Enbridge Pipelines Inc. Application Submitted to the NEB Line 3 Replacement Program Appendix 10-1 Major Announced Rail Uploading Terminals in Western Canada Operator Location Expanded Scheduled Figure 4.4 Rail Loading Terminals in Western Canada / Proposed Startup Capacity** (thousand b/d) ALBERTA Proposed Keyera/ Cheecham 32 Operating Enbridge Major Expansion Athabasca Grizzly Conklin 18 Q2 2014 Deposit Existing Canexus Bruderheim (near 100 Operating; Fort Oil sands Deposits and Oil Plays McMurray Edmonton) +? Expansion Q3 2014 Reno Cheecham Gibson Edmonton 20 (expandable Q3 2015 Falher Peace River to 40) Deposit Sexsmith Keyera/Kinder Edmonton 40 (expandable Q3 2014 (currently Morgan to 120) in construction) Cold Lake Pembina Edmonton 40 Operating Whitecourt Deposit Cardium Altex Falher 20 Operating; Strathcona County expansion Q4 2014 Edmonton Lloydminster Gibson/USDG Hardisty 120 (expandable Q2 2014 Wainwright Lashburn x2 Unity to 240) Rimbey Hardisty Kerrobert Torquay Altex Lynton 20 Operating; Lower Regina Cromer Expansion Q4 2015 Tilley Shaunavon Stoughton Estevan Bakken Woodnorth Altex Reno 24 unknown Wilmar Dollard Shaunavon NorthgateBakken-Three Forks Bromhead KinderMorgan Strathcona 100 (expandable Q4 2014 (currently /Imperial County to 250) in construction) SASKATCHEWAN Crude by Rail Movements Crescent Point Dollard 27 Operating; Expansion Q2 2014 Actual volumes of crude oil being moved by rail are TORQ Kerrobert 168 Q3 2014 generally lower than design capacity at loading facilities. Transloading Altex Lashburn 90 Operating; However, it is important to note that the definition of Expansion Q1 2015 capacity is not very standardized and there are a number TORQ Lloydminister 22 Operating of limiting factors on actual capacity that include: supply Transloading Ceres Global Northgate 35 (expandable Q2 2014 connections, system bottlenecks, operational inefficiencies, to 70) limited hours of operation, and ramp up time required to Crescent Point Stoughton 45 Operating achieve full utilization. Altex Unity 19 Operating TORQ Unity 36 Operating CAPP forecasts crude oil volumes transported by rail will Transloading increase from about 200,000 b/d in late 2013 to around MANITOBA 700,000 b/d by 2016 (Figure 4.5). It is important to note Tundra Cromer 60 Operating; Expansion Q2 2014 that most of the large scale terminals are underpinned by TOTAL 1.0 million b/d; further expandable to 1.4 million b/d long term take or pay contracts which should encourage utilization. Constraints on capacity include unloading time Figure 4.5 Western Canada Uploading Capacity vs. and weather. The load factor utilization should improve Rail Movements over time, however, particularly as producers and operators become more experienced with this mode of transportation. thousand barrels per day 1,600 The schedule for future expansion phases of capacity is 1,400 flexible and dependent on a number of factors including the Capacity timing of securing supply contracts for the facilities which 1,200 may be influenced by the pace of pipeline expansion. 1,000 Rail Movements 800 600 400 200 0 Q1 2013 Q2 2103 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Crude Oil Forecast, Markets & Transportation 32 Page 41 of 52 Enbridge Pipelines Inc. Application Submitted to the NEB Line 3 Replacement Program Appendix 10-1 Economics of Crude by Rail the rail tank car and therefore limits the amount of the commodity that can be transported before meeting the tank In general, the opportunity to ship by rail is greatest when car’s weight limitation. In addition, more time is required for the price differential between the market at a point of loading and unloading heavy crude which thereby adds to origin and the market price at the destination exceeds the cycle times and, in turn increases cost. transportation cost by rail. Recently, this has meant that the economic driver for crude by rail has been between land A number of uncontrollable factors such as weather or locked production and coastal markets where higher world mechanical issues, may also impact cycle times and affect oil prices can be accessed. producers’ netbacks. The opportunity for diluent back haul can also be considered when evaluating the costs. The There are a number of factors which could impact the range is based on the movement of varying densities of the economics of shipping crude oil to market via rail. These crude oil and the distance from markets. The actual costs include prices available in various markets that can all be for each component can fluctuate beyond the ranges shown accessed by rail and cost. The type of crude being moved due to changes to cycle times. Rail tank car leasing costs is a key determinant of cost as the heavier the crude oil are negotiated and are subject to change depending on a slate, the more rail tank cars are required to transport a number of factors, including the length of the lease. given volume of crude. Heavy crude is typically transported in steam coiled and insulated cars in order to reduce the Figure 4.6 shows the approximate cycle times and viscosity of the crude oil to facilitate the unloading process. estimated cost to various key markets in Canada and the The steam line and insulation also adds to the weight of United States. Figure 4.6 Rail Cycle Times and Estimated Cost* to Market Kitimat Cycle days to Can. West 1,069 miles (8.5 - 10) $8.71 - $10.13Ft. McMurray Coast Lynton = 8.5 to 11 cycle days 3,266 miles (15.5 - 17 cycle days); Cost: $19.62-$22.60) Cost: $8.65 - $16.05/bbl 1,060 miles (9.5 to 11) Lloydminster 1,130$8.67 miles - $10.09 (12.5 to 13) Vancouver $9.29 - $16.03 2,401 miles (13.5 to 15 cycle days); Cost:$15.55-$17.98 Cycle days to E. Canada Anacortes 2,779 miles2,553 (14.5 miles to 16 (14.5 cycle to days) 16 cycle; Cost: days);$18.56-$21.47 Cost $16.32-$18.81= 14.5 to 17 cycle days 2,485 miles (13.5 to 15 cycle days); Cost:2,528 $15.29 - $17.67 miles (15.5 to 17 cycle days); Cost: $18.26-$21.05 Cost: $16.30 - $22.60/bbl 3,009 miles (15.5 to 17 cycle days); Cost $19.43 - $22.44 2,787 miles (16 to 17 cycle days); Cost:$19.71 -$21.55 Saint John 2,072 miles (11.5 to 13 cycle days)PADD IV Cost: $13.08 - $14.75 Benicia 2,282 miles (12.5 to 14 cycle days); Cost: $15.57 - $17.78 PADD II Bakersfield Reybold 2,449 miles (13.5 to 15 cycle days); Cost: $15.93 - $18.39 Amoco Los Angeles PADD V Cycle days to US East Coast Cycle days to California = 13.5 to 17 cycle days = 11.5 to 15 cycle days PADD I Cost: $15.60 - $21.50/bbl Cost:$ 13.10 - $18.40/bbl PADD III Natchez Port Arthur Cycle days to US Gulf Coast = 13.5 to 17 cycle days Cost: $15.30 to $22.45/bbl *All rates are estimates only. Actual rates could vary depending on the density of the crude which limits the volume per carload; weather and logistical factors that could increase cycle times. Trucking costs vary depending on density of crude and distance from loading/unloading terminal. Data source: Keystone XL Final Supplemental Environmental Impact Statement 33 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS Page 42 of 52 Enbridge Pipelines Inc. Application Submitted to the NEB Line 3 Replacement Program Appendix 10-1 4.9 Transportation Summary While pipelines will remain the dominant mode of transportation, this analysis shows that in the short to medium Access to new markets will be required to absorb the term, rail can provide the ability to access markets if there are forecasted growth in supply from Western Canada. Pipelines constraints in available pipeline capacity. The role of rail will are the preferred mode of transportation to move crude oil but continue to evolve over the longer term providing producers the protracted regulatory processes has been a challenge. with access to new markets and offering new transportation The Keystone XL Pipeline, which is intended to connect to options (e.g. RailBit). The full extent of the development of rail the heavy crude oil processing refineries in the Gulf Coast, transportation will hinge on the timing and size of additions to has seen significant delays. If approval can be obtained by the pipeline infrastructure. the end of this year, however, then the pipeline could start operating in 2017. The Northern Gateway project, which connects to the West Coast market, has also been delayed slightly to Q3 2018. Figure 4.7 shows the existing and proposed takeaway capacity exiting the WCSB versus forecasted supply movements. The forecasted supply movements were developed by coupling CAPP’s latest supply forecast of western Canadian production with U.S. Bakken volumes that would utilize a portion of the pipeline capacity that exits Western Canada. Figure 4.7 WCSB Takeaway Capacity vs. Supply Forecast million barrels per day 9.0 8.0 7.0 TransCanada Energy East Western Canadian supply + Northern Gateway U.S. Bakken movements* 6.0 Trans Mountain Expansion Keystone XL 5.0 Rail expansion Alberta Clipper Expansion 4.0 Rail - current capacity only Keystone 3.0 Enbridge Mainline 2.0 Rangeland & Milk River 1.0 Trans Mountain Express Western Canadian Refineries 0 2014 2016 2018 2020 2022 2024 2026 2028 2030 *Refers to the portion of U.S. Bakken production that is also transported on the Canadian pipeline network. Capacity shown can be reduced by temporary operating and physical constraints.