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ENBRIDGE PIPELINES INC. MAINLINE PRIORITY ACCESS
REPORT OF
NEIL K. EARNEST, PRESIDENT Muse, Stancil & Co.
December 2019
5080 Spectrum Drive Suite 600E Addison, TX 75001-6505 214-954-4455
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TABLE OF CONTENTS
Page 1. INTRODUCTION ...... 3
2. MAINLINE-CONNECTED REFINERY ATTRIBUTES ...... 5 INTRODUCTION ...... 5 REGIONAL DEMAND FOR WESTERN CANADIAN CRUDE OIL ...... 5 KEY REFINER DEMAND FOR WESTERN CANADIAN CRUDE OIL ...... 8 REFINERY OWNERSHIP ATTRIBUTES ...... 12 EVOLUTION OF U.S. REFINERY OWNERSHIP...... 14 SUMMARY OF CONCLUSIONS ...... 15
3. CANADIAN CRUDE PRODUCER ATTRIBUTES ...... 17
4. MARKET IMPLICATIONS OF PRIORITY ACCESS ...... 19 INTRODUCTION ...... 19 RAIL ACTING AS PRICE SETTING MECHANISM ...... 19 UNCOMMITTED PIPELINE CAPACITY ACTING AS PRICE SETTING MECHANISM ...... 21 CONTRACT PIPELINE CAPACITY ACTING AS PRICE SETTING MECHANISM ...... 22 SUMMARY OF ANALYTICAL CONCLUSIONS ...... 24
5. OVERVIEW OF TRANSPORTATION OPTIONS ...... 26 INTRODUCTION ...... 26 WESTERN CANADIAN REFINERY DEMAND ...... 26 EXPORT PIPELINE CAPACITY ...... 26 RAIL EXPORT CAPACITY ...... 30 KEYSTONE AND TRANS MOUNTAIN APPORTIONMENT ...... 31
APPENDIX A – MAP OF MARKET REGIONS CONNECTED TO ENBRIDGE APPENDIX B – SUPPLY VERSUS EXPORT PIPELINE CAPACITY APPENDIX C – EVOLUTION OF REFINERY OWNERSHIP APPENDIX D – NEIL K. EARNEST CURRICULUM VITAE
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1. INTRODUCTION
1.1. Enbridge Pipelines Inc. (“Enbridge”) will be filing an application (the “Application”) with the Canada Energy Regulator (“CER”) seeking to shift approximately 90 percent of the Canadian Mainline (the “Mainline”) capacity to contract service (“Mainline Priority Access”). Enbridge has engaged Muse, Stancil & Co. (“Muse”) to analyze the market implications related to the Mainline Priority Access and prepare a report. Specific market aspects and issues to be addressed are:
1.1.1. The attributes of the refineries that are directly or indirectly connected to the Mainline;
1.1.2. The attributes of the Western Canadian crude oil producers;
1.1.3. The market implications of Mainline Priority Access; and
1.1.4. The current transportation options available for the export of Western Canadian crude oil.
1.2. U.S. dollar-currency units have been used throughout this report unless specifically noted otherwise. A Canadian-U.S. dollar exchange rate of 1.30/1.00 also has been used.
1.3. This report was written by Neil K. Earnest, President of Muse, and other employees of Muse assisted with the preparation of this report. Mr. Earnest holds a Bachelor of Science degree in Chemical Engineering from Michigan State University and an M.B.A. degree from the University of Houston – Clear Lake, and is a Texas registered Professional Engineer in the discipline of chemical engineering. Mr. Earnest’s 30+ years of professional experience has primarily taken place in the crude oil refining and other closely-related
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industries. He has provided testimony before the National Energy Board (“NEB”) on numerous matters. His curriculum vitae is attached as Appendix D.
1.4. Muse is an international energy consulting firm with its headquarters in the Dallas area with additional offices in Houston, London, and Singapore. The company was established in 1984 and is employee-owned. Muse professionals provide a combination of technical and economic services to assist clients in the evaluation of issues and opportunities in the energy sector.
1.5. It is Mr. Earnest’s professional judgment that the key assumptions used to generate the analytical results presented in this report are reasonable and well founded.
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2. MAINLINE-CONNECTED REFINERY ATTRIBUTES
INTRODUCTION
2.1. This section describes and quantifies the attributes of the Canadian and U.S. refineries that are directly or indirectly connected to the Mainline. The term “indirectly connected” refers to a refinery that is not directly supplied by the Mainline itself, but can be reached via one or more pipelines that are in turn connected to the Mainline. The attributes discussed include refinery capacity by region, ownership characteristics, and refinery consumption patterns of Western Canadian crude oil. Finally, this section briefly discusses the evolution of refinery ownership in the U.S.
REGIONAL DEMAND FOR WESTERN CANADIAN CRUDE OIL
2.2. Figure 1 shows the refinery crude oil capacity, disaggregated by region, that is connected to the Mainline. The regions are broadly determined on the basis of having similar logistical options with regard to Western Canadian crude oil supply. Appendix A provides a map of the regions. Total refinery capacity is approximately 12,650 thousand barrels per day (“kb/d”), which is over four times the Mainline crude oil capacity of about 3,000 kb/d. Of the total connected refining capacity, approximately 40 percent of it is located in the inland regions, with the balance located on the Gulf Coast.
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Figure 1 Refinery Crude Oil Capacity By Region 8,000 400% 7,000 350% 6,000 300% 5,000 250%
4,000 200%
3,000 150%
2,000 100% 1,000 50% Percent of Mainline Capacity 0 0%
Refinery Crude Capacity, kb/d Capacity, Crude Refinery Upper Midwest Lower Midwest Midcontinent Gulf Coast Ontario / Quebec Refinery Crude Capacity Percent of Mainline Capacity SOURCE:EIA, NEB, CAPP, Company Annual Reports, Muse
2.3. Figure 2 below provides the volume of 2018 Western Canadian crude oil processed by refineries (or “crude oil runs”) on a regional basis. The figure also displays the Western Canadian crude oil runs expressed as a percent of total refinery crude oil capacity. The Western Canadian crude oil runs in the U.S. are initially calculated by Muse at the refinery level by downloading U.S. Energy Information Administration (“EIA”) data records into a database. The EIA data records report a number of metrics concerning each batch of imported crude oil, including the processing refinery. This latter metric enables most batches of crude oil imports to be assigned to individual refineries. However, there remains a significant volume of crude oil imports that are not specifically assigned to a processing refinery in the EIA data records, and Muse attempts to allocate these crude oil imports to individual refineries using other metrics.1 The Ontario and Quebec volumes are estimated by Muse with a combination of Canadian
1 API gravity, sulphur content, importer of record, and import location are all metrics that Muse may use to assign crude oil imports to individual refineries. Not all of the unallocated batches are assigned to a specific refinery.
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Association of Petroleum Producers (“CAPP”) information, company annual reports, and industry knowledge. Figure 2
Western Canadian Crude Oil Runs By Region 2,000 100% 1,800 90% 1,600 80%
1,400 70% 1,200 60% 1,000 50% 800 40% 600 30% 400 20% 200 10%
Canadian Canadian Crude Oil Runs, kb/d
0 0% Percent of Total CrudeCapacity Upper Midwest Lower Midwest Midcontinent Gulf Coast Ontario / Quebec Heavy Crude Light Crude Western Canada Crude, % of Total Crude Capacity
SOURCE:EIA, NEB, CAPP and Company Annual Reports, Muse
2.4. In all regions, Western Canadian crude oil runs in 2018 are substantial on an absolute basis, demonstrating that the demand for Canadian crude oil is both widespread and deep in the markets accessible via Enbridge. The market share currently captured by Western Canadian crude oil producers varies significantly across the regions. Both the Upper Midwest and Ontario/Quebec are heavily dependent upon Western Canadian crude oil supply, whereas in the remaining regions Canadian crude oil supply constitutes less than half of crude oil runs. In the large Gulf Coast region, the Canadian market share is about 7 percent of capacity. A key implication of the relatively low Canadian market shares in the regions more distant from Canada, particularly the Gulf Coast, is that there is scope for further diversification of Western Canadian crude oil sales by refiner and refinery.
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KEY REFINER DEMAND FOR WESTERN CANADIAN CRUDE OIL
2.5. This subsection provides an overview of the key consumers of Western Canadian crude oil within the market regions connected to Enbridge. The information shown is developed from EIA and CAPP data, company reports, and Muse analysis. The tables in this section all provide 2018 data.
2.6. The Upper Midwest region is defined as ranging from Minnesota to the Detroit/Toledo area, plus the single refinery located in Pennsylvania that is pipeline-connected to Canada (the United refinery in Warren, Pennsylvania). Table 1 shows the 2018 Western Canadian crude demand, by refiner, in the Upper Midwest. Noteworthy characteristics of the Upper Midwest region include both the number of large consumers of Western Canadian crude oil and the comparatively low share consumed by the largest refiner of Western Canadian crude oil in the region. BP, the single largest consumer of Canadian crude oil, comprises about 24 percent of total regional consumption. Enbridge is the primary transportation route for Western Canadian crude oil supply to this region. Table 1
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2.7. The distribution of Western Canadian crude oil runs for the Ontario-Quebec region is shown in Table 2. With the exception of the Valero Jean Gaulin refinery, located outside of Quebec City, the refineries in this region process a high proportion of Western Canadian crude oil. Enbridge is the primary transportation route for Western Canadian crude oil supply.
Table 2
2.8. The Lower Midwest region consists of the Ohio and Kentucky refineries reached by various pipelines connected to the Mainline, plus the large Wood River and Robinson refineries located in southern Illinois. The number of refiners in this region is roughly a third of that in the Upper Midwest, and the Western Canadian crude oil runs are essentially concentrated among two refiners, as shown by Table 3. However, Husky has announced that it is modifying its Lima, Ohio refinery to process approximately 30 kb/d of Western Canadian heavy crude oil, with an in-service date by the end of 2019.2
2 Husky presentation, Barclays CEO Energy-Power Conference, September 2019, slide 15.
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Table 3
2.9. The existing Keystone Pipeline is a major source of Canadian crude oil supply to the Lower Midwest region. This is supplemented by additional Canadian supply via the Express/Platte system and the Southern Access Extension Pipeline. Pipelines from North Dakota (Bakken crude oil) and West Texas crude oil provide competing light crude oil supply to the region.
2.10. The Midcontinent region includes the Kansas, Oklahoma, and Texas Panhandle refineries. Table 4 provides the breakdown of Western Canadian crude oil runs by refiner in the region. Four refiners are significant consumers of Western Canadian crude oil in the Midcontinent. Canadian crude oil is supplied to this region by both Enbridge (via Spearhead Pipeline) and the Keystone Pipeline. Competing crude oils include those produced locally and in West Texas, the Rockies, and North Dakota.
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Table 4
2.11. The Gulf Coast is the largest market region accessible via Enbridge, and it also is the largest concentration of refining capacity in the world. Table 5 provides the distribution of Western Canadian crude oil runs in the region, and Canadian receipts are almost exclusively the heavy sour crude oil grades. With regard to Canadian crude oil runs, this region is characterized by low market share at both the regional and individual refiner level. In addition, Canadian crude oil runs are widely distributed among the Gulf Coast refiners. These regional characteristics indicate that there is room on the Gulf Coast for growth in Western Canadian crude oil supply and customer diversification.
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Table 5
2.12. Western Canadian crude oil supply reaches the Gulf Coast via pipelines connected to the Enbridge Mainline and the Keystone Pipeline. Competing sources of heavy sour crude oil are primarily from Latin America. Recent Venezuelan political developments that have acted to severely curtail crude oil supply from this country have increased the interest among Gulf Coast refiners in alternative sources of heavy crude oil supply.
REFINERY OWNERSHIP ATTRIBUTES
2.13. Refinery ownership can be broadly categorized into those that are owned by companies that have sizable Western Canadian crude oil production (“Canadian integrated refiners”) and those which do not have significant equity production in
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Western Canada (“non-integrated refiners”).3 Figure 3 displays the distribution of Western Canadian crude oil runs by the Canadian integrated and non-integrated refiners. The estimated Western Canadian crude oil runs for the Canadian integrated refiners totaled 882 kb/d in 2018, whereas the non-integrated refiner runs of Western Canadian crude were 2,139 kb/d. It is noteworthy that non- integrated refiner demand is more than double that of the Canadian integrated refiners, and that there are roughly twice the number of non-integrated refiners versus the Canadian integrated refiners.
Figure 3
Western Canadian Crude Oil Runs By Company Mainline Accessible Region
500 Canadian Integrated Non-integrated 400
300
200 kb/d 100
0
Heavy Crude Oil Light Crude Oil
SOURCE: EIA, NEB, CAPP and Company Annual Reports, M use
2.14. Figure 4 aggregates the data in Figure 3 above and presents the total Western Canadian crude oil runs by refiner type. Figure 4 also provides the Western Canadian crude oil runs as a proportion of refining capacity. The Canadian integrated refiners process about 30 percent Western Canadian crude oil. In summary, the analysis indicates that the crude oil market accessed by Enbridge
3 These definitions are slightly different from the traditional definitions, in that a non-integrated refiner may have sizable equity crude oil production, just not in Canada. BP is an example of a non- integrated refiner with extensive global equity crude oil production that does not have much production in Canada.
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does not have a high degree of refiner integration with upstream Western Canadian crude oil production.
Figure 4
Western Canadian Crude Oil Runs By Refiner Type Mainline Accessible Region
2,500 50%
2,000 40%
1,500 30%
1,000 20%
500 10%
Capacity Crude of Percent Canadian Crude Runs, Oil kb/d 0 0%
Heavy Crude Light Crude Western Canadian Crude, % of Capacity SOURCE: EIA, NEB, CAPP and Company Annual Reports, M use
EVOLUTION OF U.S. REFINERY OWNERSHIP
2.15. The nature of refinery ownership is dynamic and the current ownership profile will continue to change, as it has over many years. To illustrate this point, Figure 5 shows the evolution of U.S. refinery ownership over the last two decades between the integrated and independent (or non-integrated) refiners.5 Due to information source limitations, data for only the U.S. are shown.
5 This figure adopts the traditional definition of an integrated refiner as being one that has significant equity crude oil production somewhere in the world. Thus, BP is defined as an integrated refiner in this figure.
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Figure 5
Historical U.S. Refinery Ownership Profile 20,000 200 18,000 180 16,000 160 14,000 140
12,000 120 10,000 100 8,000 80 6,000 60
4,000 40 Number of Refineries Crude Oil Capacity, kb/d 2,000 20 0 0 2000 2010 2019 Integrated Independent No. of Integrated Refineries No. of Independent Refineries SOURCE:EIA, Muse
2.16. The general trend has been a decline in refinery ownership among the integrated refiners. Since 2010, the U.S. refining capacity held by the integrated companies has decreased by about 2,000 kb/d. In 2010, the four top U.S. refiners were all integrated companies (ExxonMobil, BP, Chevron, and Marathon). Today, only ExxonMobil remains among the top four U.S. refiners. Further detail on the evolution of U.S. refinery ownership is provided in Appendix C. Accordingly, recent historical trends indicate that the proportion of U.S. refining capacity held by integrated companies is unlikely to increase, and may decline further.
SUMMARY OF CONCLUSIONS
2.17. Total refinery capacity accessible via the Enbridge Mainline is approximately 12,650 kb/d, which is over four times the Mainline crude oil capacity.
2.18. In all of the regions accessible via the Enbridge Mainline, Western Canadian crude oil runs are substantial, which demonstrates that the demand for Canadian
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crude oil is both widespread and deep in the accessible markets.
2.19. In the more distant regions from Canada, particularly the large Gulf Coast region, the relatively low Canadian market share indicates that there is scope for further diversification of Canadian crude oil sales by refiner and refinery.
2.20. Non-integrated refiner demand for Canadian crude oil is more than double that of the integrated refiners, and there are roughly twice the number of non-integrated refiners versus integrated refiners.
2.21. The analysis indicates that the crude oil market accessed by the Enbridge Mainline does not have a high degree of refinery integration with upstream Western Canadian crude oil production.
2.22. The historical experience indicates that the amount of U.S. refining capacity owned by integrated companies is unlikely to significantly increase, and integrated companies may continue their historical trend of selling refinery capacity.
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3. CANADIAN CRUDE PRODUCER ATTRIBUTES
3.1. This section describes and quantifies the attributes of the Western Canadian crude oil producers. The producer characteristics discussed include production volumes and categorization as integrated or non-integrated. An integrated Canadian producer is defined as one that has significant pipeline access to one or more refineries which it owns and operates.
3.2. Data generated by Rystad Energy, an independent energy consulting services and business intelligence data firm, of crude oil production by company has been used to generate Figure 6. The integrated producers, with a total estimated production volume of 1,374 kb/d in 2018, comprise about 35 percent of the total Western Canadian crude oil production volume. The non-integrated category consists of CNRL, Cenovus, a few National Oil Companies (“NOCs”), and a number of smaller crude oil producers.6 About 4 percent of the total production is unidentified in the Rystad Energy data. Overall, there is a substantial degree of diversification among the Western Canadian crude oil producers.
6 The small producers category numbers about 110 companies, and about 8 percent of the production in this category is from large companies without much crude oil production in Canada.
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Figure 6
2018 Western Canadian Crude Oil Production 1,000
800
600
kb/d 400
200
0
Integrated Non-integrated Other SOURCE: Rystad Energy
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4. MARKET IMPLICATIONS OF PRIORITY ACCESS
INTRODUCTION
4.1. Broadly, the price of Western Canadian crude oil at Edmonton equals its value at the market-clearing point less the cost of transportation, i.e., the netback price. In general, the current market-clearing point for Western Canadian heavy sour crude oil is the Gulf Coast, where Western Canadian crude oil competes with similar heavy sour crude oil grades from Latin America. The incremental transportation mode by which Western Canadian crude oil is reaching the Gulf Coast is currently relatively high-cost rail, resulting in lower netback prices for Western Canadian crude oil producers than if pipeline capacity was available (assuming that the pipeline cost is less than the rail cost). This situation whereby rail is acting as the price-setting mechanism can be expected to persist until sufficient pipeline capacity is built such that rail does not need to be used to transport a significant volume of Western Canadian crude oil.
RAIL ACTING AS PRICE-SETTING MECHANISM
4.2. Rail has become an important crude oil transportation mode in North America. Figure 7 below illustrates the growth of Canadian crude oil shipments by rail to the U.S. from January 2011 through August 2019 (the most recent data as of the date of this report). Crude oil shipments by rail to the U.S. have exceeded 400 kb/d, and have averaged about 290 kb/d year-to-date. In addition to the rail volumes captured by the EIA data shown in Figure 7, there are also crude oil shipments by rail within Canada itself.
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Figure 7 Canadian Crude Oil Shipment by Rail to U.S.
450 400 350 300 250
kb/d 200 150 100 50 -
SOURCE: EIA
4.3. One implication of rail transportation acting as the price-setting mechanism is that the pipeline tolls do not influence the crude oil price at Edmonton. This is not to say that pipeline shippers are indifferent to the pipeline toll, just that the pipeline toll does not influence the crude oil price at Edmonton. An illustration of the Edmonton netbacks via rail, Keystone and Enbridge is provided in Table 6, using a price (or value) for a Western Canadian heavy crude oil at Houston of $55.00/barrel. As highlighted with the red box, it can be observed that the illustrative netback via rail is $37.27/barrel, which is $4.08/barrel less than the netback via Keystone and $7.52/barrel less than the netback via Enbridge.7
7 The rail transportation costs are Muse estimates. Keystone uncommitted: TransCanada Keystone Pipeline GP Ltd, NEB Tariff No. 43. Keystone committed: Keystone Pipeline System NEB Tariff No. 34 (20-year A contract to Houston) and TransCanada Keystone Pipeline, LP FERC No. 6.42 (20-year A contract to Houston). Enbridge uncommitted: Enbridge Pipelines (FSP) L.L.C. NEB No. 446. Enbridge committed: Enbridge Pipelines (FSP) L.L.C. NEB No. 446 (Flanagan South 20-year contract international joint toll). The Flanagan South contract international joint tolls are not influenced by implementation of Mainline Priority Access.
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Table 6
ILLUSTRATION OF HEAVY CRUDE OIL NETBACKS
(U.S. Dollars per Barrel)
Uncommitted Tolls 20-Year Committed Tolls Enbridge Enbridge Rail Keystone Flanagan South Keystone Flanagan South
Crude Oil Price at Houston 55.00 55.00 55.00 55.00 55.00
Less Transportation Costs Rail loading fees 1.50 - - - - Railway fees 13.11 - - - - Tank car lease expenses 1.62 - - - - Rail unloading fees 1.50 - - - -
Enbridge Edmonton to Hardisty1 - 0.65 - 0.65 - Keystone - Canada1 - - - 2.07 - Keystone - U.S. - 13.00 - 10.22 - Flanagan South - - 10.21 - 7.96 Total Transportation 17.73 13.65 10.21 12.94 7.96
Edmonton Netback Price 37.27 41.35 44.79 42.06 47.04
Note: 1) Exchange Rate = CN$1.30 per US$1.00
4.4. It should be understood that there can be only one price at Edmonton, since the crude oil buyers seeking to ship via pipeline are aware of the approximate netback price via rail, and will seek to pay only that price (and some crude oil buyers may be simultaneously shipping by pipeline and rail). Conversely, if the buyers shipping via pipeline were paying a higher price than the rail shippers, then the crude oil sellers would direct their sales to only the pipeline shippers until the price paid by the pipeline and rail shippers equilibrated.
UNCOMMITTED PIPELINE CAPACITY ACTING AS PRICE-SETTING MECHANISM
4.5. Table 6 above also illustrates the situation if uncommitted capacity on the pipelines is acting as the price-setting mechanism. In this circumstance, the Edmonton price would increase to $41.35/barrel with Keystone acting as the price-setting mechanism, which would only arise if either the Enbridge Mainline or Flanagan South is at capacity. If the Enbridge Mainline and Flanagan South are not full, then Flanagan South will be acting as the price-setting mechanism,
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and the Edmonton crude oil price rises to $44.79/barrel.8 It is also the case that implementing Mainline Priority Access does not change the Edmonton crude oil price, since the uncommitted shipments on either Keystone or Enbridge are acting to set the price.9
CONTRACT PIPELINE CAPACITY ACTING AS PRICE-SETTING MECHANISM
4.6. Finally, there is the possibility that the incremental barrel is being shipped to the Gulf Coast by a contract shipper at a contract toll, thus acting as the price-setting mechanism. This possibility is illustrated by Figure 8, which considers the scenario whereby Keystone XL and the Trans Mountain Expansion Project (“TMEP”) are both commissioned in 2022. Appendix B provides the numeric data for Figure 8 as well as the information sources. In this scenario, the total crude oil contract volume is almost 5,000 kb/d, as compared to a net CAPP supply volume in 2022 of 4,677 kb/d.10 For the first four years (2022 to 2025), the contract capacity exceeds the volume of Western Canadian crude oil that must be exported. Consequently, during this period Western Canadian crude oil prices can be expected to be established by the contract tolls. Furthermore, this circumstance can only arise if the Enbridge Mainline adopts Priority Access. Without the Enbridge Mainline in contract service, even the conversion of all of the other export pipelines to 100 percent contract would be less than the net CAPP supply volume.11 Accordingly, converting the Enbridge Mainline to Priority Access would act to increase the Western Canadian crude oil price.
8 TC Energy, the owner of Keystone, has the ability to change its spot tolls, subject to a cap, on a month- by-month basis. Accordingly, TC Energy would likely reduce its spot toll such that it is at or below the uncommitted toll on Flanagan South and both pipelines generally would be acting to set the price. 9 If uncommitted shipments on Enbridge are establishing the Edmonton price, then this assumes that the uncommitted toll under Mainline Priority Access is similar to the Enbridge toll without Priority Access to Flanagan. The Flanagan South uncommitted toll (Flanagan to Houston) is not influenced by Mainline Priority Access. 10 The net Canadian Association of Petroleum Producers (“CAPP”) supply volume is the 2019 CAPP supply forecast less estimated Western Canadian refinery crude oil demand (excluding the Parkland Burnaby refinery) of 549 kb/d. 11 The total capacity of all of the non-Enbridge Mainline export pipelines, including Keystone XL and TMEP, is about 2,800 kb/d.
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Comparison of Contract Capacity to Net Supply
7,000
6,000
5,000 4,000
kb/d 3,000
2,000
1,000
0
Enbridge To Rockies Keystone/Keystone XL Trans Mountain Net CAPP Supply SOURCE: CAPP, Muse, CER
4.7. In this scenario, as illustrated in Table 7 below and outlined in the red box, the Edmonton heavy crude oil price increases to at least $42.06/barrel, i.e., the contract rate on Keystone.12 This represents a price increase of $4.79/barrel over the rail netback, and $0.71/barrel higher than the Keystone uncommitted toll netback. Table 7
ILLUSTRATION OF HEAVY CRUDE OIL NETBACKS
(U.S. Dollars per Barrel)
Uncommitted Tolls 20-Year Committed Tolls Enbridge Enbridge Rail Keystone Flanagan South Keystone Flanagan South
Crude Oil Price at Houston 55.00 55.00 55.00 55.00 55.00 Less Transportation Costs Rail loading fees 1.50 - - - - Railway fees 13.11 - - - - Tank car lease expenses 1.62 - - - - Rail unloading fees 1.50 - - - -
Enbridge Edmonton to Hardisty1 - 0.65 - 0.65 - Keystone - Canada1 - - - 2.07 - Keystone - U.S. - 13.00 - 10.22 - Flanagan South - - 10.21 - 7.96 Total Transportation 17.73 13.65 10.21 12.94 7.96
Edmonton Netback Price 37.27 41.35 44.79 42.06 47.04
Note: 1) Exchange Rate = CN$1.30 per US$1.00
12 Contract tolls for Keystone XL and the Trans Mountain Expansion Project are not shown in Table 6 because they are not known.
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4.8. In addition, for a shipper holding a volume commitment much of the contract toll is a sunk cost, because they are obligated to ship the barrel or pay for it anyway.13 Accordingly, the contract shipper has an incentive to ship even when the crude oil price difference, or arbitrage, between the Gulf Coast and Edmonton is less than the contract toll. For example, if a take-or-pay contract toll is $12.00/barrel and the Gulf Coast crude oil price is only $8.00/barrel over the Edmonton price, then the contract shipper is notionally “losing” $4.00/barrel, i.e., $12.00/barrel less $8.00/barrel. However, if they do not ship at all, then they are losing $12.00/barrel, since this amount must be paid irrespective if they ship or not. Consequently, the price difference between the Gulf Coast and Edmonton can narrow to something less than the contract toll, since the contract shipper will continue to ship when the available arbitrage does not fully cover the contract toll. This market dynamic can be expected to cease once all of the contract volume is fully utilized, and the price-setting mechanism reverts to the uncommitted pipeline toll.
SUMMARY OF ANALYTICAL CONCLUSIONS
4.9. When rail is acting to establish the price, implementation of Mainline Priority Access will not decrease the price of Western Canadian crude oil.
4.10. When uncommitted pipeline capacity is acting to establish the price, implementation of Mainline Priority Access will not decrease the price of Western Canadian crude oil.
4.11. Implementation of Mainline Priority Access has the potential to significantly increase Western Canadian crude oil prices for a period of time, because a discounted contract toll will be the price-setting mechanism whenever the total
13 The terms of the Transportation Services Agreements vary somewhat between the pipeline companies on the split between the fixed and variable components of the toll. On Flanagan South, over 90 percent of the contract toll is fixed, i.e., is a sunk cost, whereas on Keystone about 67 percent of the toll is fixed.
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export pipeline contract capacity exceeds the crude oil volume that must be shipped by pipeline.
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5. OVERVIEW OF TRANSPORTATION OPTIONS
INTRODUCTION
5.1. The general objective of this section is to provide information concerning the transportation options available to export Western Canadian crude oil. Export pipeline and rail transportation capacities are provided plus demand estimates for refineries located in Western Canada. Finally, the current apportionment levels on the Keystone and Trans Mountain Pipelines are shown.
WESTERN CANADIAN REFINERY DEMAND
5.2. Through the end of October 2019, total refinery demand in British Columbia, Alberta, and Saskatchwan was 598.9 kb/d.14 Included in the refinery category is the Northwest Redwater Sturgeon facility in the Edmonton area with an estimated capacity of 80 kb/d of heavy crude oil. Of the refineries in these three provinces, only the Parkland Burnaby refinery is supplied by one of the export pipelines (Trans Mountain), and crude oil deliveries to the Burnaby refinery were 49.6 kb/d in 2018.15 Consequently, Western Canadian crude oil runs (exclusive of Burnaby) in 2018 were 549.3 kb/d.
EXPORT PIPELINE CAPACITY
5.3. Trans Mountain Pipeline – Owned by the Trans Mountain Corporation, which is a wholly-owned subsidiary of the Canada Development Investment Corporation. The Trans Mountain Pipeline originates at Edmonton and terminates in Burnaby, in the Vancouver area, where it can load tankers at the Westridge dock or interconnect with the Puget Sound Pipeline to supply U.S. refineries in Washington state. The Westridge dock and the Puget Sound Pipeline are also
14 The data source is the CER Weekly Regional Report. 15 The data source is the CER Pipeline System Portal.
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owned by the Trans Mountain Corporation. The pipeline also transports refined product to Kamloops and Burnaby.
5.4. Figure 9 shows the historical throughput of light and heavy crude oil on Trans Mountain to three locations: Burnaby; the Westridge dock; and Sumas, which is the interconnection point with the Puget Sound Pipeline.16 The Burnaby deliveries are either light crude oil to the Parkland (formerly Chevron) Burnaby refinery or refined product to a third-party refined product terminal. In 2018, total Trans Mountain Pipeline throughput averaged 290.5 kb/d, including 27.8 kb/d of refined product shipments.
5.5. TMEP – Trans Mountain is currently engaged in expanding its capacity with the TMEP. The TMEP will add a second pipe to increase the total system capacity to 890 kb/d. The Westridge dock capacity is also being expanded to 625 kb/d.
Figure 9
Trans Mountain Throughput 400 350 Refined Product to Burnaby 300 250 Light Crude Export via Westridge 200 kb/d Light Crude Export via Sumas 150 100 Light crude to Burnaby 50 0 Heavy Crude Export via Westridge
Jul-15 Jul-16 Jul-17 Jul-18 Jul-19 Apr-15 Oct-15 Apr-16 Oct-16 Apr-17 Oct-17 Apr-18 Oct-18 Apr-19 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Heavy Crude Export via Sumas SOURCE:CER
5.6. Keystone Pipeline – Owned by TC Energy, the Keystone Pipeline originates at Hardisty with delivery points in southern Illinois (Wood River and Patoka),
16 The Trans Mountain Pipeline makes refined product deliveries at Kamloops which are not shown on Figure 9, and also receives small volumes of crude oil at Kamloops. The data source for Figure 9 is the CER Pipeline System Portal.
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Cushing, and Beaumont and Houston on the Gulf Coast. Originally built to just southern Illinois, TC Energy (then TransCanada) added a connection originating at Steele City, Nebraska, and terminating at Cushing (the “Cushing Extension”) followed by southern extension to the Gulf Coast from Cushing (the “Cushing Marketlink”). These two later pipeline segments were sized to accommodate the proposed Keystone XL Pipeline. The capacity of the Keystone Pipeline is 591 kb/d. The pipeline does not transport refined products. Figure 10 displays the Keystone Pipeline throughput at the border since January 2015. In 2018, total crude oil throughput on the Keystone Pipeline averaged 588.9 kb/d.
Figure 10
Keystone Throughput 700 600 500 400
kb/d 300
200 100
0
Jul-15 Jul-16 Jul-17 Jul-18 Jul-19 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Mar-15 Mar-16 Mar-17 Mar-18 Mar-19 Sep-15 Nov-15 Sep-16 Nov-16 Sep-17 Nov-17 Sep-18 Nov-18 Sep-19 May-15 May-16 May-17 May-18 May-19 Heavy Crude Light Crude SOURCE:CER
5.7. Keystone XL Pipeline – The proposed Keystone XL Pipeline will originate at Hardisty and terminate at Steele City, Nebraska. At this point, it will tie into the existing Keystone Pipeline segment between Steele City and Cushing, with onward connectivity to the Gulf Coast via the Cushing Marketlink segment. The indicated crude oil capacity Keystone XL Pipeline is 830 kb/d, with the existing Keystone Pipeline capacity remaining at 591 kb/d.
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5.8. A closely related project also sponsored by TC Energy is the Heartland Pipeline. This pipeline would connect Edmonton to Hardisty with a crude oil capacity of approximately 900 kb/d. The project was approved by the Alberta Energy Regulator (the “AER”) in 2015. However, TC Energy has deferred the project due to market conditions, and has requested and received two license extensions from the AER. The most recent extension for one year was received on February 4, 2019.
5.9. Export Pipelines to Rockies – There are three pipelines that transport crude oil from Alberta south into the Rockies with an estimated aggregate capacity of 510 kb/d. These are:
5.9.1. Express Pipeline – Originates at Hardisty and terminates at Casper, Wyoming. At this location it is connected to the Platte Pipe Line as well as local pipelines. The Platte Pipe Line terminates at Wood River, located in southern Illinois. The current Express Pipeline capacity is approximately 280 kb/d, and Enbridge expects to complete an expansion of the Express Pipeline to 310 kb/d by mid-year 2020.
5.9.2. Milk River Pipeline – The primary receipt point is an interconnection in southern Alberta with the Bow River Pipeline. The Milk River Pipeline delivery point is at the Canadian/U.S. border with the Front Range Pipeline, which supplies crude oil to several refineries in Montana. The capacity of the Milk River Pipeline is estimated to be 100 kb/d.
5.9.3. Rangeland Pipeline – Owned by Plains Midstream Canada, the Rangeland Pipeline collects light crude oil in Alberta for transportation to Edmonton and to an interconnection with the Glacier Pipeline at the border.17 Current capacity of the Rangeland Pipeline to the border is estimated to be 45 kb/d. On July 8, 2019, Plains Midstream Canada announced that it is proposing an expansion of the Rangeland Pipeline to
17 The 0.75 km section of the Rangeland Pipeline immediately north of the border is under CER regulation, and it is called the Aurora Pipeline.
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increase the delivery capacity to the border to up to 100 kb/d, i.e., an expansion of 55 kb/d.18
5.9.4. Wascana Pipeline – Owned by Plains Midstream Canada, the Wascana Pipeline is bi-directional and connects Regina to the U.S. border in Saskatchewan. At the border, there is an interconnection to the Plains Pipeline Montana. The current capacity of the pipeline is estimated to be 40 kb/d, and it is further understood to be currently operating in a southbound direction.
RAIL EXPORT CAPACITY
5.10. Table 8 below displays the installed capacity to load crude oil onto rail cars in Western Canada.19 The current rail loading capacity exceeds 1,100 kb/d. The EIA reported that crude oil imports via rail from Canada in July 2019 were 366 kb/d. There are additional rail shipments within Canada that are not captured by the EIA data.
18 Plains Midstream Canada News Release, July 8, 2019. 19 The information source is the CAPP 2019 Crude Oil Forecast, Markets and Transportation Report, Table 4.3, pg. 29.
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Table 8
RAIL UPLOADING TERMINALS IN WESTERN CANADA
(Barrels per Day)
Operator Location Capacity Comments
Alberta Kinder Morgan/Imperial Sherwood Park 210,000 Operating since Jul 2014 Gibson/USD Group Hardisty 225,000 Expansion operating since Sept 2014 Cenovus Bruderheim 100,000 Operating since April 2015 Keyera/Kinder Morgan Edmonton 40,000 Operating since Sept 2014 Altex Lynton 27,000 Operating Savage Reno 25,000 Operating since Q2 2014 Keyera/Enbridge Cheecham 24,000 Operating since Oct 2013 Gibson/USD Group Edmonton 42,500 Operating since Q3 2015 Secure/Predator High Prairie 19,000 Operating since Q3 2015 Subtotal 712,500
Saskatchewan Plains Kerrobert 70,000 Startup Nov 2015 but suspended since May 2016 as facilities were underutilized. Re-started in 2018 Altex Lashburn 88,000 Expanded capacity op. since 2015 Crescent Point Stoughton (45,000) Suspended facility account to Gov't of SK TORQ Transloading Unity 79,000 Operating since Mar 2012 Altex Unity 29,000 Operating since Jul 2012 TORQ Transloading Lloydminster 24,200 Operating since March 2012 TORQ Transloading Bromhead 45,300 Operating since Jul 2013 Subtotal 335,500
Manitoba Tundra Cromer 60,000 Expansion operating since Q4 2014 Subtotal 60,000
Total 1,108,000
SOURCE:Source: CAPP CAPP Notes: 1. Facilities with less than 15,000 b/d are not shown. 2. Estimated capacities based on assumptions for operating hours, available car spots, type of crude oil transported, and contracts in place (if known.)
KEYSTONE AND TRANS MOUNTAIN APPORTIONMENT
5.11. The apportionment data for the Keystone and Trans Mountain Pipelines are obtained from the CER Pipeline System Portal, and are provided below on Figures 11 and 12, respectively. The Trans Mountain Pipeline has been in
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apportionment for a number of years, and the Keystone Pipeline generally has been in apportionment since 2016.
Figure 11 Keystone Apportionment
100% 90% 80% 70% 60% 50% 40% 30% 20%
Percent Apportionment 10% 0%
SOURCE: CER
Figure 12
Trans Mountain Apportionment 100% 90% 80% 70% 60% 50% 40% 30% 20%
Percent Apportionment 10% 0%
SOURCE: CER
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APPENDIX A MARKET REGIONS CONNECTED TO ENBRIDGE
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APPENDIX B SUPPLY VERSUS EXPORT PIPELINE CAPACITY
COMPARISON OF PIPELINE CONTACT CAPACITY AND EXPORT VOLUME KXL AND TMEP WITH MAINLINE PRIORITY ACCESS (Barrels per Calendar Day, Unless Noted)
Year 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Western Canadian Supply CAPP Western Canadian Supply 5,226.2 5,297.2 5,383.5 5,471.7 5,581.2 5,665.8 5,753.0 5,782.7 5,866.7 5,949.5 6,023.1 6,139.3 6,254.0 6,335.6 Less Western Canadian Demand (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) (549.3) Less Rail ------Net Supply to Pipeline 4,676.9 4,747.9 4,834.2 4,922.4 5,031.9 5,116.5 5,203.7 5,233.4 5,317.4 5,400.2 5,473.7 5,589.9 5,704.7 5,786.3
Canadian Export Pipelines Total Capacity Enbridge Mainline (Gretna) 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 3,084.0 Express, Milk River, Rangeland, Wascana 540.0 540.0 540.0 540.0 540.0 540.0 540.0 540.0 540.0 540.0 540.0 540.0 540.0 540.0 Keystone 641.0 641.0 641.0 641.0 641.0 641.0 641.0 641.0 641.0 641.0 641.0 641.0 641.0 641.0 Keystone XL 830.0 830.0 830.0 830.0 830.0 830.0 830.0 830.0 830.0 830.0 830.0 830.0 830.0 830.0 Trans Mountain 840.0 840.0 840.0 840.0 840.0 840.0 840.0 840.0 840.0 840.0 840.0 840.0 840.0 840.0 Total 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0 5,935.0
Contract Capacity Enbridge Mainline (Gretna) 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 2,760.0 Express, Milk River, Rangeland, Wascana 335.0 335.0 335.0 335.0 335.0 335.0 335.0 335.0 335.0 335.0 335.0 335.0 335.0 335.0 Keystone 450.0 450.0 450.0 450.0 450.0 450.0 450.0 450.0 450.0 450.0 450.0 450.0 450.0 450.0 Keystone XL 750.0 750.0 750.0 750.0 750.0 750.0 750.0 750.0 750.0 750.0 750.0 750.0 750.0 750.0 Trans Mountain 672.5 672.5 672.5 672.5 672.5 672.5 672.5 672.5 672.5 672.5 672.5 672.5 672.5 672.5 Total 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 4,967.5 Unused Contract Capacity 290.6 219.6 133.3 45.1 ------
Total Available Capacity 1,258.1 1,187.1 1,100.8 1,012.6 903.1 818.5 731.3 701.6 617.6 534.8 461.3 345.1 230.3 148.7
Muse, Stancil & Co. November 2019
SOURCES: CAPP Western Canadian Supply: CAPP 2019 Crude Oil Forecast, Markets and Transportation, Appendix A2 Western Canadian Crude Demand: Muse calculation, subtracting Trans Mountain crude oil deliveries to Burnaby per CER Pipeline System Portal from total Western Canadian crude oil runs per CER. Contract Capacities: Enbridge Mainline: Open Season Procedures, pg. 13. Express, Milk River, Rangeland, and Wascana: Enbridge and Muse estimates. Keystone (Combined): TransCanada Investor Day presentation, November 13, 2018, PDF pg. 65. Trans Mountain: Application by Trans Mountain for Approval of the Trans Mountain Expansion Project, December 2013, Volume 1, pg. 1-2. Of the total volume commitment of 707.5 kb/d, Muse has assumed that 35 kb/d would be utilized for refined product transportation.
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APPENDIX C EVOLUTION OF REFINERY OWNERSHIP
Refinery Ownership By Company ― 2000 3,500 35 3,000 30 2,500 25 2,000 20 1,500 15 1,000 10 500 5 Number Number Refineries of
Crude Oil Capacity, kb/d 0 0
Crude Oil Capacity Number of Refineries SOURCE: EIA
Refinery Ownership By Company ― 2010 3,500 35 3,000 30 2,500 25 2,000 20 1,500 15
1,000 10 500 5 Number of Refineries
Crude Oil Capacity, kb/d 0 0
Crude Oil Capacity Number of Refineries SOURCE: EIA
Refinery Ownership By Company ― 2019 3,500 35 3,000 30 2,500 25 2,000 20 1,500 15 1,000 10 500 5 Number of Refineries 0 0 kb/d Capacity, Oil Crude
Crude Oil Capacity Number of Refineries
SOURCE: EIA . Page 35
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APPENDIX D CURRICULUM VITAE – NEIL K. EARNEST
SUMMARY OF EXPERIENCE:
Mr. Earnest has over 35 years of experience focused on the downstream sector of the energy business, and has played key roles in major international arbitrations, multi- billion-dollar downstream asset acquisitions, and Canadian crude marketing and upgrading programs totaling hundreds of thousands of barrels per day. As a consultant, he has worked on a broad range of assignments around the world with an emphasis on asset acquisition and divestitures, crude and refined product marketing analyses, expert testimony in support for highly complex arbitrations and major pipeline projects, and project feasibility assessment. Mr. Earnest began his career at Phillips Petroleum Company, where he spent 11 years in a variety of roles at Phillips’ largest refinery and petrochemical plant and in corporate planning/engineering. Mr. Earnest is currently the President of Muse.
REPRESENTATIVE CONSULTING EXPERIENCE:
Asset Acquisition and Divestitures
Mr. Earnest has frequently headed Muse’s teams that have assisted clients contemplating downstream acquisitions or divestitures. Over the years, dozens of detailed valuations of North American refineries for a variety of clients have been completed. Representative engagements follow:
1. Provided a detailed technical and economic assessment of the range of options available to a Canadian heavy crude producer commencing a downstream integration strategy. Assistance included board-level presentations and assistance negotiating the purchase-sales agreements and the joint-venture operating agreements.
2. Developed a detailed valuation of the combined sales value of the European downstream assets of a major oil company. Included projecting refinery cash flow considering the evolving environmental, product demand, and product specification issues in Europe.
3. Provided economic, technical, and LP modeling assistance to a corporate team considering entry into the Asia-Pacific refining industry.
4. Conducted due diligence of, and assessed the potential for, investment in four state-owned African refineries.
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5. Assisted a U.S. client considering the merger of their refining assets with another refiner. The assistance included an assessment of the competitive position of the potential merger partner and potential synergies.
Market, Strategic, and Competitive Analysis
Have provided a broad range of market and competitive analyses in support of client strategy objectives. Clients include pipeline companies, refiners, and crude producers. Representative examples include:
1. Assisted a number of Canadian crude producers with their long-range investment and market development strategies, including detailed market and potential customer assessments, for their synthetic and heavy sour crude programs.
2. For several refiner clients, provided a detailed assessment of their refinery competitive position versus domestic and foreign competition.
3. Generated a detailed assessment, considering multiple market scenarios, of the expected prices for a range of potential synthetic crude formulations that was instrumental in finalizing the design basis for a multi-billion-dollar Canadian oil sands upgrader.
4. Provided the market analysis in support of a new proposed product pipeline in the Rockies.
5. Assisted several clients with quantifying the value of their equity crude to specific purchasers. The purchasers were either being considered for term contracts or were large volume buyers.
6. Provided the Government of Alberta, Ministry of Energy, detailed analysis of the technical attributes, from the refiner’s perspective, of extra-heavy crude oil blends as well as an assessment of their value in potential markets.
Project Feasibility and Technology Assessment
Representative project and technology assessment analyses include:
1. Provided a detailed assessment of the value of a biomass-sourced, partially upgraded feedstock to the refining industry on behalf of the biofuel manufacturer. This assistance included extensive analysis of the suitability and value of the individual fractional components of the bio- feedstock to the typical Gulf Coast refiner, and assessing the economic benefits to the biofuel manufacturer of adding additional desulfurization
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and hydrogen-addition process technologies. The client ultimately constructed a commercial-scale plant.
2. Provided a detailed technical and economic assessment of a heavy crude partial upgrading technology on behalf of a potential investor in the technology company. Later acted as the independent engineer to certify the performance tests for the commercial demonstration plant. The certification was one of the pre-conditions for the sale of the technology company to the investor.
3. Provided a technology assessment of six extra-heavy crude oil partial- upgrading technologies. The technologies ranged from variations on fairly conventional refinery process technologies to super-critical water cracking schemes and sodium-based desulfurization technologies. The engagement included a ranking of the technologies on an economic, technical feasibility, and readiness for commercialization basis.
4. Assisted a major Canadian heavy crude oil producer with the selection of the process technology for the conversion of extra-heavy crude oil to light synthetic crude oil. The engagement included the detailed technical and economic assessment of competing process technologies.
5. In-depth evaluation of resid upgrading options for a large Middle East refinery. The assistance included the detailed LP modeling of the alternatives.
6. Assisted a South American client with process optimization in connection with a major upgrade of their lube manufacturing facilities.
7. Performed the detailed technical and economic analysis of the overall merits of constructing a new resid FCC unit on behalf of a South American refiner.
Expert Testimony
1. Private Arbitration (1998): Koch Shipping Inc., Koch Supply & Trading Company, and Koch Refining Company, L.P. v. Mobil Shipping and Transportation Company.
2. Provided expert report, in 2006, on behalf of Enbridge Pipelines regarding the market demand for Canadian crude oils and quantified the benefits that would flow to Illinois and other U.S. consumers regarding the Southern Access Pipeline. Report filed with the Illinois Commerce Commission.
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3. Provided expert report and direct testimony before the National Energy Board (Canada) regarding the Southern Lights Project, on behalf of Enbridge Pipelines, Inc., with hearings held in Calgary, Alberta, in 2007.
4. Expert report and direct testimony before the National Energy Board (Canada) regarding the Alberta Clipper Project, on behalf of Enbridge Pipelines, Inc., with hearings held in Calgary, Alberta, in 2007.
5. Provided expert report, in 2007, on behalf of Enbridge Pipelines to the National Energy Board (Canada) regarding the crude supply and demand for Ontario and Montréal refineries.
6. Provided expert reports, in 2007, to the U.S. Federal Energy Regulatory Commission on behalf of Enbridge Pipelines regarding the expected utilization of the Southern Access Extension pipeline, as well as other non- rate shipper benefits that ensued from the commissioning of the pipeline. Also provided written affidavit in response to intervener’s expert.
7. Provided direct testimony, in 2008, before the Minnesota Public Utilities Commission regarding the Alberta Clipper Project, on behalf of Enbridge Pipelines, Inc.
8. Direct testimony, in February 2008, before the International Court of Arbitration, with hearings held in Zurich, Switzerland, on behalf of Louis Dreyfus S.A.S. (Respondent) against Ronald W. de Ruuk, as Bankruptcy Administrator for Holding Tusculum B.V., (Claimant). Testifying expert at hearings on behalf of the respondent regarding the value of the Wilhelmshaven, Germany, refinery. Also, co-authored valuation report and responses to claimant’s experts.
9. Provided expert report, in May 2009, and oral testimony to the International Court of Arbitration on behalf of Mobil Cerro Negro, Ltd (Claimant) against Petroleos de Venezuela, SA regarding the expropriation of assets.
10. Expert report and direct testimony before the National Energy Board (Canada) regarding the Keystone XL Project, on behalf of Enbridge Pipelines, Inc., with hearings held in Calgary, Alberta, in 2009.
11. Provided expert and reply report, in 2009, on behalf of Enbridge Pipelines to the National Energy Board (Canada) regarding the medium-term prospects for Line 9 in westbound service.
12. Provided expert and reply reports, in 2010 and 2011, to the International Centre for Settlement of Investment Disputes on behalf of Venezuelan Holdings B.V., et.al. (Claimant) against the Bolivarian Republic of
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Venezuela, and oral testimony at the hearing held in Paris in 2012 regarding the expropriation of assets.
13. Provided expert oral testimony in 2011 on behalf of Enbridge Inc. to the National Energy Board (Canada) regarding the Southern Lights Pipeline.
14. Provided expert report, in 2011, on behalf of Enbridge Bakken Pipeline Company to the National Energy Board (Canada) regarding the market prospects for North Dakota crude oil.
15. Submitted export report in January 2012 to the Michigan Public Service Commission regarding the public need and local economic benefits of Enbridge Line 17, on behalf of Enbridge Pipelines (Toledo) Inc.
16. In 2011, submitted expert and rebuttal reports to the U.S. Federal Energy Regulatory Commission on behalf of Enbridge Pipelines regarding the Southern Lights Pipeline followed by oral testimony at the hearing in Washington, D.C., in 2012.
17. Provided expert and rebuttal reports to the Joint Review Panel (Canada) regarding the Northern Gateway Pipeline project, followed by oral testimony at hearing held in Edmonton, Alberta in September 2012, on behalf of the Northern Gateway Pipeline.
18. Provided expert report to the National Energy Board (Canada) regarding the market prospects for the Enbridge Edmonton-to-Hardisty pipeline project in November 2012, followed by direct testimony in October 2013, on behalf of Enbridge Pipelines.
19. Provided expert report, rebuttal, and surrebuttal testimony in 2013 and 2014 before the Minnesota Public Utilities Commission regarding the Line 67 Station Expansion Project – Phase 2, on behalf of Enbridge Pipelines, Inc.
20. Provided expert report and rebuttal testimony in 2014 to the U.S. Federal Energy Regulatory Commission on behalf of North Dakota Pipeline Company LLC regarding the Sandpiper pipeline.
21. In June 2014, provided written and oral expert testimony in the English High Court of Justice – Commercial Court, on behalf of Innospec Inc. versus Jalal Bezee Mejel Al-Gaood & Partner regarding issues in the Iraqi refining sector.
22. Provided expert and rebuttal testimony to the National Energy Board (Canada) regarding Trans Mountain Pipeline nomination verification procedures in 2014, on behalf of Tesoro Canada.
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23. Provided expert reports and oral testimony in August 2014 through January 2015 before the Minnesota Public Utilities Commission regarding the Sandpiper Pipeline Project on behalf of North Dakota Pipeline Company LLC.
24. Provided expert report and rebuttal report, followed by oral testimony at trial in February, 2016, in the U.S. District Court for the Central District of California, on behalf of Southern California Edison Company versus ExxonMobil Oil Corporation. The dispute concerned an electrical outage at a refinery.
25. Provided reply report in October 2014, followed by oral testimony in February 2017, to the International Centre for Settlement of Investment Disputes on behalf of ConocoPhillips Petrozuata B.V., et.al. (Claimant) against the Bolivarian Republic of Venezuela regarding the expropriation of assets.
26. Provided an expert report in November 2014 to the National Energy Board (Canada) regarding the expected utilization of the Enbridge Mainline for the Enbridge Line 3 Replacement Program.
27. Provided expert report and oral testimony in June and December, 2015 to the ICC International Court of Arbitration on behalf of Wallis Trading Inc. versus SGS Societe Generale de Surveillance SA for a case regarding issues relating to a collateral management agreement at an Albanian storage facility.
28. Provided expert report in September 2015 to the National Energy Board (Canada) regarding the expected utilization of and the Canadian crude oil producer benefits from the Trans Mountain Expansion Project.
29. Provided expert report to the U.S. Federal Energy Regulatory Commission in November 2015 on behalf of Colonial Pipeline Company regarding revisions to its Rules and Regulations tariff.
30. Provided an expert report and oral testimony in May and December 2016 to the ICC International Court of Arbitration on behalf of ConocoPhillips Petrozuata B.V., et.al. (Claimant) versus Petróleos de Venezuala, S.A. regarding the expropriation of assets.
31. Provided an expert report in August 2017 in the U.S. District Court for Montana, on behalf of Northwestern Energy versus ExxonMobil Oil Corporation. The dispute concerned an electrical outage at a refinery.
32. Provided expert, rebuttal, surrebuttal, and supplemental surrebuttal reports in 2015 and 2017, followed by oral testimony, to the Minnesota
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Public Utilities Commission regarding the utilization and market impact of the Enbridge Mainline for the Enbridge Line 3 Replacement Program, on behalf of Enbridge Pipelines, Inc.
33. Provided expert and rebuttal reports in 2017 to an AAA Arbitration proceeding on behalf of NARL Refining Limited Partnership versus BP Products North America regarding technical and economic issues related to a crude oil toll processing contract.
34. Provided an expert report, reply report, and oral testimony in 2017-2019 to the ICC International Court of Arbitration on behalf of the Republic of Turkey versus the Republic of Iraq regarding a dispute concerning Kurdish crude oil exports.
35. Provided an expert report in 2018 to the ICC International Court of Arbitration on behalf of Phillips 66 Company versus PDVSA. The dispute concerns the appropriate valuation methodology for a Venezuelan heavy sour crude oil.
36. In 2019, provided an expert and reply report in a private expert proceeding regarding the appropriate protocol to value the crude oils shipped on a North Sea crude oil pipeline. The parties involved included a number of North Sea crude oil producers.
37. In 2019, provided an expert report in the Superior Court of the State of Washington on behalf of the City of Tacoma, Washington – Department of Public Utilities versus U.S. Oil & Refining. The dispute concerned an electrical outage at a refinery.
38. In 2019, provided an expert report in the High Court of Justice Business and Commercial Courts of England and Wales – Commercial Court on behalf of JSC Antipinsky Refinery versus VTB Commodities Trading DAC. The dispute concerned a toll processing agreement at the Antipinsky refinery.
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WORK EXPERIENCE:
Muse, Stancil & Co. 1991 - Present Current Position: President
Phillips Petroleum Company 1981-1991 Positions: Process Senior Engineer Economics Engineer Staff Process Engineer
EDUCATION: B.S. Chemical Engineering - 1981 Michigan State University M.B.A. - 1986 University of Houston – Clear Lake
PROFESSIONAL REGISTRATION: Chemical Engineer, Texas, #75398
PUBLICATIONS/PRESENTATIONS:
1. “Refinery-Profitability Statistics Begin” Oil & Gas Journal January 2001
2. “Canadian Crude Market Outlook” Alberta Department of Energy Workshop #2 March 2002
3. “View from the Market: The Refiner’s Perspective” CERI 2003 World Oil Conference January 2003
4. “Traditional Markets and New Opportunities” CERI 2004 World Oil Conference March 2004
5. “Independent Views on Markets for Oil Sands and Pipeline Capacity” TD Newcrest Oil Sands Forum 2004 July 2004
6. “Independent Views of Markets for Oil Sands and Pipeline Capacity” 2004 National Petrochemical & Refiners Association July 2004
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7. “The Canadian Crude Market” 2005 Canadian Crude Oil Conference September 2005
8. “The Canadian Crude Market” 3rd Annual Canadian Oil Sands Summit January 2006
9. “Bigger is Better” 4th Annual Oil Sands Forum – Oil Sands Market Overview July 2006
10. “U.S. Market for Canadian Crude – Oil Sands Market Overview” Crude Oil Quality Group General Meeting November 2006
11. “Future Markets for Canadian Crude” 4th Annual Canadian Oil Sands Summit January 2007
12. “Canadian Crude Market Outlook” 3rd Annual Enbridge Mid-Continent Shippers Conference January 2007
13. “New Market Outlook for Canadian Crude” 42nd Annual Enbridge Jasper Conference June 2007
14. “Canadian Oil Market – Opportunities and Challenges” 5th Annual Canadian Oil Sands Summit January 2008
15. “Canadian Crude Market and Outlook” Argus US/Canada Asphalt Conference 2008 April 2008
16. “Oil Sands Integration with the U.S. Market – A Revised Perspective” 20th Annual Canadian Crude Oil Conference September 2008
17. “The Economy and Oil Demand: Where are They Taking the Oil Market?” CERI 2009 Oil Conference April 2009
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18. “Oil Sands Integration with the Global Markets – A Revised Perspective” TD Newcrest London Oil Sands Forum 2009 January 2009
19. “Oil Sands Integration with the Global Markets” TD Newcrest Canadian Unconventional Oil Forum 2009 July 2009
20. “Implications of Expanding Canadian Pipeline Infrastructure” Argus Americas Crude Summit 2010 January 2010
21. “Counter-Party Risk” TD Newcrest – Unconventional Oil & Gas Forum July 2010
22. “U.S. Downstream in the New Economic Reality” Annual Canadian Crude Oil Conference September 2010
23. “The Road to Recovery” Argus 4th Annual Americas Asphalt Summit March 2011
24. “Crack Spreads are Back: Which PADDs Stand to Benefit and How Long Will It Last?” TD Securities – Unconventional Energy Conference TD Newcrest – 2011 Calgary Unconventional Energy Conference July 2011
25. “Overall Market Landscape for Canadian Crude Oil” Argus – Americas Crude Summit 2012 January 2012
26. “Canadian Crude Landscape and Market Expansion Prospects” Argus – Americas Asphalt Summit 2012 March 2012
27. “The Changing Crude Supply Landscape – The Refiner’s Perspective” TD Securities July 2012
28. “Rail vs. Pipeline: What Projects are Being Developed to Accommodate Growing Shale Crude Production?” Argus Americas Crude Summit January 2013
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29. “Implications of the North American Oil Renaissance” American Fuel & Petrochemical Manufacturers January 2013
30. “Implications of the Evolving North American Crude Supply Outlook” TD Securities – 2013 TD Calgary Energy Conference July 2013
31. “Implications of the Evolving North American Crude Supply Outlook” AICHE –5th Southwest Process Technology Conference October 2013
32. “Renaissance of the North American Energy Sector” Lloyds Register – Energy Conference October 2013
33. “Changing Topography of U.S. Crude” Argus – Americas Crude Summit 2014 January 2014
34. “Canadian Tidewater Access – Implications for the U.S.” American Fuels & Petrochemical Manufacturers Annual Meeting 2014 March 2014
35. “Dealing with an Oversupply of Light Crudes in a World of Heavy Crude Refineries” Canadian Energy Research Institute 2014 Oil Conference April 2014
36. “Update on Market Access by Pipeline” Argus Canadian Crude Summit 2015 June 9, 2015
37. “North American Crude Market Outlook” Enbridge 50th Annual Liquids Pipelines Conference 2015 June 11, 2015
38. “Crude Oil Market Dynamics for 2016” Canadian Heavy Oil Association Annual Luncheon January 7, 2016
39. “Survival Outlook for Canadian Oil” 8th Argus Americas Crude Summit January 21, 2016
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40. “Light Transportation Fuels – Supply-Demand Outlook and Implications for Logistical Infrastructure” Argus Americas Motor Fuels Summit January 17, 2018
41. “Headwinds for the Russian Refining Industry” IP Week Conference – Re-Engineering the Oil and Gas Operating Models: An Industry in Transition February 22, 2018
42. North American Shale and Heavy Barrel Competition – The Latin American Competition Argus Canadian Crude Summit May 1, 2018
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