crude oil capacity has proceeded at the Husky Lima refinery, although Husky in the past has indicated that it is considering such a project.
Page 10 Table 5
Lower Midwest
Refinery m 3 /d kb/d
CountryMark Mt. Vernon 4,500 28.6 Husky Lima 23,800 150.0 Marathon Canton 12,400 78.0 Marathon Catlettsburg 33,700 212.0 Marathon Robinson 32,800 206.0 Valero Memphis 28,600 180.0 WBR Wood River 48,600 306.0 Total 184,400 1,160.6
MIDCONTINENT
Table 6 provides the calendar day capacity for the refineries in the Midcontinent market.
Table 6
Midcontinent
Refinery m 3 /d kb/d
CVR Energy Coffeyville 18,400 115.7 CVR Energy Wynnewood 11,100 70.0 Holly Frontier El Dorado 20,700 130.0 Holly Frontier Artesia 16,700 105.0 Holly Frontier Tulsa 13,500 85.0 NCRA McPherson 13,600 85.5
Phillips 66 Ponca City 31,500 198.4 Valero Ardmore 13,900 87.4 Valero McKee 27,200 171.0 WRB Borger 23,200 146.0 Total 189,800 1,194.0
Muse’s definition of the Midcontinent market includes the Valero McKee and the WRB Borger refineries in the Texas Panhandle as well as the HollyFrontier Artesia refinery in southeastern New Mexico, as these three refineries can receive crude oil via the
Page 11 Cushing, Oklahoma, hub. Total Canadian heavy crude oil demand in this market area is approximately 15,900 m3/d (100 kb/d).
GULF COAST
Total Gulf Coast refining capacity is approximately 1,271,900 m3/d (8,000 kb/d), whereas Table 7 shows just the Gulf Coast refineries included in the Crude Market Optimization Model that have a significant capability to process heavy sour crude oil
Table 7
Gulf Coast
Refinery m 3 /d kb/d
Houston BP Texas City 64,600 406.6 Deer Park Refining Deer Park 52,000 327.0 ExxonMobil Baytown 89,100 560.6 Houston Refining Houston 44,600 280.4 Phillips 66 Sweeny 39,300 247.0 Valero Texas City 35,800 225.0 Subtotal 325,400 2,046.6 Beaumont/Port Arthur/Lake Charles ExxonMobil Beaumont 54,800 344.5 Motiva Port Arthur 95,400 600.0 Phillips 66 Westlake 38,100 239.4 Total Port Arthur 27,600 173.5
Valero Port Arthur 46,400 292.0 Subtotal 262,300 1,649.4 Louisiana/Mississippi
Chalmette Refining 30,600 192.5 Chevron Pascagoula 52,500 330.0 ExxonMobil Baton Rouge 79,800 502.0 Hunt Tuscalusa 5,700 36.0 Marathon Garyville 73,800 464.0 Valero St. Charles 32,600 205.0 Subtotal 244,400 1,537.0
Grand Total 862,700 5,425.5
Page 12 and are regarded by Muse as being likely to receive Canadian heavy crude oil. This latter requirement has eliminated the refineries in the Corpus Christi, Texas, area from consideration. Table 7 is further subdivided into the Houston, Beaumont/Port Arthur/Lake Charles, and Louisiana/Mississippi submarkets, reflecting the somewhat different logistical costs and constraints associated with reaching these areas from Canada.
The Gulf Coast, as well as the Pacific Basin, represents the incremental market for Canadian heavy crude oil. Accordingly, the volume of Canadian heavy crude oil that transits Hardisty can be expected to increase over time as Western Canadian crude oil production climbs. In 2015, the projected volume of Canadian heavy crude oil reaching the Gulf Coast is approximately 51,700 m3/d (325 kb/d), whereas by the end of the forecast period the volume is over 222,600 m3/d (1,400 kb/d).3
3 By the end of the forecast period, additional volumes of Canadian heavy crude oil are also reaching the Gulf Coast via rail, as the pipeline network, as modeled in the Crude Market Optimization Model, has essentially reached its ultimate capacity.
Page 13 HARDISTY THROUGHPUT ANALYSIS
The Muse Crude Market Optimization Model has been used to estimate the volume of heavy crude oil that will transit the Hardisty hub. This model has been developed by Muse for use in a wide variety of commercial applications, including detailed forecasts of Western Canadian crude oil prices, assessment of likely Western Canadian crude oil consumers, and pipeline utilization studies. The Crude Market Optimization Model is a distribution model that predicts the flow of crude oil to various markets and the Western Canadian crude oil prices that result from such flows. Consequently, it is well-suited for assessing the market implications of changes in the logistical infrastructure that enables Canadian crude oil to reach the market.
The model uses linear programming (LP) techniques to allocate all Western Canadian and inland U.S. crude oil production among Canadian, U.S., and Northeast Asian refineries, within the confines of existing and expected pipeline, rail, barge, and refinery capacity constraints, while maximizing the Western Canadian crude oil netback price at Edmonton.4 Said differently, the model is seeking to route Western Canadian crude oil to the refineries that will pay the most for the crude oil, taking into consideration the transportation costs from Canada, while simultaneously having due regard for the finite capacities of the pipeline and rail routes (and the refineries themselves)5. In essence, the model attempts to mirror the crude oil distribution pattern that would arise from an efficiently operating crude oil marketplace.
4 The netback price is the price that a specific grade of crude oil is sold for at its market-clearing point, less the transportation cost between Edmonton and the market-clearing point. The market-clearing point is also frequently referred to as the parity point. The parity point can, and does, differ between crude oil grades (heavy sour, sweet synthetic, etc.). 5 The model is also seeking to minimize the transportation cost (thus maximizing their netback) for various inland U.S. crude oil grades. It is necessary to also consider U.S. crude oils because U.S. inland and Canadian crude oils are frequently competing for the same pipeline and refinery capacity.
Page 14 The inputs to the model include: 1) The supply of Western Canadian, Alaskan, and inland U.S. crude oil, by individual crude grade (heavy sour, sweet synthetic, etc.);
2) The capacity of each pipeline, rail, and barge route (by segment, where necessary);
3) Where applicable, pipeline volume commitments;
4) The pipeline tolls/rates and other transportation costs (e.g., tanker, barge, and rail costs);
5) The crude oil capacity of each refinery as well as refinery-specific constraints; and
6) The refining value of the crude oil grades at each refinery, expressed as a function of crude oil throughput.
The supply of inland U.S. crude oil is a model input because it influences the disposition of Canadian crude oil (as U.S. and Canadian crude oil frequently use the same pipeline) and consumes refinery capacity that would be otherwise available for Canadian crude oil. Once the variables are input into the model, linear programming techniques are used to maximize the desired outcome, which in this case is the aggregate Edmonton netback crude oil price, while simultaneously satisfying all of the constraints imposed upon the solution.
CRUDE OIL SUPPLY
The June 2012 CAPP forecast is the basis for the Western Canadian crude oil supply projection The CAPP forecast disaggregates total Canadian supply into Light and Medium Conventional, Conventional Heavy, Upgraded Light (Synthetic), and Oil Sands Heavy. To improve the precision of the optimization model, Muse has further disaggregated the Oil Sands Heavy category into Western Canadian Select, Cold Lake Blend, Athabasca Dilbit, Athabasca Synbit, and sour synthetic.
Page 15 For Bakken crude oil production (Williston Basin), the internal Enbridge forecast that supported its application to the NEB for the Bakken Pipeline Project Canada (OH-1-2011) has been used. Muse’s internal forecasts are used for other inland U.S. regions (West Texas, Rockies, etc.) and Alaska.
CRUDE OIL TRANSPORTATION INFRASTRUCTURE AND TOLLS
The North American crude oil pipeline network modeled is that which exist today plus all significant non-Enbridge pipeline projects that have been approved by the NEB. Muse has assumed certain U.S. pipeline projects will take place that, in Muse’s opinion, are highly likely to proceed.6 Major Enbridge expansion projects, both in Canada and the U.S., are also included in the Crude Market Optimization Model although they may not have been approved by the relevant regulatory authorities as of the date of this report. Details regarding the pipeline assumptions follow:
Keystone System – The capacity of the Legacy Keystone pipeline is taken to be 94,000 m3/d (591 kb/d). For the Keystone XL pipeline, an origination capacity at Hardisty of 111,300 m3/d (700 kb/d) is used. A total volume commitment of 144,700 m3/d (910 kb/d) is used for the Keystone System (XL plus Legacy Keystone). The volume commitment determines the total crude volume that can be transported at the committed tolls on the Keystone System. Destination-specific volume commitments are not imposed, and the committed barrels can be routed to Wood River, Patoka, Cushing, Beaumont-Port Arthur, and Houston, subject to the capacity of the individual pipeline segments of the Keystone System. The volume commitments are assumed to be in place through 2030. Muse has further assumed that the Bakken Marketlink and Cushing Marketlink components of the Keystone XL project also proceed. For the Bakken and Cushing Marketlink projects, Muse has used volume commitments of 10,300 m3/d (65 kb/d) and 11,900 m3/d (75 kb/d), respectively.
6 California and offshore Gulf of Mexico crude pipelines are not included in the model, as they have no influence on Canadian crude distribution.
Page 16 Enbridge Flanagan South – The proposed Enbridge Flanagan South pipeline project is commissioned in 2015 with a capacity of 95,400 m3/d (600 kb/d) with a sizable volume commitment. The Flanagan South pipeline originates in the Chicago area and terminates at Cushing, Oklahoma.
Seaway System – Muse has assumed that the existing Seaway pipeline will be twined by 2015 to provide a total southbound crude capacity between Cushing and Houston, Texas, of 135,100 m3/d (850 kb/d), with a 95,400 m3/d (600 kb/d) extension from Houston to the Beaumont/Port Arthur, Texas, area. There are also volume commitments associated with the twined Seaway system.7
Enbridge Mainline – Consistent with Enbridge’s business plan as of the date of this analysis, the following Mainline segments have been expanded by the indicated capacity: - Cromer to Clearbrook – 55,600 m3/d (350 kb/d) to a total capacity of 415,400 m3/d (2,613 kb/d)
- Clearbrook to Superior – 55,600 m3/d (350 kb/d) to a total capacity of 386,000 m3/d (2,428 kb/d)
- Superior to Chicago/Flanagan – 69,200 m3/d (435 kb/d) to a total capacity of 280,000 m3/d (1,761 kb/d)
- Superior to Sarnia (Line 5) – 7,900 m3/d (50 kb/d) to a total capacity of 86,000 m3/d (541 kb/d)8
7 As of the date of this report, the volume commitments on Flanagan South and Seaway are not public information and, accordingly, are not provided herein. The volume commitments are assumed to be in place through 2030. 8 In 2015, Line 5 capacity is reduced by approximately 5,900 m3/d (37 kb/d) to account for shipments of natural gas liquids (NGLs) in the pipeline. NGL shipments are assumed to decrease by about 2 percent per year, and the Line 5 capacity available for crude oil shipments increases accordingly.
Page 17 - Chicago to Stockbridge (Line 6B) – 41,300 m3/d (260 kb/d) to a total capacity of 78,100 m3/d (491 kb/d)
- Sarnia to Westover (Line 9A) – Reversed to eastbound service
- Westover to Montreal (Line 9B) – Reversed to eastbound service by 2015. The total origination capacity of Line 9 at Sarnia to Westover and Montreal is 47,700 m3/d (300 kb/d).
Enbridge North Dakota System – The following capacities have been used for the Enbridge North Dakota System, and are unchanged throughout the forecast period. - To Clearbrook – The existing capacity of 29,400 m3/d (185 kb/d) plus an additional 35,800 m3/d (225 kb/d) added in 2016 (the Sand Piper Project)
- To Cromer – 32,100 m3/d (145 kb/d)
Trans Mountain – Total capacity is 47,700 m3/d (300 kb/d), less an estimated 7,200 m3/d (45 kb/d) of refined product shipments. A crude loading capacity for the Westridge dock of 11,900 m3/d (75 kb/d) has been used.
Rockies – Total crude export pipeline capacity to the Rockies (PADD IV) is estimated to be 81,700 m3/d (514 kb/d) throughout the forecast period. The Crude Market Optimization Model does not individually model the various export pipelines that connect Alberta with the Rockies. The outbound (from the Rockies) capacities of the Platte and White Cliffs pipelines are estimated to be 23,100 m3/d (145 kb/d) and 11,100 m3/d (70 kb/d), respectively.
Other U.S. Pipeline Projects – Muse has made the following assumptions regarding other potential U.S. pipeline projects. All of these
Page 18 projects are in construction or the advanced commercial development phase and, in the opinion of Muse, are likely to proceed. - The Magellan Longhorn pipeline is in crude service between West Texas and the Houston area with a total capacity of 35,800 m3/d (225 kb/d). Volume commitments are estimated to be 90 percent of pipeline capacity. - The Butte/Belle Fourche pipeline system is expanded to 31,800 m3/d (200 kb/d). - The Shell Ho-Ho pipeline is reversed to transport crude from the Houston area to Louisiana with an origination capacity of 39,700 m3/d (250 kb/d), and an ex-Beaumont capacity of 57,200 m3/d (360 kb/d). - The combined Sunoco West Texas Expansion and Permian Express Phase 1 projects have a capacity of 36,600 m3/d (230 kb/d) between West Texas and the Gulf Coast. The Sunoco Amdel pipeline (Big Spring to Beaumont) has a capacity of 4,800 m3/d (30 kb/d).
Rail and Barge – Barges are currently being used to transport Western Canadian crude down the Mississippi River, and rail has emerged as a credible transportation mode for large volumes of crude. For example, by the end of 2012, an estimated 79,500 m3/d (500 kb/d) of rail loading capacity will be in place in the Williston Basin, mostly in North Dakota. The modeling alternative to assuming increased rail transportation capacity is either the shut-in of Western Canadian crude oil production or some new, high-capacity crude export pipeline that can access a sizable market in either the Gulf Coast or Northeast Asia. Assumptions regarding barge and rail transport follow: - Barge capacity is assumed to be 17,500 m3/d (110 kb/d) in 2015, and grows to 28,600 m3/d (180 kb/d) by 2030. The barge route is via the Mississippi River from the Wood River area to Louisiana.
Page 19 - Total rail capacity for Western Canadian crude oil to the British Columbia ports, for further transportation by tanker to the Pacific markets, is assumed to grow to 63,600 m3/d (400 kb/d) by 2030. In practice, the volume of crude oil that can be transported by rail to British Columbia ports is likely to be more limited by constraints at the ports themselves rather than railroad capacity. The tanker cost from Kitimat to the various Pacific markets is used.
- Total rail capacity (Western Canadian plus Bakken) to the Gulf Coast is assumed to be 21,500 m3/d (135 kb/d) in 2015, and grows to 82,700 m3/d (520 kb/d) by 2030. Slightly different rail costs are used for the Houston, Beaumont/Port Arthur, and Louisiana markets.
- Total rail capacity to the Washington state refineries is estimated at 11,100 m3/d (70 kb/d) in 2015, and grows to 19,100 m3/d (120 kb/d).
- Total rail capacity for Bakken crude to Cushing is assumed to be 17,500 m3/d (110 kb/d) in 2015, and grows slightly over the forecast period.
Pipeline tolls and rates are obtained from NEB, FERC, and state tariff filings. For the Enbridge Mainline System that extends from Alberta to the Midwest and Ontario, the tolls as detailed in the Competitive Toll Settlement have been used. The barge and rail costs are based on Muse’s industry experience and research.
All volume commitments are modeled as shipments that can take place at discounted tolls, rather than as minimum throughput obligations. This more closely mimics actual market behavior, in that it recognizes that committed shippers incur low incremental cash costs to ship, but are not obligated to physically ship the barrels.
Page 20 REFINERY CAPACITY
Within the Crude Market Optimization Model, most refineries located in Canada, the Puget Sound area, the Midwest, and the Mid-Continent are individually represented. Most refineries located in Northern China, Southern China, Japan, Korea, Taiwan, Gulf Coast, the Rockies, and California are represented as a number of aggregates, rather than as individual refineries, mostly due to the large number of refineries in these areas. For U.S. refineries, crude capacities are obtained from the Energy Information Administration (EIA) Refinery Capacity 2012 Report, adjusted by Muse as appropriate to incorporate known capacity expansions.9 Capacity information for other refineries is obtained from the Oil & Gas Journal 2012 Worldwide Refining Survey, frequently supplemented with information from company and other public sources.10 Muse has applied utilization factors, which vary somewhat by region and refinery, to the refinery calendar day capacities within the Crude Market Optimization Model
CRUDE OIL REFINING VALUES
A key input variable to the Crude Market Optimization Model is the value of various Western Canadian crudes to the potential refinery customers. Muse refers to these crude values as the crude oil refining value. The refining values are developed by Muse via the use of highly complex refinery LP models. Muse licenses the AspenTech PIMS® modeling system, which is the same system used by over half of the North American refiners to optimize their refinery operations. The refiner’s optimization objectives include crude selection, determining process unit run rates, and selecting the mix of refined products to be produced. The PIMS® models used by Muse are substantially identical to those used by the refiners themselves.
For each refinery, or refinery aggregate, of interest in the Canadian crude oil market area, a PIMS® model is constructed using public information regarding individual
9 EIA, Refinery Capacity 2012, Table 3, “Capacity of Operable Petroleum Refineries by State as of January 1, 2012.” 10 Oil & Gas Journal, December 5, 2011.
Page 21 process unit capacities and capabilities. A base case is established whereby the refinery is fully utilizing the key process units using some combination of domestic crudes and waterborne imports. Next, increasing volumes of the various Canadian crude oil grades are input to the model, backing out some volume of the refiner’s crude oil alternatives, thus developing an understanding of the value to the refiner of the Canadian crude oil as a function of the Canadian crude oil throughput.11 The value of any crude oil grade typically decreases as its throughput increases, as all refineries generally experience diminishing returns for any specific crude oil grade as greater volumes are processed. This can be because process unit constraints require the sale of lower-valued intermediate products, various product specifications are becoming increasing difficult to satisfy, or key process units are not fully utilized. By developing an understanding of the value of Canadian crude oils as a function of the individual refinery throughput, the marketplace for Canadian crude oil can be disaggregated into a much larger number of demand nodes than would be possible if only whole individual refineries were considered. This analytical approach improves the precision of the optimization model.
The development of the Canadian crude oil refining values with a refinery LP model requires a complete set of non-Canadian crude oil and refined product prices. The non- Canadian crude oil prices are important as they are the competitive alternative that is being displaced by the Canadian crude. Canadian crude oils also produce a slightly different set of refined products than the non-Canadian alternative, thus the refined product prices are also required to fully assess the refining value of the Canadian crude oils.
11 Refining values are developed using the PIMS models for Cold Lake Blend, Western Canadian Select, Athabasca DilBit, and Sweet Synthetic. Values for the conventional Canadian crude oil grades and sour synthetic are developed from correlations using the explicitly modeled grades.
Page 22 CRUDE OIL AND PRODUCT PRICE FORECAST
For the analysis, Muse has used its standard, as of November 2012, crude oil and refined petroleum product price forecast. Muse employs a long-established methodology for the development of its price forecasts that is fundamentally based on five key market variables. These variables are:
1) Light Louisiana Sweet (LLS) price at St. James, Louisiana, which primarily establishes the absolute price level for all crude oils and products;
2) Natural gas price at the Houston Ship Channel, which influences refinery operating costs and the liquid petroleum gases (LPG) to light product (gasoline, diesel, etc.) pricing relationships;
3) Contribution margin for a Gulf Coast cracking refinery, which primarily influences the light product to crude differential;
4) The contribution margin for a Gulf Coast coker, which primarily influences the light-heavy product differential; and
5) The ultra-low sulfur diesel to unleaded regular differential.
These variables are used because they address the principal aspects of the refining industry and are comparatively independent of one another. The future values for these variables that Muse selects are informed both by the refining industry’s historical experience and Muse’s analyses and opinions regarding its forward path. Once the five independent variables are selected, Muse’s proprietary pricing models generate a unique set of Gulf Coast refined product, LPG, and intermediate feedstock prices that return the cracking refinery and coking margins required, and are consistent with the three other independent variables.
Muse’s crude oil price forecasting methodology is based upon the principle that all crude oils that have their price established in a given market (U.S. Gulf Coast,
Page 23 Rotterdam, Singapore, etc.) must have the same refining margin.12 For a refiner, the product yield of a crude oil, and the associated operating costs, is its primary determinant of value. Therefore, as part of its crude pricing methodology, Muse generates the product yields and variable operating costs representative of a typical Gulf Coast cracking refinery for a large number of crude oils. The net refining values for all crude oils of interest are then generated by multiplying the crude-specific product yield by the product prices, and subtracting the variable operating costs. The forecast price for all crude oils priced on the Gulf Coast then equals the net refining value less the desired contribution margin for a Gulf Coast cracking refinery. This methodology leaves the refiner indifferent between purchasing one crude oil versus another. Crude prices at inland locations for all crudes priced on the Gulf Coast are developed by adding the appropriate pipeline tolls to the Gulf Coast crude value.
ANALYTICAL RESULTS
The output of the Crude Market Optimization Model includes:
1) The throughput on each pipeline, barge, tanker, and rail route;
2) The disposition of Western Canadian crude by market;
3) The disposition of inland U.S. crude by market;
4) Refinery throughput; and
5) The value (price) of each Canadian crude oil grade.
The detailed disposition of the Canadian heavy crude oil that transits the Hardisty Hub is provided in Appendix Table I. The precise transit volume is determined by starting with the total consumption of Canadian heavy crude oil in the indicated markets, and then making certain adjustments to account for the volume of heavy crude oil
12 If not, the refiner will buy the higher margin crude oil, increasing its price, and sell (or not buy) the lower margin crude oil, lowering its price, until the crude oil margins come back into equilibrium.
Page 24 transported by rail to the indicated markets and the volume of Canadian conventional heavy crude oil delivered into the Rockies. This latter adjustment is made because a portion of the conventional heavy crude oil that is delivered into the Rockies does not transit Hardisty.
Appendix Table II provides the detailed analysis of the required amount of inbound heavy crude oil pipeline capacity to Hardisty. The volume of Canadian heavy crude oil exiting Hardisty via the Enbridge Mainline, the Keystone System, and the Express/Milk River pipelines is captured from the output of the Crude Market Optimization Model. The heavy crude oil throughput on the individual pipelines is not shown as the Enbridge Mainline volume is influenced by the volume commitments and tolls on the Enbridge Line 9B and Flanagan South Projects, and this sensitive business information is confidential at this point in time.13
The inbound Oil Sands heavy crude pipelines include:
Enbridge Athabasca System – In 2015, the capacity is 93,600 m3/d (589 kb/d), expanded by 71,500 m3/d (450 kb/d) in 2016 (the Athabasca Twinning Project currently in the regulatory approval phase at the ERCB). Light crude oil shipments on the Athabasca System will be between 11,400 and 27,800 m3/d (72 and 175 kb/d), leaving a net heavy crude oil inbound capacity of 137,400 to 153,700 m3/d (864 to 967 kb/d) post-2016. For the analysis, the Enbridge Athabasca System is assumed to operate at 100 percent of capacity.
Enbridge Line 4 – Heavy crude oil capacity is 126,600 m3/d (796 kb/d) and transports only Athabasca, Peace River or Cold Lake heavy crude oil blends (no conventional heavy crude oil). The Line 4 capacity was provided by Enbridge.
13 The confidential information was provided to Muse by Enbridge.
Page 25 IPF Cold Lake Pipeline – The IPF Cold Lake System capacity is taken to be 50,100 m3/d (315 kb/d) and transports only Athabasca or Cold Lake heavy crude oil blends. The pipeline capacity was obtained from the 2012 Inter Pipeline Fund Annual Information Form, pg. 6.
CNRL Echo Pipeline – The Echo Pipeline capacity is taken to be 12,000 m3/d (75 kb/d) and transports only Athabasca or Cold Lake heavy crude oil blends. The pipeline capacity was obtained from the ERCB ST98-2011 report, pg. 3-25.
In addition to the inbound Oil Sands heavy crude oil pipelines, there is a significant volume of conventional heavy crude oil that is delivered into Hardisty or on the Enbridge Mainline at Regina or Cromer by various gathering systems. These conventional heavy crude oil volumes would reduce the need for inbound heavy crude oil pipeline capacity, irrespective if they are received at Hardisty or further downstream on the Enbridge Mainline. The net volume of conventional heavy crude oil available for the markets serviced by the Hardisty hub is estimated by subtracting from the CAPP forecast of conventional heavy crude oil the deliveries to the Rockies via the Express and Bow River/Milk River pipelines and local refinery consumption. The volume of Canadian conventional heavy crude oil shipped into the Rockies is obtained from the Crude Market Optimization Model. The volume of conventional heavy crude oil processed by the Gibson Moose Jaw and COOP Regina refineries is estimated by Muse.
The final step of the analysis is to calculate the required amount of operating margin needed to efficiently operate the Hardisty hub. The required operating margin is estimated to be 20 percent of the total outbound heavy crude oil volume.
Appendix Table II provides the quantum of surplus or deficit inbound heavy crude oil pipeline capacity both without consideration of an operating margin and with the operating margin considered. As detailed in Appendix Table II, and summarized below through 2025 in Table 8, if the Hardisty heavy crude oil supply-demand balance
Page 26 includes the consideration of a reasonable degree of operating margin, there is a need for additional inbound heavy crude oil pipeline capacity in all years but one over the forecast period (the exception is 2016).
Table 8 HARDISTY HEAVY CRUDE OIL SUPPLY-DEMAND BALANCE
(Thousands of Barrels per Calendar Day, Unless Noted)
Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Surplus (Deficit) with Operating Margin Lower Range (200) 15 (227) (383) (151) (437) (528) (725) (797) (865) (1,050) Upper Range (97) 118 (124) (280) (48) (334) (425) (622) (694) (762) (947)
Page 27 A P P E N D I X T A B L E I DISPOSITION OF HEAVY CRUDE OIL TRANSITING THE HARDISTY HUB
(Thousands of Barrels per Calendar Day, Unless Noted)
Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Submarket Heavy Crude Demand Atlantic Canada/US East Coast - - 6.3 6.3 4.7 6.3 - 6.3 24.9 85.7 101.6 101.6 121.4 130.8 130.8 130.8 Ontario/Quebec 130.8 137.7 137.7 139.7 132.8 132.8 132.8 132.8 139.7 139.7 146.6 146.6 146.6 146.6 146.6 146.6 Rockies 159.5 160.0 166.9 181.9 179.5 182.9 183.3 183.8 185.3 185.7 196.2 197.0 197.4 199.0 199.4 199.8 Upper Midwest 849.4 839.5 848.0 870.9 863.7 861.1 868.6 876.6 883.4 885.6 907.4 907.3 928.9 938.3 950.9 949.7 Lower Midwest 211.9 213.9 214.5 214.4 214.4 213.9 210.8 210.1 215.3 217.2 212.1 222.7 223.4 223.4 231.4 247.2 Mid-Continent 91.8 91.8 85.9 85.9 79.3 94.7 92.1 81.6 94.7 97.1 104.1 106.0 101.8 116.8 124.7 143.8 U.S. Gulf Coast 319.4 514.5 697.4 782.7 614.8 833.5 907.6 1,065.2 1,096.3 1,141.9 1,254.4 1,302.7 1,435.3 1,564.6 1,641.1 1,760.7 Total 1,762.9 1,957.5 2,156.7 2,281.7 2,089.2 2,325.1 2,395.2 2,556.3 2,639.5 2,752.9 2,922.5 2,983.9 3,154.9 3,319.6 3,425.0 3,578.7
Adjustments Rail to U.S. East Coast ------(24.9) (85.7) (101.6) (101.6) (101.6) (101.6) (101.6) (101.6) Conv. Heavy to Rockies (116.6) (116.0) (116.0) (116.0) (131.0) (126.7) (116.0) (126.0) (131.3) (121.3) (117.7) (118.4) (118.9) (119.4) (119.8) (120.2) Rail to U.S. Gulf Coast ------(50.3) (144.2) (234.0) (356.1) Heavy Crude Shipments via Hardisty Atlantic Canada/US East Coast - - 6.3 6.3 4.7 6.3 - 6.3 - - - - 19.8 29.2 29.2 29.2 Ontario/Quebec 130.8 137.7 137.7 139.7 132.8 132.8 132.8 132.8 139.7 139.7 146.6 146.6 146.6 146.6 146.6 146.6 Rockies 42.9 44.0 50.8 65.8 48.5 56.1 67.3 57.8 54.0 64.4 78.5 78.5 78.5 79.6 79.6 79.6 Upper Midwest 849.4 839.5 848.0 870.9 863.7 861.1 868.6 876.6 883.4 885.6 907.4 907.3 928.9 938.3 950.9 949.7 Lower Midwest 211.9 213.9 214.5 214.4 214.4 213.9 210.8 210.1 215.3 217.2 212.1 222.7 223.4 223.4 231.4 247.2 Mid-Continent 91.8 91.8 85.9 85.9 79.3 94.7 92.1 81.6 94.7 97.1 104.1 106.0 101.8 116.8 124.7 143.8 U.S. Gulf Coast 319.4 514.5 697.4 782.7 614.8 833.5 907.6 1,065.2 1,096.3 1,141.9 1,254.4 1,302.7 1,385.1 1,420.4 1,407.1 1,404.6 Total 1,646.3 1,841.4 2,040.7 2,165.6 1,958.2 2,198.4 2,279.2 2,430.3 2,483.4 2,545.9 2,703.2 2,763.8 2,884.2 2,954.4 2,969.6 3,000.7
Page 28 A P P E N D I X T A B L E II HARDISTY HEAVY CRUDE OIL SUPPLY-DEMAND BALANCE
(Thousands of Barrels per Calendar Day, Unless Noted)
Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Outbound Pipeline Demand Enbridge Mainline System Legacy Keystone Keystone XL Express/Milk River Total Outbound Pipeline 1,646.3 1,841.4 2,040.7 2,165.6 1,958.2 2,198.4 2,279.2 2,430.3 2,483.4 2,545.9 2,703.2 2,763.8 2,884.2 2,954.4 2,969.6 3,000.7
Inbound Pipeline Supply
Enbridge Line 4 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0 796.0
Enbridge Athabasca Capacity 589.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 1,039.0 Maximum Light Shipments (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) (175.0) Minimum Light Shipments (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) (72.0) Minimum Heavy Supply 414.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 864.0 Maximum Heavy Supply 517.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0 967.0
IPF Cold Lake 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0 315.0
CNRL Echo 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0
Total Inbound Oil Sands Heavy Minimum 1,600.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 2,050.0 Maximum 1,703.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0 2,153.0
Local Conventiona Heavy Balance Total Supply (CAPP 2012) 317.5 315.8 313.1 306.7 304.7 302.5 297.7 292.1 289.2 286.7 286.6 283.3 280.2 276.0 274.4 271.8 Conventional Heavy to Rockies (116.6) (116.0) (116.0) (116.0) (131.0) (126.7) (116.0) (126.0) (131.3) (121.3) (117.7) (118.4) (118.9) (119.4) (119.8) (120.2) Local Refinery Consumption (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) (25.0) Net Availability 175.9 174.8 172.1 165.7 148.7 150.8 156.6 141.2 132.9 140.3 143.9 139.8 136.3 131.6 129.6 126.6
Net Hardisty Heavy Crude Balance
Outbound Pipeline Demand 1,646.3 1,841.4 2,040.7 2,165.6 1,958.2 2,198.4 2,279.2 2,430.3 2,483.4 2,545.9 2,703.2 2,763.8 2,884.2 2,954.4 2,969.6 3,000.7 Inbound Pipeline Supply Minimum (1,600.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) (2,050.0) Maximum (1,703.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) (2,153.0) Local Heavy Production (175.9) (174.8) (172.1) (165.7) (148.7) (150.8) (156.6) (141.2) (132.9) (140.3) (143.9) (139.8) (136.3) (131.6) (129.6) (126.6)
Surplus (Deficit) Lower Range 129.6 383.3 181.4 50.0 240.5 2.4 (72.6) (239.2) (300.5) (355.6) (509.3) (574.0) (697.8) (772.8) (790.0) (824.1) Upper Range 232.6 486.3 284.4 153.0 343.5 105.4 30.4 (136.2) (197.5) (252.6) (406.3) (471.0) (594.8) (669.8) (687.0) (721.1)
20 Percent Operating Margin (329.3) (368.3) (408.1) (433.1) (391.6) (439.7) (455.8) (486.1) (496.7) (509.2) (540.6) (552.8) (576.8) (590.9) (593.9) (600.1)
Surplus (Deficit) with Operating Margin Lower Range (199.6) 15.1 (226.7) (383.1) (151.1) (437.2) (528.4) (725.2) (797.2) (864.8) (1,049.9) (1,126.8) (1,274.7) (1,363.7) (1,383.9) (1,424.3) Upper Range (96.6) 118.1 (123.7) (280.1) (48.1) (334.2) (425.4) (622.2) (694.2) (761.8) (946.9) (1,023.8) (1,171.7) (1,260.7) (1,280.9) (1,321.3)
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