Gowling Lafleur Henderson LLP, on Behalf of Valero Energy Inc. And

OUTLOOK FOR ENBRIDGE LINE 9 RE-REVERSAL IMPACT ON QUEBEC REFINERIES

Prepared for:

Gowling Lafleur Henderson LLP, On Behalf of Valero Energy Inc.

and

Bennett Jones LLP, On Behalf of Suncor Energy Marketing Inc.

Prepared by:

IHS Global Canada Limited

July 2013 Steven J. Kelly

The accompanying materials were prepared by IHS. Content distributed or reprinted must display IHS’ legal notices and attribu tions of authorship. IHS provides the materials “as is” and does not guarantee or warrant the correctness, completeness or correctness, merchantability, or fitness for a particular purpose. All warranties of which are hereby expressly disclaimed and negated. To the extent permissible under the governing law, in no event will IHS be liable for any direct, indirect, special, incidental, lost profit, lost royalties, lost data, punitive, and/or consequential damages, even if advised of the possibility of same. ©2013 IHS.

C10016/smu

Gowlings / Bennett Jones Table of Contents -- i

TABLE OF CONTENTS

INTRODUCTION ...... 7 SUMMARY OF CONCLUSIONS ...... 8 REFINING INDUSTRY BACKGROUND ...... 9 EASTERN CANADA REFINING MARKETS ...... 11 NORTH AMERICAN CRUDE SUPPLY, DEMAND AND PRICING ANALYSIS ...... 18 IMPACT OF THE PROJECT ON QUEBEC REFINERIES ...... 25

APPENDIX A: ...... 32 CRUDE SOURCING AND SUPPLY OPTIMIZATION ...... 32 PARITY PRICING CONCEPTS ...... 33 THE INVESTMENT PROCESS ...... 34

APPENDIX B: ...... 36 TABLES ...... 36

APPENDIX C: ...... 42 DATA TABLES ...... 42

APPENDIX D: RESUME OF PROFESSIONAL QUALIFICATIONS STEVEN J. KELLY...... 46

LIST OF FIGURES

FIGURE 1 QUEBEC CRUDE SLATE ...... 11 FIGURE 2 QUEBEC CRUDE SOURCES ...... 12 FIGURE 3 QUEBEC CRUDE IMPORT SOURCES ...... 12 FIGURE 4 ONTARIO CRUDE SLATE ...... 15 FIGURE 5 ATLANTIC CANADA CRUDE SLATE ...... 16 FIGURE 6 PADD I CRUDE SLATE ...... 17 FIGURE 7 CAPP WESTERN CANADA TOTAL CRUDE SUPPLY FORECAST SCENARIO COMPARISON ...... 19 FIGURE 8 WILLISTON BASIN CRUDE PRODUCTION FORECAST COMPARISON ... 20 FIGURE 9 CRUDE OIL PRICE FORECAST ...... 21 FIGURE 10 WTI, CUSHING – BRENT, FOB ...... 22 FIGURE 11 BONNY LIGHT – MSW (QUALITY ADJUSTED) ...... 28

LIST OF TABLES

TABLE 1 REFINERY CAPACITY: JANUARY 2013 ...... 37 TABLE 2 MAJOR PIPELINE PROJECTS CONNECTING OIL SANDS TO FUTURE MARKETS ...... 38 TABLE 3 CRUDE OIL DELIVERY COSTS TO MONTREAL AND QUEBEC CITY (CURRENT U.S. DOLLARS) ...... 39 TABLE 4 CRUDE OIL DELIVERY COSTS TO MONTREAL AND QUEBEC CITY (CONSTANT U.S. DOLLARS) ...... 40

ABBREVIATIONS AND ACRONYMS

B/D Barrels per Day

CAPP Canadian Association of Petroleum Producers

CIF Cost, Insurance and Freight

ECA Emission Control Areas

EIA Energy Information Administration

FCC Fluid Catalytic Cracking

FOB Free on Board

IMO International Maritime Organization

LPG Liquefied Petroleum Gases

MSW Alberta Mixed Sweet crude

NDPA North Dakota Pipeline Authority

NEB National Energy Board

NGL Natural Gas Liquid

OPEC Organization of the Petroleum Exporting Countries

PADD Petroleum Administration for Defense District

PGI Purvin & Gertz, Inc.

PMPL Portland-Montreal Pipe Line

RFO Residual Fuel Oil

SCO Synthetic Crude Oil

TAN Total Acid Number

TNPI Trans-Northern Pipelines Inc.

TSA Transportation Services Agreement

VGO Vacuum Gas Oil

WTI West Texas Intermediate

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1 INTRODUCTION

2 Q.1. Please state your full name, position and business address.

3 A.1. My name is Steven J. Kelly. I am a Vice President at IHS Global Canada Limited (“IHS”). 4 I direct the Downstream Energy Consulting operations at the IHS office in Calgary, 5 Alberta. Prior to IHS, I was Senior Vice President and Director at Purvin & Gertz Inc. 6 (“Purvin & Gertz” or “PGI”). IHS acquired PGI in November 2011. My current business 7 address is Suite 200, 1331 Macleod Trail S.E., Calgary, Alberta, T2G 0K3.

8 Q.2. Please describe your educational and professional background.

9 A.2. I graduated with a Bachelor of Engineering degree in Chemical Engineering from 10 McMaster University in Hamilton, Ontario in 1982. I obtained a Master of Engineering 11 degree in Chemical Engineering from McMaster University, with specialization in 12 process computer control in 1985, and a Master of Business Administration degree from 13 the University of Calgary in 1998. I worked as a process engineer at the Sarnia and 14 Scotford refineries of Shell Canada, and in a variety of operations and strategic planning 15 roles at Shell Canada’s Calgary head office. In 1996, I joined PGI’s Calgary office as an 16 Associate Consultant. I have worked at PGI (and IHS since November 2011) for a total 17 of 17 years, including a four-year posting in the Purvin & Gertz office in London, UK. 18 Much of my work at PGI/IHS has involved market studies for conventional crude oil, oil 19 sands and refined products in North America and Europe. I have prepared and provided 20 expert testimony on pipeline matters in Canada before the National Energy Board 21 (“NEB”). I am a Professional Engineer, registered in Alberta.

22 Q.3. Please describe IHS and its Energy Insight consulting operations.

23 A.3. IHS is a global information company that provides comprehensive content, insight and 24 expertise to business and government clients around the world. IHS has been providing 25 information, independent analysis and insight to its customers for more than 50 years. 26 IHS has been in business since 1959 and became a publicly traded company on the 27 New York Stock Exchange in 2005. The company is headquartered in Englewood, 28 Colorado, USA, and employs over 6,000 people in more than 30 countries around the 29 world. IHS Energy Insights Consulting offers industry and business advisory expertise 30 across the upstream, midstream, downstream, and chemicals segments of the energy 31 value chain.

1 Q.4. What is the purpose of your evidence in this proceeding?

2 A.4. On behalf of Valero Energy Inc. (“Valero”) and Suncor Energy Marketing Inc. (“SEMI”), 3 IHS has been engaged by Gowling Lafleur Henderson LLP (“Gowlings”) and Bennett 4 Jones LLP (“Bennett Jones”), respectively, to address various supply and market issues 5 related to the Enbridge Pipelines Inc. (“Enbridge”) pipeline facilities application 6 OH-002-2013, entitled the “Line 9B Reversal and Line 9 Capacity Expansion Project” 7 (“the Project”) to the NEB (“the Application”).

8 In this testimony, I will address the following matters:

9 1. A market study with respect to the configuration and historical crude oil supply to the 10 Quebec refineries;

11 2. Discussion of current and prospective supply and pricing situation for crude oil to the 12 Quebec refineries; and

13 3. Analysis of the impact of the Project on Quebec refineries

14 SUMMARY OF CONCLUSIONS

15 Q.5. Please summarize your conclusions.

16 A.5 IHS’ conclusions from this analysis are summarized below:

17 1. The refining industry in Quebec consists of two operating facilities; the Suncor 18 refinery in Montreal and the Valero refinery in Lévis, (collectively “the Quebec 19 Refineries”). The Quebec Refineries are subject to competitive pressure from other 20 refineries in Eastern North America, as well as from refined product trade originating 21 in other regions of the Atlantic Basin. The configurations of the Quebec Refineries 22 are of medium complexity, which is consistent with the marginal refinery 23 configuration in North America.

24 2. The Quebec Refineries depend mainly on imported crude sources. At present and 25 for the last several years, pricing for light crude in North America has been subject 26 to extraordinary discounts against global benchmark crudes such as North Sea 27 Brent. In IHS’ opinion, this situation is attributable to logistical constraints that have 28 arisen due to rapid growth in production from shale plays and the Canadian oil 29 sands. Resolution of the extraordinary discounts is foreseen within several years, as 30 a number of pipeline projects start up.

31 3. IHS has evaluated the impact of the Project on the Quebec Refineries. We conclude 32 that the Project will allow the Quebec Refineries to access Western Canadian crude 33 at favourable prices relative to imported supplies. We forecast the price advantage 34 to moderate, but to persist after resolution of the extraordinary discounts for

1 Western Canadian crude. This result is sensitive to the pipeline toll in the 2 re-reversed Enbridge Line 9, and to the timing and extent of the anticipated return to 3 more typical pricing relationships for inland crudes.

4 Q.6. Which sources did IHS rely on for preparation of its evidence?

5 A.6. In preparing its evidence, IHS reviewed the Application, as well as information request 6 responses from Enbridge pertaining to the Application. Regulatory filings considered to 7 be relevant to this proceeding were also reviewed. Public information and IHS’ own 8 proprietary models and databases were utilized in preparation of the IHS analysis. For 9 clarity in this document, analysis completed before the IHS acquisition of PGI is referred 10 to by “PGI”, and analysis completed after the acquisition is referred to by “IHS”.

11 REFINING INDUSTRY BACKGROUND

12 Q.7. Which refining industry information of a general nature does IHS consider to be 13 relevant to this proceeding?

14 A.7. IHS notes that refineries constantly make operating and investment decisions that affect 15 their profitability, and ultimately, their economic viability. The decision processes relate 16 to the processing of crude oils and other feedstocks, the operations and maintenance of 17 facilities, and the future capital projects that will allow the refinery to meet applicable 18 product quality specifications, while at the same time satisfying market demand for a 19 range of refined products. Appendix A to this document provides details of the decision 20 making processes that are considered relevant to this proceeding. A summary is 21 provided below:

22  Crude sourcing and supply optimization decisions describe the crude 23 selection decisions and supply decisions followed by refineries in the course of 24 normal operation. Refineries are similar to other businesses in that their 25 profitability is determined by their operating margin, defined as the difference 26 between the revenue received for products produced and the costs of acquiring 27 and processing crude oils and other feedstocks. Supply decisions refer to the 28 “make versus buy” option for meeting market demand.

29  Parity pricing decisions determine the point of indifference between two 30 potential crudes that may be processed in a given refinery. The unique nature of 31 individual crudes and the different capabilities of individual refineries suggest 32 that a rigourous process of evaluation is required to assess the value of one 33 crude in relation to others.

34  Investment process decisions determine the approach to evaluation of the 35 capital investments that are made by refineries, in response to mandated

1 specification changes, opportunistic supply availability of certain crudes, or other 2 factors.

3 Q.8. Describe any specific developments in the North American refining industry that 4 are considered relevant to this proceeding.

5 A.8. IHS notes that crude production in North America has grown steadily in recent years, 6 due to two major developments: (1) oil sands production from Western Canada, and (2) 7 production from the exploitation of certain shale oil plays.

8 Oil sands production has grown for several decades, and includes bitumen production 9 as well as various synthetic crude oil (“SCO”) products from upgraders. The most 10 prominent shale developments have been in the Bakken formation (North Dakota) and 11 the Eagle Ford formation (Texas), but other plays across the continent are showing 12 similar potential.

13 In addition to the production trends noted above, a number of projects have been 14 announced for logistics infrastructure in North America. These include expansions and 15 new build projects.

16 The above developments have many implications for the North American refining 17 industry. The decision processes highlighted in Q/A 7 are discussed in more detail later 18 in this document, with reference to the production and logistical trends noted above.

19 Q.9. Describe the regional refining centres that are considered relevant for this 20 analysis of Enbridge Line 9.

21 A.9. This analysis is primarily focused on the current situation and outlook for the Quebec 22 Refineries (the Suncor refinery in Montreal and the Valero refinery in Lévis), and the 23 impact of the re-reversal of Enbridge Line 9 on the Quebec Refineries. For the purposes 24 of this analysis, the appropriate competitive environment for the Quebec Refineries 25 includes refineries in Ontario, Atlantic Canada, and the northern portion of the U.S. East 26 Coast.1 This is so because refined products are traded between these regions to 27 balance supply and demand. For example, products from Eastern Canada are exported 28 to the U.S. East Coast, where they compete with domestic supply and other imports 29 serving that region. Products from Quebec are transferred to Ontario, and contribute to 30 the overall supply balance in that province. Product prices are linked by transportation 31 and quality differentials between regions. It is this linkage through product trade that 32 creates a competitive environment for the refineries in each of these regions. Therefore,

1 The U.S. East Coast is designated by the U.S. Energy Information Administration (“EIA”) as Petroleum Administration for Defense District (“PADD”) I, and is one of seven PADD’s designated by the EIA. The PADD regions are described in detail at http://www.eia.gov/todayinenergy/detail.cfm?id=4890, accessed on 10 July, 2013.

1 we have included consideration of each of these regional refining industries in our 2 discussion.

3 EASTERN CANADA REFINING MARKETS

4 Q.10. Describe the Quebec Refineries, their historical crude slates and sources.

5 A.10. Total crude distillation capacity of the Quebec Refineries as of January 2013 was 6 372,000 barrels per day (“B/D”), based on the Oil & Gas Journal annual refining survey.2 7 Both refineries have a “cracking”, or “medium conversion” configuration. The major 8 process unit capacities for each refinery are listed in Table 1. Shell Canada shut down 9 its Montreal East Refinery in 2010, and converted the refinery to a products terminal.3

10 The Quebec Refineries primarily run light crude oils, and a small amount of heavy crude 11 oil. Figure 1 (below) and Appendix C summarize the regional crude slate in Quebec.4 12 Most of the light crude processed in Quebec is estimated by IHS to be light sweet crude. 13 Light crude runs in Quebec are estimated by IHS at about 310,000 B/D in 2012.

FIGURE 1 QUEBEC CRUDE SLATE

Thousand Barrels/Day Thousand Cubic Metres/Day 600 Condensate and Pentanes Crude Bitumen 500 Synthetic Crude Conventional Heavy 80 Conventional Light 400 60 300 40 200 20 100

0 0 2009 2010 2011 2012 14 15 Figure 1 Quebec Crude Slate 16 Refineries in Quebec have historically relied mainly on imported crude, although some 17 offshore Canadian East Coast crude oil has been processed. Crude supply sources for 18 Quebec are presented in Figure 2 and Appendix C, as reported by Statistics Canada.5

2 Oil & Gas Journal, “2012 Worldwide Refining Survey”, December 3, 2012. The Oil & Gas Journal survey has been used as a consistent source for refinery capacity information throughout this document, alt hough it recognized that company information and other sources may be available. Where capacity information is not available from the Oil & Gas Journal survey, other sources (including IHS estimates) have been utilized. 3 http://www.shell.ca/en/aboutshell/media-centre/news-and-media-releases/archive/2010/jan07-montreal-east- refinery.html, accessed on 30 July 2013. 4 Source: Statistics Canada, monthly publication series 45-004. In this document, references to the Statistics Canada 45-004 publication use the terms “Crude Bitumen” and “Conventional Heavy”, as defined by Statistics Canada. Taken together, these crude types are heavy crude oil, a more general term that is used in this document. 5 Statistics Canada, monthly publication series 45-004.

1 None of the imported crude for Quebec for the period 2009 to 2012 (as reported by 2 Statistics Canada) has come from the U.S. However, Valero has indicated that it is 3 shipping Eagle Ford crude oil from the U.S. Gulf Coast by tanker to the Jean Gaulin 4 refinery.6

FIGURE 2 QUEBEC CRUDE SOURCES

Thousand Barrels/Day Thousand Cubic Metres/Day 600

Imports Eastern Canada Western Canada 500 80

400 60

300 40 200 20 100

0 0 2009 2010 2011 2012 5 6 Figure 2 Quebec Crude Sources 7 Consistent with the overall crude slate, refineries in Quebec have imported mainly light 8 sweet grades. Imports by source region are shown in Figure 3 and Appendix C. Most of 9 the Quebec imports from Organization of the Petroleum Exporting Countries (“OPEC”) 10 countries are light sweet crude or condensate from Algeria. Imports from the North Sea 11 could range in quality from light sweet to medium or heavy sweet high Total Acid 12 Number (“TAN”) crude. OPEC countries provided the largest source of supply to the 13 province in 2012 but imports from “Other” countries (including mainly Russia and the 14 Caspian countries) are growing in importance.

FIGURE 3 QUEBEC CRUDE IMPORT SOURCES

Thousand Barrels/Day Thousand Cubic Metres/Day 600 Other North America (US & Mexico) 500 North Sea (Norway & UK) 80 OPEC 400 60

300 40 200 20 100

0 0 2009 2010 2011 2012 15 16 Figure 3 Quebec Crude Import Sources

6 Valero Energy Corporation, http://www.valero.com/NewsRoom/Pages/PR_20130430_0.aspx, accessed on 10 July 2013.

1 Runs of offshore Atlantic crude oil in Quebec have been small and declining. Total 2 receipts of Canadian crude in Quebec were about 27,500 B/D in 2012.7 Suncor reported 3 processing 21,600 B/D of “East Coast Canada light conventional crude” in Montreal in 4 2012.8 This is down from about 38,100 B/D in 2009.9

5 Q.11. Describe in more detail the operations and capabilities of the Quebec Refineries.

6 A.11. Valero Jean Gaulin Refinery

7 The 235,000 B/D Valero Jean Gaulin Refinery in Lévis (near Quebec City) currently 8 receives crude oil by waterborne tankers with capacity up to 1 million barrels. The crude 9 slate includes sweet, high mercaptan crude oils and lower-quality, sweet high TAN crude 10 oils.10 The refinery products include gasoline, diesel, home heating oil, industrial fuel oil, 11 jet fuel and liquefied petroleum gases (“LPG”).

12 Finished products from the Jean Gaulin refinery are delivered to customers directly by 13 truck, rail, marine vessel and pipeline. The 243-kilometre Saint-Laurent Pipeline 14 (started up in 2012) connects the refinery to the Valero terminal in Montreal East.11 15 Valero is a shipper on the Trans-Northern Pipelines Inc. (“TNPI”), which delivers refined 16 products from Montreal to distribution terminals in Ontario. Product is also transported 17 by unit train between the refinery and the company’s terminals in New Brunswick and 18 Ontario.

19 Suncor Montreal Refinery

20 Crude oil for the 137,000 B/D Suncor Montreal refinery is supplied mainly via the 21 Portland-Montreal Pipeline (“PMPL”). Products manufactured at the Montreal refinery 22 include gasoline, distillate, asphalt, heavy fuel oil, petrochemicals and solvents. The 23 Montreal refinery also produces feedstock for Suncor’s lubricants plant in Ontario. 24 Suncor delivers refined products to distribution terminals in Ontario via TNPI, and 25 delivers products to customers directly by truck, rail and marine vessel.12

26 Q.12. Are there any announced changes to refinery configurations in the Quebec 27 Refineries?

28 A.12. IHS is not aware of any configuration changes that are currently planned in the Quebec 29 Refineries. However, the owners of these facilities have pursued strategies that would

7 Statistics Canada, monthly publication series 45-004. 8 Suncor Energy Inc., 2012 Annual Information Form, p.25 9 Statistics Canada, monthly publication series 45-004. 10 Valero Energy Corporation, 2012 Form 10-K, http://www.valero.com/InvestorRelations/FinancialReports_Filings_Statements/Documents/VEC_10K_2012.p df, accessed on 10 July 2013. 11 Valero Energy Inc., http://www.ultramar.ca/en/our-company/valero/, accessed on 10 July 2013. 12 Suncor Energy Inc., 2012 Annual Information Form, p.20.

1 increase their ability to access North American crude oils, which are currently subject to 2 extraordinary discounts.

3 As noted in Q/A 10, Valero recently began importing Eagle Ford crude at the Lévis 4 refinery by marine vessel.13 The company plans to rail up to 30,000 B/D of light crude to 5 the refinery starting in the third quarter of 2013, increasing to 50,000 B/D by the third 6 quarter of 2014.14 Further, the company has indicated that it intends to make 7 investments in its Quebec facilities to support the processing of Western Canadian 8 crude received at Montreal, via a reversed Line 9 (assuming the Project is approved and 9 proceeds). Expenditures associated with this initiative would include modifications to the 10 company’s Montreal terminal and to the refinery, as well as the acquisition of ships for 11 transporting the crude.15

12 Prior to its merger with Suncor, Petro-Canada had been evaluating the feasibility of 13 adding a 25,000 B/D delayed coker to the Montreal refinery in order to take advantage of 14 low cost heavier crude oils. The project is currently inactive. However, Suncor is 15 understood to be considering a series of projects that would increase access to oil 16 sands and inland crudes. The projects range from installation of facilities that would 17 increase rail offloading capacity, to the eventual completion of the coker project. 16

18 Q.13. Describe the refining industries in regions considered competitive with the 19 Quebec Refineries.

20 A.13. Ontario

21 The refineries in Ontario compete with the Quebec Refineries, because refined product 22 supply from Quebec is needed to meet demand in the large Southern Ontario market. 23 There are five refineries operating in Ontario, with process unit capacities as listed in 24 Table 1. Capacities shown are from the most recent Oil & Gas Journal annual refining 25 survey.17 Total crude capacity in Ontario, based on this survey, is 468,500 B/D. Three 26 Ontario refineries are cracking or medium conversion refineries. One refinery (Imperial 27 Sarnia) is more complex, with a coking unit. The NOVA Chemicals (NOVA) refinery at 28 Corunna is a topping refinery, so named because feedstocks are fractionated (“topped”) 29 to produce components that are sold or processed at the NOVA petrochemical complex.

30 Refineries in Ontario have access to several crude sources, including the Atlantic Basin, 31 Western Canada, the U.S. Midwest (North Dakota and Michigan), and the U.S. Gulf

13 Valero Energy Corporation, http://www.valero.com/NewsRoom/Pages/PR_20130430_0.aspx, accessed on 10 July 2013. 14 Valero Energy Corporation, July 2013 Investor Presentation, accessed 10 July 2013. 15 http://www.reuters.com/article/2013/05/29/valero-quebec-refinery-idUSL2N0EA21I20130529, accessed on 22 July 2013. 16 http://seekingalpha.com/article/1384751-suncor-energy-s-ceo-discusses-q1-2013-results-earnings-call- transcript, accessed on 10 July 2013. 17 Oil & Gas Journal, “2012 Worldwide Refining Survey”, December 3, 2012..

1 Coast (via the Capline/Chicap system, which interconnects with the Enbridge system in 2 Illinois).

3 The historical Ontario crude supply by crude type for the period 2009 to 2012 is 4 summarized in Figure 4.18 Refer to Appendix C for the supporting data for this figure. 5 Refineries in Ontario have traditionally processed significant quantities of light crude . 6 Conventional heavy and crude bitumen are heavy sour grades. According to Statistics 7 Canada, runs of heavy crude oil remained relatively stable between 2009 and 2012 at 8 less than 20 percent of total crude processed.

FIGURE 4 ONTARIO CRUDE SLATE

Thousand Barrels/Day Thousand Cubic Metres/Day 600 Condensate and Pentanes Crude Bitumen 500 Synthetic Crude Conventional Heavy 80 Conventional Light 400 60 300 40 200 20 100

0 0 2009 2010 2011 2012 9 10 Figure 4 Ontario Crude Slate 11 SCO runs in Ontario were about 71,000 B/D in 2012.19 Suncor reported processing 12 45,500 B/D of SCO at its Sarnia refinery in 2012, which included 22,700 B/D of sour 13 SCO.20 This suggests that about 25,500 B/D of SCO were processed by other Ontario 14 refineries (mainly Shell and Imperial).

15 Atlantic Canada

16 The refineries in Atlantic Canada are considered competitive with the Quebec 17 Refineries, since both regions depend on refined product trade in the large U.S. East 18 Coast market. There are three refineries currently operating in Atlantic Canada, with 19 process unit capacities as listed in Table 1. Total crude distillation capacity for the 20 refineries in this region is 450,000 B/D, based on the Oil & Gas Journal annual refining 21 survey.21 All three refineries have a cracking (or medium conversion) configuration.

22 Imperial Oil announced in June 2013 that it would cease operations at the Dartmouth 23 Refinery, and convert the refinery to a products terminal.22 The initial startup of the

18 Statistics Canada, monthly publication series 45-004. 19 Statistics Canada, monthly publication series 45-004. 20 Suncor Energy Inc., 2012 Annual Information Form, p.25. 21 Oil & Gas Journal, “2012 Worldwide Refining Survey”, December 3, 2012. 22 http://www.imperialoil.ca/Canada-English/about_media_releases_20130619.aspx, accessed on 10 July 2013.

1 converted facilities will be later in 2013. Excluding the Imperial Dartmouth Refinery, the 2 total crude distillation capacity in Atlantic Canada is 365,000 B/D.

3 The Atlantic Canada refineries process a range of crude oils, but a relatively small 4 amount of heavy crude oil. Segregated crude run statistics are not available for 5 individual refineries. Figure 5 (below) and Appendix C present the regional crude slate in 6 Atlantic Canada.23 Between 2009 and 2012, refineries in Atlantic Canada processed 7 significant quantities of light crude, as well as some heavy crude for asphalt.

FIGURE 5 ATLANTIC CANADA CRUDE SLATE

Thousand Barrels/Day Thousand Cubic Metres/Day 600 Condensate and Pentanes Crude Bitumen Synthetic Crude Conventional Heavy 500 80 Conventional Light

400 60 300 40 200 20 100

0 0 2009 2010 2011 2012 8 9 Figure 5 Atlantic Canada Crude Slate 10 Atlantic Canada refineries run mainly imported crude, although some domestic East 11 Coast crude oil is also processed in the region. The OPEC countries have historically 12 accounted for the largest share of imports to Atlantic Canada. Imports from the North 13 Sea, Russia and countries in the Caspian region make up the balance. None of the 14 imported crude for Atlantic Canada between 2009 and 2012 was from the U.S., as 15 reported by Statistics Canada. However, the delivery of crude from the northern U.S. 16 states by rail has increased in the last year. Irving is understood to be transporting up to 17 90,000 B/D of crude by rail to Saint John.24

18 U.S. Northeast

19 Refineries in the U.S. Northeast operate in a region with very large refined product 20 demand. Product prices in this region are established through international trade and 21 transfers from other U.S. refining centres, notably the Gulf Coast. In turn, the Quebec 22 Refineries realize refined products prices that are set by trade balances to the U.S. 23 Northeast.

24 Most of the refining capacity in the U.S. East Coast (PADD I) is located in New Jersey, 25 Pennsylvania and Delaware. The major fuel refineries in these states (listed in Table 1) 26 have combined crude capacity of approximately 1.3 million B/D, according to the latest

23 Statistics Canada, monthly publication series 45-004 . 24 http://www.bloomberg.com/news/2012-12-26/irving-refinery-said-to-get-90-000-barrels-a-day-by-rail.html, accessed 10 July 2013.

1 Oil & Gas Journal annual refining survey.25 Most of the refineries in the U.S. Northeast 2 are in coastal locations, and are able to accommodate ocean-going tankers for crude 3 delivery. Only the United Refining facility at Warren, PA receives Western Canadian 4 crude delivered by pipeline via Ontario. Cracking (medium complexity) configurations 5 are common in the U.S. East Coast region, as the market has significant residual fuel oil 6 demand. Two refineries in the region have coking capacity.

7 IHS’ estimate of the PADD I crude slate is summarized in Figure 6 and Appendix C. 8 Many of the coastal refineries in PADD I were built to process foreign crude. A number 9 of refineries run exclusively sweet crude, and some run a combination of light sweet and 10 light sour crudes. Heavy crude runs are estimated at about 137,000 B/D in 2012, for 11 asphalt production and coking operations.

FIGURE 6 PADD I CRUDE SLATE

Thousand Barrels/Day Thousand Cubic Metres/Day 2,000 300 Heavy Light Sour Light Sweet 250 1,500 200

1,000 150

100 500 50

0 0 2009 2010 2011 2012

12 Figure 6 PADD I Crude Slate 13 PADD I refineries rely mainly on imported crude, mainly from offshore foreign sources 14 but including some Canadian east coast crude. Crude imports are dominated by West 15 Africa (Nigeria and Angola), which produce mainly light sweet crude oil.

16 Q.14. Comment on any changes in product specifications that may be relevant for the 17 Eastern Canada refining industry, and the Quebec Refineries in particular.

18 A.14. Specifications for marine bunker fuel have come under greater scrutiny. The 19 International Maritime Organization (“IMO”) reduced fuel oil sulfur limits from 4.5 percent 20 to 3.5 percent in 2012. Furthermore, the IMO has adopted regulations calling for 21 significant reductions in fuel oil sulfur, from 1.5 percent sulfur to 1.0 percent sulfur (after 22 1 July 2010), and to 0.1 percent sulfur (after 1 January 2015) in certain defined 23 Emissions Control Areas (“ECA’s”). A reduction to 0.5 percent outside of ECA’s is

25 Oil & Gas Journal, “2012 Worldwide Refining Survey”, December 3, 2012.

1 proposed in 2020.26 The IMO has designated specific portions of Canada and U.S. 2 coastal waters as ECAs, as of 1 August 2012.27

3 The above bunker fuel specification changes have had material impact on cracking 4 refineries (that is, refineries that blend unconverted residue into fuel oil). We believe that 5 cracking refineries would not be able to comply with future fuel oil specifications through 6 crude selection. Instead, refineries would be most likely to supply marine diesel to 7 vessels operating in Canadian waters. To the extent that the Quebec Refineries (or 8 other refineries in Atlantic Canada or the U.S. Northeast) produce fuel oil from their 9 current crude slate, they may benefit from processing crude oils that have no residue 10 (such as sweet SCO), which would address the pending specification change by 11 reducing the production of heavy fuel oil. This may be an economic option, at least 12 seasonally, subject to evaluation of any refining issues associated with processing SCO.

13 NORTH AMERICAN CRUDE SUPPLY, DEMAND AND PRICING ANALYSIS

14 Q.15. What is the current outlook for Western Canadian crude oil production and 15 supply?

16 A.15. Figure 7 summarizes the total supply of crude oil from Western Canada, consistent with 17 production scenarios developed annually by the Canadian Association of Petroleum 18 Producers (“CAPP”) for the period 2009 to 2013. The series of CAPP forecasts 19 illustrates a trend of growth in the outlook for Canadian oil sands crude production and 20 supply. The 2009 Growth scenario forecast28 and the 2010 Growth scenario forecast29 21 are generally similar for the duration of the forecast period, but since 2011 the CAPP 22 forecasts have increased each year. For example, comparing CAPP production outlooks 23 for 2025, the 2011 forecast30 called for an increase of 717,000 B/D over the 2010 24 forecast. The 2012 forecast31 includes a further increase of 933,000 B/D over the 2011 25 forecast.

26 International Maritime Organization, http://www.imo.org/environment/mainframe.asp?topic_id=233, accessed on 30 July 2013. 27 International Maritime Organization, “Sulfur oxides (SOx) – Regulation 14”, http://www.imo.org/ourwork/environment/pollutionprevention/airpollution/pages/sulphur-oxides-(sox)- %E2%80%93-regulation-14.aspx, accessed on 10 July 2013. 28 CAPP, “Crude Oil Forecast, Markets & Pipeline Expansions”, June 2009 29 CAPP, “Crude Oil Forecast, Markets & Pipelines”, June 2010 30 CAPP, “Crude Oil Forecast, Markets & Pipelines”, June 2011 31 CAPP, “Crude Oil Forecast, Markets & Pipelines”, June 2012

FIGURE 7 CAPP WESTERN CANADA TOTAL CRUDE SUPPLY FORECAST SCENARIO COMPARISON

(Thousand Barrels per Day) 8000 7000 2011 Growth 2012 Forecast 6000 2013 Forecast 2010 Growth 5000 2009 Growth 4000 3000 2000 1000 0 2005 2010 2015 2020 2025 2030 1 2 Figure 7 CAPP Western Canada Total Crude Supply Forecast Scenario Comparison 3 The CAPP 2013 forecast was released in June 2013.32 The major contributing factors 4 for the increase in the 2013 forecast are growth in in-situ bitumen production, and a 5 consequent increase in the supply of crude to the market (due to the requirement to 6 blend bitumen with lighter streams to achieve pipeline specifications).

7 Q.16. Describe the outlook for crude oil production and supply from shale plays such as 8 the Bakken formation.

9 A.16. The volume of domestic light sweet crude available to North American refineries is 10 increasing, due largely to technological developments that have been applied to tight 11 shale reservoirs in the Williston Basin, Eagle Ford and elsewhere. The application of 12 long horizontal drilling and multiple fracturing techniques has rejuvenated crude 13 production in North Dakota and Montana (and to a similar degree in the Canadian 14 provinces of Saskatchewan and Manitoba). The Bakken formation is the target of 15 significant exploration and development activity in the Williston Basin.

16 Forecasts of Williston Basin crude production provided by the North Dakota Pipeline 17 Authority (“NDPA”) are compared in Figure 8.33,34,35 The figure illustrates the strong 18 historical growth, and future potential for production from the Williston Basin. Combined 19 production from the major producing states in the U.S. northern tier (North Dakota and 20 Montana) has risen sharply, to about 735,000 B/D in 2012, up from 131,000 B/D in 2000

32 CAPP, “Crude Oil Forecast, Markets & Transportation”, June 2013 33 Source: North Dakota Pipeline Authority, “North Dakota’s Transportation Infrastructure”, December 2010, accessed at https://www.dmr.nd.gov/pipeline/assets/01062011/NDPA%20Dec%202010%20Oil%20Report.pdf on 10 July 2013. 34 Source: North Dakota Pipeline Authority, May 23, 2012 presentation, accessed from http://ndpipelines.files.wordpress.com/2012/04/ndpa-wbpc-5-23-2012.pdf on 10 July 2013. 35 Source: North Dakota Pipeline Authority, May 17, 2013 presentation, accessed from http://ndpipelines.files.wordpress.com/2012/04/ndpa-may-17-2013.pdf on 10 July 2013.

1 and 188,000 B/D in 2005.36 Further gains are expected, with production forecast to be 2 between 1.4 and 1.6 million B/D by 2020, according to the most recent NDPA forecast.

FIGURE 8 WILLISTON BASIN CRUDE PRODUCTION FORECAST COMPARISON

Million Barrels per Day 1.8 1.6 Source: Adapted from North Dakota Pipeline 1.4 Authority forecasts in various publications 1.2 1.0 0.8 0.6 2013 Forecast - High 2013 Forecast - Low 0.4 2012 Forecast - High 2012 Forecast - Low 0.2 2010 Forecast - High 2010 Forecast - Low

0.0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 3 4 Figure 8 Williston Basin Crude Production Forecast Comparison

5 Q.17. What do these crude production and supply trends mean for refiners generally, 6 and for refiners in Eastern markets of North America in particular?

7 A.17. Growth in the supply of light crude (from shale plays) and oil sands crudes have 8 changed the economic outlook for refineries that can readily access these sources of 9 supply. Increasing supplies of light sweet crude from shale reservoirs such as the 10 Bakken or Eagle Ford offer refineries with capabilities to process conventional light 11 crudes a significant source of supply that was not previously foreseen. These crudes are 12 generally directly substitutable for imported conventional light crudes, and are therefore 13 of greatest interest to those refineries in North America that rely on imports of similar 14 quality crudes for their supply.

15 The characteristics of refineries in the Eastern markets of North America (including the 16 Quebec Refineries) are well suited to processing light conventional crude. However, 17 access to these growing supplies is limited, due to logistical constraints in the installed 18 pipeline infrastructure.

19 Oil sands crudes are considered partial substitutes for the conventional light and heavy 20 crudes processed in many North American refineries. Existing refineries may require 21 modification to process significant quantities of oil sands crudes. Considerations for 22 refineries to undertake such projects include technical as well as strategic and 23 commercial issues. Several large coking projects have been undertaken in recent years 24 by Midwest refineries, whose objective in completing the projects was to access 25 anticipated growing supplies of lower valued Western Canadian bitumen.

36 U.S. Energy Information Administration, http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm, accessed on 10 July 2013.

1 Q.18. Describe the major proposed export pipeline projects that would allow Western 2 Canadian oil sands or U.S. shale oil to serve new refining markets.

3 A.18. Table 2 summarizes pipeline projects to the U.S. Gulf Coast, and to the North American 4 East Coast and West Coast. IHS expects the pipeline project developments to the U.S. 5 Gulf Coast (as listed in the upper panel of Table 2) to reach completion. These projects 6 are expected to result in a stronger price trend (i.e. narrower discount) for Canadian 7 crude within the next several years. Other projects listed in Table 2 may also be 8 developed, as well as some projects not listed in Table 2.

9 Q.19. What is IHS’ current outlook for crude oil pricing?

10 A.19. The current IHS price forecast for Brent (FOB Sullom Voe) is given in Figure 9. 11 Supporting data for the figure is found in Appendix C. Brent is representative of North 12 Sea light sweet crude, and serves an important role as a contract basis for crude trade 13 in the Atlantic Basin.

FIGURE 9 CRUDE OIL PRICE FORECAST

Dollars per Barrel 175

150 Dated Brent, FOB WTI, Spot Cushing 125 Bonny Light, FOB 100 MSW, Edmonton 75

0 2000 2005 2010 2015 2020 2025 14 15 Figure 9 Crude Oil Price Forecast 16 IHS’ proprietary methodology for regional crude price forecasting is based on Brent, and 17 determines key benchmark crudes in other regions through transportation and quality 18 adjustments. The forecast reflects our outlook for the cost of incremental crude supply, 19 and takes into account the expected impact of price on supply and demand.

20 The IHS methodology for regional crude oil pricing is based on the concept of parity 21 pricing, as described in Appendix A. The parity price (or the price at which the refinery is 22 indifferent as to crude substitution) relative to a regional benchmark crude is established 23 in the marginal refinery configuration for the region in question. A cracking refinery 24 configuration is considered the marginal refinery configuration in the markets of interest 25 for this analysis.

26 Waterborne transportation costs are a function of ship size (which is generally optimized 27 for the length of voyage), the characteristics of the crude, and other costs that may be

1 applicable to the voyage. Pipeline transportation costs are set by lowest cost toll, 2 utilizing the system that is believed to have available capacity for spot transportation. 3 Generally, spot market tolls establish the price differential between crude oils.

4 The forecast price for Bonny Light, FOB Nigeria and West Texas Intermediate (“WTI”) at 5 Cushing, OK are given in Figure 9. Bonny Light is a light sweet crude benchmark in the 6 Atlantic Basin, and is representative of crude oils that may be imported by the Quebec 7 Refineries. WTI is a pricing benchmark for inland crudes in North America, including 8 Alberta Mixed Sweet (“MSW”) crude. The forecast price for MSW at Edmonton is also 9 shown in Figure 9. Relationships between these crude oils are addressed below.

10 Q.20. Describe the historical situation for price differentials between Brent and North 11 American benchmark crudes. Include a discussion of the rationale for the reversal 12 and potential re-reversal of Line 9.

13 A.20. Figure 10 illustrates the historical trend of the monthly price differential between WTI 14 and Dated Brent (FOB Sullom Voe). The WTI-Brent differential is indicative of regional 15 supply and demand fundamentals at these two Western Hemisphere trading hubs. The 16 economics of crude oils delivered by Enbridge Line 9 have evolved in line with these 17 fundamental trends. At the time of the Line 9 reversal in 1999, there was a prevailing 18 incentive to bring Atlantic Basin crude (mainly North Sea light sweet crude such as 19 Brent) into the Ontario refining market. This incentive was predicated on two factors: 20 declining supplies of Western Canadian conventional light crude, and a surplus volume 21 of North Sea crude that was serving North American refining markets.

FIGURE 10 WTI, CUSHING - BRENT, FOB Source: Platts

(U.S. Dollars Per Barrel) 20.00 High prices 15.00 Line 9 reversal High volatility 10.00 Discounts on WTI, MSW 5.00 0.00 -5.00 -10.00 Line 9 favoured Line 9 favoured for Ontario for Ontario -15.00 Extraordinary mid-continent crude -20.00 price discounts -25.00 -30.00 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 22 23 Figure 10 WTI, Cushing – Brent, FOB 24 The economics of delivering imported crudes versus Western Canadian crudes to the 25 inland market regions of Canada have varied with the prevailing WTI-Brent trend shown 26 above. There have been periods of time since Line 9 was reversed when a comparative 27 price advantage existed for delivering Western Canadian crude into Ontario. Indeed, for 28 much of the time since late 2005, North American inland crude prices (including WTI 29 and crudes priced against it) were discounted to Brent. Since late 2010, the growth of oil

1 production from shale reservoirs has exacerbated the discounts for inland crudes. This 2 has led to a period of apparent strong advantage for Western Canadian crude 3 processing in Ontario and Quebec.

4 Q.21. Briefly describe the conditions that have led to the current price discounting for 5 Western Canadian crude oil, with specific reference to export takeaway capacity 6 from Western Canada.

7 A.21. The current demand for crude oil transportation capacity to markets outside of Western 8 Canada exceeds the available takeaway capacity. In 2011, PGI estimated that more 9 pipeline capacity would be needed by 2014 to 2016, depending on future crude 10 production.37 In 2012, IHS estimated that total takeaway capacity for Western Canadian 11 crude had increased from 1.468 million B/D in 1993 to 3.925 million B/D in 2011. 38 The 12 2012 CAPP forecast suggested that an imbalance between takeaway capacity and 13 forecasted supply would lead to additional pipeline capacity exiting Western Canada 14 being needed as early as 2014.39

15 In our opinion, there may be many causes for an imbalance between pipeline takeaway 16 capacity and forecasted crude supply. Projects such as the Keystone XL, which would 17 add takeaway capacity, have been delayed relative to their originally proposed schedule. 18 Production outlooks for heavy and light crude oils may vary from year to year, based on 19 the prevailing incentives to produce and upgrade bitumen to SCO. Effective pipeline 20 capacity may be reduced due to operational issues, such as pressure restrictions. 21 Perhaps most important is the impact of increases in production of crude from tight 22 shale reservoirs, which has added supplies of crude oil into the North American balance, 23 and has created additional competition for pipeline capacity. Each of these factors has 24 contributed to the current situation.

25 Q.22. Describe the practical implications of the logistical constraints described above, 26 with reference to Western Canadian crude oils?

27 A.22. The high demand for pipeline transportation service has led to a period of pro-rationing 28 of capacity in major export pipelines, and discounted prices for Western Canadian crude 29 in relation to relevant benchmark crude oil prices. The discounted spot prices for crude 30 oil reflect the cost to clear the market using higher cost transportation services or using 31 a different transportation mode to the highest valued available market region.

32 Western Canadian light and heavy crude oils have been affected by these logistical 33 constraints. Light crude (conventional and SCO) competes for inland markets with 34 growing tight oil supply. A growing surplus of heavy crude has exceeded the takeaway

37 Purvin & Gertz, Inc. “More Capacity Urgently Needed for Crude Pipelines”, http://www.purvingertz.com/dynpage.cfm?PageID=11&filter=2&Article=179, October 19, 2011. 38 Reply evidence of IHS, as filed in NEB proceeding RH-001-2012, Exhibit A3F1C8, January 2013. 39 Canadian Association of Petroleum Producers, “Crude Oil Forecast, Markets & Pipelines”, June 2012, p.32.

1 capacity for delivery of these crudes, and significant discounts have been observed for 2 representative Western Canadian heavy crude oils in comparison with international 3 benchmark crudes. PGI provided evidence that the price of Cold Lake Blend had been 4 discounted versus Maya at either the U.S. Gulf Coast40 or in the U.S. Midwest41 for most 5 of the time since 2006.

6 Refineries across North America may be candidates to process advantageously priced 7 oil sands crudes or conventional crudes from western regions of North America. 8 Following is a brief summary of the potential for crude processing of different types:

9  Bitumen blends such as DilBit (bitumen blended with condensate as a diluent) or 10 SynBit (bitumen blended with SCO as a diluent) may be processed in refineries 11 with residue conversion capacity.42

12  Sweet SCO may be processed in refineries that traditionally process light sweet 13 crude. Refineries with significant Vacuum Gas Oil (“VGO”) conversion capacity 14 or with limited disposition outlets for fuel oil production may be the best 15 candidates for this operation.

16  Light conventional crude from shale plays could be processed as a substitute for 17 similar quality crude delivered to these refineries from other sources.

18 There is ample evidence that the prevailing discounts on Western Canadian and other 19 inland crudes have been sufficient to prompt refineries across North America to pursue 20 strategies geared to accessing these crudes in greater quantities.43,44,45

21 Q.23. Present IHS’ views on the potential for future discounts on Canadian light crude.

22 A.23. IHS expects the fundamental factors that have created the environment of discounted 23 Western Canadian crude oil to be resolved within several years. It is our opinion that 24 increased exports to regions other than the traditional markets for Western Canadian 25 crude46 will be needed. In addition to Quebec, other potential markets include the U.S.

40 PGI identified the potential for this situation to develop in the Keystone XL proceeding. Refer to “Western Canada Crude Supply and Markets”, as filed in NEB Proceeding OH-1-2009, Exhibit A1I9R7, February 2009. 41 Purvin & Gertz, Inc., “Keystone XL Pipeline and Midwest Gasoline Prices”, April 2012, http://www.purvingertz.com/content/articles/Keystone%20XL%20Pipeline%20FAQ.pdf , accessed on 23 July, 2013. 42 As used in this document, the term “bitumen blend” describes any of the marketed blends of bitumen and a lighter hydrocarbon stream, which is required to meet pipeline specifications. The term is considered to be synonymous with “Crude Bitumen” as used by Statistics Canada in statistical series 45-004. 43 http://www.bloomberg.com/news/2013-04-22/tesoro-plans-west-coast-rail-operation-to-tap-shale-crude- boom.html, accessed on 18 July 2013. 44 http://www.bloomberg.com/news/2013-02-04/pbf-energy-completes-delaware-city-rail-terminal-for-bakken- oil.html, accessed on 18 July 2013 45 http://www.phillips66.com/EN/newsroom/feature-stories/Pages/AdvantagedCrude.aspx, accessed on 18 July 2013. 46 “Traditional markets” for Western Canadian crude oil have been defined by IHS as those markets having preferential access to this source of crude supply. For this analysis, traditional markets include the northern regions of PADD II, Montana, and the Pacific North West region of PADD V. Other markets for Western Canadian crude oil have access to other sources of supply.

1 Gulf Coast (PADD III), the U.S. West Coast (PADD V), the Pacific Rim, and the Atlantic 2 Basin.

3 IHS believes that pipeline capacity that will enable access to these markets will be 4 constructed in an efficient manner, taking into account all constraints applicable to its 5 construction. Indeed, our current forecast calls for resolution of observed extraordinary 6 discounts for heavy crude within several years, based on anticipated pipeline projec t 7 developments. Keystone XL is seen as an important project for the resolution of the 8 current price discounts for Canadian crude. While IHS acknowledges that the 9 opportunities and constraints that apply to any given pipeline project are unique, it also 10 considers it improbable that the market response would fall short of the capacity needed 11 to resolve the current extraordinary differentials. It is quite possible that overbuilding of 12 capacity may result, if all pipeline projects were to proceed to completion.

13 Our forecast is that the cumulative impact of pending pipeline projects will be to 14 essentially eliminate extraordinary discounts on Canadian crude by 2016. The pricing 15 mechanism for light sweet crude in our forecast is based on cracking refining parity 16 against WTI in the U.S. Midwest.

17 IMPACT OF THE PROJECT ON QUEBEC REFINERIES

18 Q.24. Comment on the potential of Quebec Refineries to process crude oils that may be 19 delivered by an eastbound Enbridge Line 9?

20 A.24. Valero Jean Gaulin Refinery

21 The Valero Jean Gaulin refinery has comparatively low VGO processing capacity as a 22 percentage of crude (29 percent, based on the 67,500 B/D Fluid Catalytic Cracking 23 (“FCC”) unit) and limited sulfur plant capacity of 80 tonnes per day. These process 24 capacities would tend to limit the amount of light sour and heavy sour crude oils that 25 could be processed with the current refinery configuration, and would therefore likely 26 preclude the processing of bitumen blends without capital investment.

27 Some SCO could be processed at the Valero refinery. The volume would be optimized 28 within the existing refinery constraints, including VGO processing capacity, since sweet 29 SCO generally has high VGO content. Valero could process SCO and export any 30 surplus VGO.

31 Conventional light crude as produced from Bakken shale would be highly substitutable 32 versus imported light sweet crude in the Valero refinery.

33 Suncor Montreal

34 The Suncor Montreal refinery has VGO processing capacity that is close to the average 35 of the Eastern regional refineries (37 percent of crude oil), and has both an FCC unit

1 and VGO hydrocracker. The refinery may be able to process bitumen blend and some 2 SCO. It is likely that crude quality constraints would apply for the production of asphalt, 3 lube oil feed and other specialty products such as petrochemical feedstocks. These 4 quality constraints could limit the extent of substitution by bitumen blend and/or SCO in 5 the existing refinery crude slate.

6 It is entirely possible that Suncor would consider steps to integrate the Montreal refinery 7 with its oil sands operations. As noted in Q/A 12, a series of projects are under 8 consideration by Suncor. If Suncor were to pursue a coker project in Montreal, it would 9 allow the refinery to use more heavy crude, presumably including bitumen blends, and 10 would increase its yield of finished products.

11 In addition to the above oil sands processing opportunities, the Suncor Montreal refinery 12 would be expected to have potential for processing light sweet conventional crude, 13 including production from shale plays.

14 Q.25. Provide an assessment of the outlook for crude supply to the Quebec Refineries, 15 if the Project does not proceed.

16 A.25. If the Project does not proceed, the Quebec Refineries would not have the option to 17 receive Western Canadian or Bakken crude oil by pipeline. Alternative sources of crude 18 supply and/or different delivery methods would be required. The options for crude supply 19 to the Quebec Refineries would include, but are not limited to, the following:

20 1. Domestic crude supply by pipeline

21 2. Domestic crude supply by rail

22 3. Imported crude supply by pipeline

23 4. Imported crude supply by rail

24 5. Imported crude supply by waterborne tanker

25 The majority of crude supply in the status quo is supplied either by pipeline from 26 imported sources (for Suncor Montreal) or by waterborne tanker (for Valero Lévis). The 27 economics of crude supply to the Quebec Refineries by any of the above mechanisms 28 would depend on the source of crude, the price of the crude at its origination point, 29 transportation assumptions and costs for delivery to the refinery location, and the 30 specific constraints applicable to the processing of the crude in question. Other factors 31 may be relevant to the refinery in question, such as any equity (ownership) relationships 32 that may create an incentive to process specific crudes in preference to others.

1 Q.26. What are the economics of delivered crudes to the Quebec Refineries in an 2 eastbound Enbridge Line 9?

3 A.26. To assess competitive crude pricing to the Quebec Refineries, IHS assessed the 4 delivery costs for crude oils that are considered representative of the current slate. Many 5 individual crudes may be sourced and shipped to Portland, ME (for onward delivery to 6 Montreal) or directly to Quebec City. The Quebec Refineries would ideally process crude 7 oils with suitable refining characteristics for their specific configuration, and with 8 sufficient volume availability to meet their requirements. For this analysis we have 9 considered Bonny Light as the imported crude and MSW as the domestic crude from 10 Western Canada.

11 Freight economics are an important component of delivered costs for Atlantic Basin 12 crude supplies. Greater economies of scale may be realized through the use of the 13 largest practical tanker size, within the constraints of the load port and destinati on port. 14 The following table summarizes shipping distances and current costs for primary 15 (waterborne) transportation of the selected Atlantic Basin crude oils from their 16 respective load port to Portland and Quebec City.

IMPORTED CRUDE OIL DELIVERY LOGISTICS

Bonny Bonny Brent Light Brent Light

Country of Origin UK Nigeria UK Nigeria Destination Portland Portland Quebec City Quebec City Round Trip Distance (miles) 5,558 10,021 5,245 10,518 Days in Transit 11 18 11 19 Vessel Size (1,000 DWT) 135 135 135 135 Total Transportation Costs (1) 1.51 2.11 1.48 2.20 Notes: (1) Transportation costs in 2013 U.S. dollars per barrel, including duties and estimated Notes: (1) port fees.

17 A range of pipeline transportation costs for crude oil delivery from Sarnia to Montreal via 18 Line 9 in eastbound operation were used in this analysis. Estimates of future pipeline 19 tolls in Line 9 are taken from the Transportation Services Agreement (“TSA”), under 20 which the committed toll for light crude delivery from Edmonton to Montreal is $5.22 per 21 barrel, and the committed toll for heavy crude delivery from Edmonton to Montreal is 22 $6.31 per barrel.47 For the purposes of this analysis, IHS considered a range of tolls, 23 with the TSA estimates (above) as the low toll and the current westbound tolls as the

47 Enbridge Pipelines Inc., Response to NEB IR1.1 – Attachment 1 – Pro Forma TSA – Exhibit A3G4R9, Adobe pg. 34.

1 high toll.48 For onward delivery from Montreal to Quebec City, IHS assumed that 2 waterborne delivery costs of $1.00 per barrel would apply.

3 The comparative analysis of delivered crude prices is based on the current IHS long 4 range price forecast. Price differential forecasts are based on equilibrium price 5 expectations for crude from different supply regions.

6 The delivered cost comparisons for domestic and imported crude oils are presented in 7 Tables 3 and 4. Forecast prices are provided for Montreal and Quebec City, in current 8 and constant 2011 U.S. dollars, respectively.

9 Bonny Light - MSW

10 Figure 11 compares the delivered costs for Bonny Light and MSW in Montreal and 11 Quebec City on a refining quality-adjusted basis. With a Line 9 re-reversal for eastbound 12 operation, the estimated delivered cost of MSW in Montreal and Quebec City would be 13 lower than the delivered cost of Bonny Light for the forecast period through 2025. We 14 conclude that the Project will allow the Quebec Refineries to access Western Canadian 15 light sweet crude at favourable prices relative to imported supplies. IHS forecasts that 16 the price advantage will moderate after resolution of the conditions that led to the 17 current extraordinary discounts for Western Canadian light sweet crude. IHS considers it 18 unlikely that the conditions which led to extraordinary discounting will re-emerge for the 19 foreseeable future. However, we forecast that there will be a persistent incentive for the 20 Quebec Refineries to access Western Canadian crude through the Project, as shown in 21 Figure 11.

FIGURE 11 BONNY LIGHT - MSW (QUALITY ADJUSTED)

Forecast in Constant 2011 Dollars per Barrel 24 Quebec City (High Toll) Source: Platts, company postings, IHS analysis 18 Quebec City (Low Toll) Montreal (High Toll) Montreal (Low Toll) 12 Western Canada Favoured

0 Offshore Favoured -6 2005 2010 2015 2020 2025

22 Figure 11 Bonny Light – MSW (Quality Adjusted)

48 Enbridge Pipelines Inc. “Tolls Applying on Offshore Crude Petroleum Transported in Line 9 Operating in an East to West Direction”,http://www.enbridge.com/DeliveringEnergy/Shippers/~/media/www/ Site%20Documents/Delivering%20Energy/Shippers/2013Tariffs/NEB%20No%20336%20July%202013.pdf, accessed on 10 July 2013.

1 The economic results are sensitive to the pipeline toll in the re-reversed Line 9, and to 2 the timing and extent of the anticipated return to more typical pricing relationships for 3 inland crudes. Illustrative results are highlighted below:

4  In 2015, the estimated advantage for MSW in Montreal ranges from $7.34 to 5 $9.42 per barrel, depending on the Line 9 toll. The advantage for MSW in 6 Quebec City ranges from $4.80 to $6.89 per barrel.

7  In 2025, the estimated advantage for MSW in Montreal ranges from $4.44 to 8 $6.44 per barrel, depending on the Line 9 toll. The advantage for MSW in 9 Quebec City ranges from $1.79 to $3.79 per barrel.

10 Q.27. How would the costs of other alternatives compare with the Line 9 reversal?

11 A.27. The Quebec Refineries each have unique capabilities to handle crude supplies delivered 12 by pipeline, rail and/or waterborne tanker. The specific capabilities to accommodate any 13 of these delivery modes are a commercially sensitive aspect of refinery operations, and 14 are generally not publicly available. However, IHS notes that the economics of feedstock 15 supply are improved by scale, encouraging the largest delivered quantities of crude oil 16 that can be readily handled.

17 It is generally true that rail will be more expensive than pipelines for long haul 18 transportation of crude oil. Rail delivery may be competitive with other modes of 19 feedstock delivery in specific instances, but several factors often limit this type of 20 operation. For example, limited capacity may exist for offloading of crude oil by rail 21 (which may require capital expenditure at the refinery), or tight specifications may be 22 imposed on crude quality (which may be critical for production of certain specialty 23 products). On the other hand, rail has inherent advantages of flexibility and scalability.

24 As a practical matter, the actual costs for delivery of crude by rail will depend on factors 25 such as the competitiveness of the specific rail network segment, the need to transfer 26 cargo between carriers, the type of crude being handled, and the availability of suitable 27 loading and offloading facilities. For illustrative purposes, IHS estimates that the costs of 28 delivering crude oil from Western Canada or the U.S. northern tier to the Quebec 29 Refineries would be in the range $13-16 per barrel. This range of costs is significantly 30 higher than the estimated costs through the re-reversed Line 9.

31 Q.28. What effect would the reversal of Line 9 have on the economic outlook and 32 continued viability of the Quebec Refineries?

33 A.28. The profitable operation of the Quebec Refineries is a business objective of the facility 34 owners. Economics of petroleum refining are subject to many factors, including the yield 35 and price received for the refined products manufactured in the refinery, the cost of 36 crude oil and other feedstocks, and the cost of operating and maintaining the refinery. 37 All else being equal, reducing feedstock costs likely represents the best opportunity to

1 improve refinery economic performance, since these costs account for the majority of 2 costs incurred in the typical refinery operation. It is noted that the Quebec Refineries are 3 considered to be price takers for the refined products they manufacture, since the prices 4 of these products are determined by trade in efficient international markets.

5 The re-reversal of Line 9 would accomplish several objectives for the Quebec 6 Refineries, which may ultimately facilitate improved economic performance. First, the 7 Project would provide access to additional sources and type of feedstocks. The 8 available feedstocks may include conventional crudes sourced from Canada and/or the 9 U.S., as well as oil sands crudes from Canada. Second, to the extent these feedstocks 10 are favourably priced versus the available market alternatives, there may be an 11 economic advantage realized through an increase in the refinery margin. Third, in the 12 case of at least one refinery (Suncor Montreal), the Project may facilitate future 13 downstream integration for its oil sands assets. Suncor has actively pursued such a 14 strategy in its Sarnia and Denver refinery integration projects.49

15 The continued viability of refineries in the Eastern regions of North America will be 16 determined by many competitive factors. In IHS’ experience, it is often a combination of 17 factors that prompts a decision by a refiner to cease refining operations at a facility. A 18 profitable refinery operates, as does any other business, on the basis of sustained 19 positive operating margins. Comparative strength against its regional competitors (and 20 against refined products that enter the region from other refining locations) helps ensure 21 that a refinery will be able to withstand periodic shocks, cyclical market downturns or 22 capital expenditures required to meet product quality legislation.

23 If a refinery is able to secure feedstock at advantageous pricing, it is a significant 24 positive factor supporting operating margins, and therefore future operation as a going 25 concern. Based on our analysis, the re-reversal of Line 9 would provide a feedstock cost 26 incentive for the Quebec Refineries to process light crude sourced from Western 27 Canada and the U.S. Northern Tier, as a substitute for imported offshore supply.

28 Q.29. What is the expected impact of the Line 9 reversal on offshore Atlantic crude that 29 may be processed in the Quebec Refineries?

30 A.29. The Project may result in the displacement of Atlantic offshore crude runs from the 31 Quebec Refineries, to the extent that the available supply of Western Canadian crude is 32 priced favourably into Quebec. Other considerations may limit the substitution potential 33 for Western Canadian crude, such as common equity ownership in producing and 34 refining assets. Aside from these considerations, any domestic crude from the offshore 35 Atlantic that is displaced from Quebec is considered by IHS to be widely marketable to 36 refineries in other locations. The characteristics of the crude oils produced from the 37 region (typified by Hibernia and Terra Nova) are similar to light sweet crudes imported

49 Suncor has indicated its interest in potential oil sands integration with its Montreal refinery. Suncor Energy Inc., “Positioning for Long Term Growth”, Investor Information, May 2010, p.10.

1 into the U.S. PADD I region from other producing regions. In IHS’ opinion, there will be 2 no constraints to placing any displaced offshore Atlantic crude production into other 3 refining markets.

4 Q.30. Does this conclude IHS’ evidence?

5 A.30. Yes.

APPENDIX A:

1 CRUDE SOURCING AND SUPPLY OPTIMIZATION

2 All refineries are unique in terms of their configuration and processing capabilities. 3 Regardless of configuration, distillation is an essential unit operation in petroleum 4 refining. Distillation is a process of fractionation of a crude oil into its constituent 5 fractions, or “cuts”, which may be further processed in subsequent unit operations or 6 blended to produce finished products.50

7 The refining industries in the regions of interest for this study include a high proportion 8 of “cracking” or “medium conversion” refineries. 51 It should be noted that in the markets 9 of interest for this analysis, IHS considers cracking refineries to be the marginal (or 10 price-setting) configuration for establishing refined product prices and crude oil price 11 differentials.

12 Cracking refineries may process a range of different crude oils or other feedstocks. The 13 mix of crude oil and feedstocks will depend upon conversion capacity relative to crude 14 distillation capacity, market demand, crude oil availability, and other factors.

15 Coking refineries are more complex than cracking refineries, since the heaviest crude 16 oil fraction (vacuum residue) is processed in a coker to produce light product blending 17 components and byproduct coke. Hydroskimming and topping refineries are less 18 complex than cracking refineries, and do not have VGO conversion capacity.

19 One of the most significant decisions for a refiner is the choice of refinery feedstock. 20 The value of flexibility in crude sources derives from the ability to select among the 21 widest possible range of feedstocks, while meeting anticipated demand for products. 22 This will generally result from operations that maximize utilization of refinery conversion 23 units with streams produced from the lowest cost feedstocks.

24 It must be recognized that once a refinery is in operation, the ability to make material 25 variations in the crude supply is limited. Refineries that are configured to run a 26 significant proportion of light conventional crude will necessarily be constrained to 27 consideration of this type of crude by their capacity to convert all of the crude fractions 28 into valuable light products. Processing of alternative feedstocks, such as heavy crude, 29 will be generally inefficient in such a configuration. Similarly, refineries with a

50 In a fuels refinery, crude oil is generally fractionated, or distilled, into the following cuts, from lightest to heaviest: light ends, naphtha, kerosene, atmospheric diesel or gas oil, vacuum gas oil ( “VGO”), and vacuum residue. The “vacuum” designation for the latter two streams indicates that the streams are produced through vacuum (as opposed to atmospheric) distillation. 51 Refineries that have naphtha reforming, distillate hydrotreating and VGO conversion, or cracking. VGO cracking is indicated by Fluid Catalytic Cracking (“FCC”) capacity with alkylation and/or VGO hydrocracking capacity. The vacuum residue in cracking refineries is blended into residual fuel oil (“RFO”) or asphalt.

1 configuration that is suited to processing a significant proportion of heavy crude will be 2 less efficient in processing a light crude slate. Changes to a refinery crude slate are 3 major decisions, which involve a number of interrelated issues.

4 In practice, there are complexities that affect crude optimization decisions. Crude 5 selection will typically involve consideration of seasonal product demand and 6 specifications, as some crudes will be preferred for maximizing production of specific 7 products. If the refinery produces any specialty products, such as asphalt, lube base oil 8 or petrochemicals, the crude selection process is by nature more restrictive, based on 9 the need to secure crude oils that are suitable to the production of these products. The 10 availability of crude oils with specific quality characteristics may present unique 11 opportunities or challenges, which the refiner must consider within physical or market 12 constraints.

13 Processing of synthetic crude oil (“SCO”) and heavy crude (including bitumen blends 14 from the Canadian oil sands) will present certain challenges and opportunities. 15 Depending on the specific configuration and amount of crude being considered, major 16 capital projects may need to be undertaken to allow an existing refinery to make 17 substantial crude slate changes for SCO or bitumen blend. These constraints are of 18 particular interest in the context of the long term outlook for increasing surpluses of 19 Western Canadian crude. The issues associated with investment in capital projects are 20 considered in more detail below.

21 PARITY PRICING CONCEPTS

22 Parity pricing between crude oils is an important concept. In simple terms, the value 23 difference between two crudes at a given location is established by the aggregate value 24 of products produced from refining in the marginal (or price-setting) refinery 25 configuration for that location. The product yield (and hence the aggregate yield value) 26 for any two crudes will differ due to their inherent quality characteristics. Price parity 27 establishes the substitution value, or the refining value differential, of one crude relative 28 to another.

29 Another key concept in determining crude oil price relationships is the volume of trade 30 between regions. In most cases, transportation costs are a significant factor in 31 determining the flow of crude oils to markets. In the case of waterborne crude deliveries, 32 transportation costs can be optimized using tanker sizes that are appropriate to the 33 length of voyage and the capabilities of the loading and discharging ports. Because 34 downstream margins are quite narrow compared to the price of crude oil, small 35 differences in transportation costs can be an important driver in trade patterns.

36 Changes in crude flow patterns arise from changes in supply of crude oil (by type and 37 location), demand (by type and location), and other factors. The availability of new 38 resources and the depletion of others can lead to shifts in crude oil trade flows. Regional 39 demand patterns for light and heavy refined products will determine the general pattern

1 of crude demand, but it must be recognized that the refining infrastructure acts as a 2 constraint on the types of crude oils that can be processed, for the reasons described 3 above.

4 The above considerations are important in establishing potential sources of crude oil 5 that are available or may become available for Line 9 deliveries, in either an eastbound 6 or westbound direction. Price parity relationships are not static, but change over time. 7 Historical trends therefore do not provide a reliable basis for establishing future parity 8 pricing relationships. The key consideration in this regard is the location of the “clearing 9 market” for a given crude oil, which establishes the spot market price for that crude. 10 Prices for the same crude in other markets will be determined by transportation costs 11 from the point of origin.

12 IHS regularly assesses parity price relationships for key crude oils, taking into account 13 transportation and quality differentials. Supply, demand and other factors outlined above 14 are analyzed on a global basis, to establish expected patterns of trade for selected 15 crude oils.

16 THE INVESTMENT PROCESS

17 The refining industry is extremely competitive. Refineries are generally characterized by 18 high capital requirements and narrow operating margins. Refining margins are the 19 difference between what is paid for raw materials and the wholesale market prices for 20 the range of products produced, less operating costs. Of the factors affecting refining 21 margin, the choice of refinery feedstock is the most significant, given the high proportion 22 of costs represented by feedstock. The crude supply optimization process was 23 discussed above.

24 A refiner considering major changes to the crude slate would generally do so to take 25 advantage of favourably priced feedstocks. It may be that a parity shift has made certain 26 crude oils structurally more attractive than the historical crudes being processed. The 27 decision process may require the refiner to evaluate extensive modifications to an 28 existing refinery, and significant capital costs would generally be required to complete 29 such a project. The actual incremental investment will be highly case-specific, and 30 dependent upon many factors. The original configuration and the expected future 31 configuration, the size and location of the refinery, availability of spare plot space, 32 technology choice, external licensing and permitting requirements, logistical factors and 33 the degree of integration with other facilities are but a few of the issues that must be 34 considered. Another cost is the lost profit during the extended downtime that is required 35 for refinery tie-ins and modifications.

36 The magnitude of the capital investments involved in implementing significant changes 37 in crude slate is likely to act as a “barrier to entry” for such a project. The refiner 38 contemplating significant crude slate changes (such as those listed above) must 39 consider both the outlook for margin improvement that would be realized by

1 implementing a major project, as well as the expected capital and operating cost 2 required. Even in an environment where significant margin improvement is indicated, the 3 project is likely to face intense competition for capital and human resources.

4 Long lead times for planning and implementation add further complexity to the decision 5 process. In IHS’ experience, a thorough and disciplined approach to capital investment 6 decisions is generally followed. Prudent practice will consider not only the project 7 margins indicated at the time of the analysis (likely part of an annual budget review), but 8 also the future outlook. Project economics will depend on the outlook for future margins 9 after the project is completed, which may be substantially different if the projected 10 balance for the target crude does not materialize. In other words, the refiner considering 11 a crude slate change must assess whether an attractive opportunity for such a change is 12 likely to be persistent.

13 Additionally, the refiner who undertakes a crude slate conversion project in an operating 14 facility must work within the constraints imposed by periodic planned shutdowns. It 15 would be impractical from an economic perspective to shut the facility down outside of 16 these planned shutdown periods. Since shutdowns are typically scheduled on a 17 multi-year cycle, any delays in the planning for a major project may result in a 18 disproportionate extension of the project implementation timeline.

APPENDIX B:

1 TABLES

3 Table 1 Regional Refining Capacity: January 2013

4 Table 2 Major Pipeline Projects Connecting Oil Sands to Future Markets

5 Table 3 Crude Oil Delivery Costs to Montreal and Quebec City (Current)

6 Table 4 Crude Oil Delivery Costs to Montreal and Quebec City (Constant)

TABLE 1 REFINERY CAPACITY: JANUARY 2013 (1) (Barrels per Calendar Day)

Hydrocracking Region Company - Location Type (2) Crude Vacuum Coker FCC (Distillate/VGO) Asphalt

Quebec (3) Valero Energy Corp. - St. Romuald CRK 235,000 48,500 0 67,500 0 0 Suncor Energy Products - Montreal CRK 137,000 53,000 0 31,000 19,000 30,000 Total Quebec 372,000 101,500 0 98,500 19,000 30,000

Ontario Imperial Oil Ltd. - Sarnia COK 119,000 31,500 25,000 30,500 0 0 Imperial Oil Ltd. - Nanticoke CRK 113,500 48,000 0 48,500 0 10,000 Suncor Energy Products - Sarnia CRK 85,000 26,730 0 16,668 32,078 0 Novacor Chemicals (Canada) Ltd. - Corunna TOP 80,000 33,000 0 0 0 0 Shell Canada Ltd. - Sarnia CRK 71,000 24,400 0 14,000 6,300 0 Total Ontario 468,500 163,630 25,000 109,668 38,378 10,000

Atlantic Canada Irving Oil Ltd. - Saint John, NB CRK 250,000 100,000 0 95,000 34,000 0 North Atlantic Refining Ltd. - Come By Chance, NL CRK 115,000 55,000 0 0 38,000 0 Imperial Oil Ltd. - Dartmouth, NS CRK (4) 85,000 41,500 0 31,500 0 1,500 Total Atlantic Canada 450,000 196,500 0 126,500 72,000 1,500

U.S. Northeast PBF Energy Partners - Delaware City, DE COK 190,000 102,000 47,000 82,000 0 0 Phillips 66 - Linden, NJ CRK 238,000 71,250 0 138,000 0 0 PBF Energy Partners - Paulsboro, NJ COK 185,000 90,000 27,000 59,800 0 14,500 NuStar - Thorofare, NJ TOP 74,000 40,000 0 0 0 49,000 Sunoco Inc. - Westville, NJ N/A (5) 0 0 0 0 0 0 Delta Airlines/Monroe Energy - Marcus Hook, PA CRK 185,000 78,700 0 50,000 21,500 0 Sunoco Inc. - Marcus Hook, PA N/A (5) 0 0 0 0 0 0 Philadelphia Energy Solutions - Philadelphia, PA CRK 330,000 157,400 0 135,000 0 0 United Refining Co. - Warren, PA CRK 66,700 27,000 0 25,000 0 20,000 American Refining Group - Bradford, PA HDSK 10,000 0 0 0 0 0 Ergon West Virginia Inc - Newell, WV HDSK 20,000 8,400 0 0 0 550 Total PADD I 1,298,700 574,750 74,000 489,800 21,500 84,050

Notes: (1) Source: Oil & Gas Journal (December 3, 2012) and IHS estimates. Notes: (2) Type: COK = coking or high complexity; CRK = cracking or medium complexity; TOP or HDSK = simple or low complexity Notes: (3) Shell Montreal closed in 2010. Notes: (4) Imperial Oil announced in June 2013 that the Dartmouth refinery will be shut down. 1 Notes: (5) Refinery has ceased operations. No known plans to restart. 2 Table 1 Refinery Capacity: January 2013 3

TABLE 2 MAJOR PIPELINE PROJECTS CONNECTING OIL SANDS TO FUTURE MARKETS

Distance Capacity Proposed in- Destination Pipeline project (proponent) Route (km) (B/D) Status service date

Flanagan South (Enbridge) Flanagan, IL to Cushing, OK 960 585,000 Announced 2014

Keystone XL (TransCanada Pipelines) Hardisty, AB to Port Arthur, TX 2,750 1 700,000 Regulatory review 2015

Seaway reversal—Phase 1 US Gulf Coast 150,000 Operating 2012 (Enbridge/Enterprise Products) Seaway—Phase 2 Cushing, OK to Freeport, TX 800 250,000 Operating 2013 (Enbridge/Enterprise Products) Seaway—Phase 3 450,000 Application 2014 (Enbridge/Enterprise Products)

Alberta to Montreal and/or Quebec City, QC 300,000– Energy East (TransCanada Pipelines) 3,500 Announced 2017 and/or Saint John, NB 800,000

East Coast Line 9 Re-reversal (Line 9B) (Enbridge) Sarnia, ON to Montreal, QC 2 640 300,000 Regulatory review 2014

Portland to Montreal Pipeline Reversal Montreal, QC to South Portland, ME 380 140,000 Conceptual n/a (Montreal Pipe Line)

Northern Gateway Pipelines (Enbridge) Bruderheim, AB to Kitimat, BC 1,180 525,000 Regulatory review 2018 West Coast

Trans Mountain TMX Expansion Edmonton, AB to Westridge Marine Terminal in 1,150 590,000 Regulatory review 2017 (Kinder Morgan) Burnaby, BC

Source: Various sources and IHS analysis Notes: (1) Keystone XL consists of two parts. A 1,897-km (1,179-mi) leg from Hardisty, Alberta to Steele City, Nebraska, and a 780-km (485-mi) leg from Cushing, Oklahoma to Notes: (1) Nederland, Texas combined with a 76-km (47-mi) lateral to the Houston, Texas area (called the Gulf Coast Pipeline Project). Notes: (2) In July 2012 the National Energy Board of Canada approved the reversal of the 192-km section of Line 9 from Sarnia, ON to North Westover, ON ("Line 9A"). The reversal of the line from Montreal, QC to North Westover ("Line 9B") and an increase in capacity of the system are the subject of this application. 1 First published in January 2013 IHS CERA Special Report—Canadian Oil Sands Dialogue: Future Markets for Canadian Oil Sands. Updated July 2013. 2 Table 2 Major Pipeline Projects Connecting Oil Sands to Future Markets

TABLE 3 CRUDE OIL DELIVERY COSTS TO MONTREAL AND QUEBEC CITY (Current US Dollars per Barrel Unless Otherwise Noted)

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2025

Bonny Light Delivery Costs FOB, Bonny Terminal 81.30 113.11 112.84 106.58 98.14 97.68 100.43 103.60 107.01 110.50 113.52 124.73 Transportation to Portland, ME (1) 1.88 1.76 1.83 1.65 1.88 2.08 2.33 2.53 2.67 2.77 2.87 3.14 Losses & Insurance 0.21 0.29 0.29 0.27 0.25 0.25 0.26 0.27 0.27 0.28 0.29 0.32 Duties and Fees (2) 0.16 0.20 0.20 0.19 0.18 0.18 0.18 0.19 0.19 0.20 0.20 0.22 CIF Portland 83.54 115.36 115.16 108.70 100.45 100.20 103.20 106.58 110.14 113.75 116.88 128.40 PMPL to Montreal 0.94 1.47 1.84 1.55 1.59 1.61 1.63 1.65 1.67 1.69 1.71 1.82 CIF Montreal 84.48 116.83 117.00 110.25 102.04 101.81 104.84 108.23 111.82 115.44 118.59 130.23 Transportation Costs to Montreal 3.19 3.72 4.16 3.67 3.90 4.13 4.41 4.63 4.81 4.94 5.07 5.50 FOB, Bonny Terminal 81.30 113.11 112.84 106.58 98.14 97.68 100.43 103.60 107.01 110.50 113.52 124.73 Transportation to Quebec City, QC (1) 1.97 1.87 1.94 1.74 1.98 2.19 2.45 2.66 2.81 2.91 3.02 3.30 Losses & Insurance 0.21 0.29 0.29 0.27 0.25 0.25 0.26 0.27 0.27 0.28 0.29 0.32 Duties and Fees (2) 0.16 0.20 0.20 0.19 0.18 0.18 0.18 0.19 0.19 0.20 0.20 0.22 CIF Quebec City 83.64 115.47 115.26 108.78 100.54 100.31 103.33 106.71 110.28 113.90 117.03 128.57 Transportation Costs to Quebec City 2.34 2.36 2.43 2.20 2.41 2.62 2.89 3.11 3.28 3.40 3.51 3.84

Alberta Mixed Sweet (MSW) Delivery Costs FOB Edmonton 75.18 96.41 86.20 86.76 80.55 83.71 88.23 91.90 95.77 99.20 102.15 112.59 Transportation to Montreal, Low Toll 4.60 5.02 5.01 5.12 5.28 5.36 5.43 5.49 5.56 5.63 5.70 6.06 Transportation to Montreal, High Toll 5.35 6.56 7.20 7.32 7.50 7.58 7.68 7.77 7.87 7.97 8.07 8.59 Losses & Insurance ------CIF Montreal, Low Toll 79.78 101.43 91.21 91.88 85.83 89.07 93.65 97.39 101.34 104.83 107.85 118.66 CIF Montreal, High Toll 80.53 102.97 93.41 94.08 88.05 91.29 95.90 99.67 103.65 107.17 110.22 121.18 Transportation to Quebec City 0.88 0.96 0.90 1.00 1.11 1.20 1.31 1.39 1.45 1.49 1.54 1.68 CIF Quebec City, Low Toll 80.66 102.39 92.11 92.88 86.94 90.27 94.96 98.78 102.79 106.33 109.39 120.34 CIF Quebec City, High Toll 81.41 103.93 94.31 95.08 89.16 92.49 97.21 101.06 105.10 108.67 111.76 122.86

Bonny Light-MSW Refining Economics Refining Value Differential (MSW-Bonny Light) (1.44) (2.64) (2.93) (2.71) (2.49) (2.69) (2.64) (2.71) (2.81) (2.93) (3.03) (3.45) Montreal Bonny Light-MSW, Quality Adjusted (Low) (3) 3.26 12.76 22.86 15.66 13.73 10.05 8.54 8.13 7.67 7.68 7.71 8.12 Bonny Light-MSW, Quality Adjusted (High) (3) 2.51 11.22 20.66 13.46 11.50 7.82 6.29 5.85 5.36 5.34 5.34 5.59 Quebec City Bonny Light-MSW, Quality Adjusted (Low) (3) 1.54 10.44 20.22 13.19 11.12 7.34 5.73 5.22 4.69 4.64 4.61 4.78 Bonny Light-MSW, Quality Adjusted (High) (3) 0.79 8.90 18.03 10.99 8.90 5.12 3.48 2.95 2.38 2.30 2.24 2.25

Notes: (1) Assumes Suezmax delivery from FOB load port to destination. Working capital costs have been excluded. Notes: (2) Includes applicable crude oil import duties, harbour fees and other charges. Notes: (3) Positive differential is indicative of favourable Line 9 crude delivery economics in eastbound operation. 1 Table 3 Crude Oil Delivery Costs to Montreal and Quebec City (Current U.S. Dollars)

TABLE 4 CRUDE OIL DELIVERY COSTS TO MONTREAL AND QUEBEC CITY (Constant 2011 US Dollars per Barrel Unless Otherwise Noted)

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2025

Inflation Factor (2011 = 1.00) 1.00 1.00 1.02 1.03 1.05 1.07 1.08 1.10 1.12 1.13 1.15 1.26

Bonny Light Delivery Costs FOB, Bonny Terminal 81.30 113.11 110.88 103.35 93.49 91.64 92.82 94.31 95.87 97.40 98.39 98.96 Transportation to Portland, ME (1) 1.88 1.76 1.80 1.60 1.79 1.96 2.15 2.30 2.39 2.44 2.49 2.49 Losses & Insurance 0.21 0.29 0.28 0.26 0.24 0.23 0.24 0.24 0.25 0.25 0.25 0.25 Credit terms (2) ------Duties and Fees (2) 0.16 0.20 0.20 0.19 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 CIF Portland 83.54 115.36 113.16 105.40 95.69 94.00 95.38 97.03 98.68 100.27 101.30 101.88 PMPL to Montreal 0.94 1.47 1.81 1.51 1.52 1.51 1.51 1.50 1.50 1.49 1.49 1.44 Losses & Insurance ------Credit terms (1) ------CIF Montreal 84.48 116.83 114.97 106.90 97.21 95.51 96.89 98.53 100.18 101.76 102.79 103.32 Transportation Costs to Montreal 3.19 3.72 4.09 3.56 3.72 3.87 4.07 4.22 4.31 4.36 4.40 4.36 FOB, Bonny Terminal 81.30 113.11 110.88 103.35 93.49 91.64 92.82 94.31 95.87 97.40 98.39 98.96 Transportation to Quebec City, QC (1) 1.97 1.87 1.91 1.68 1.88 2.06 2.27 2.42 2.52 2.57 2.61 2.62 Losses & Insurance 0.21 0.29 0.28 0.26 0.24 0.23 0.24 0.24 0.25 0.25 0.25 0.25 Duties and Fees (2) 0.16 0.20 0.20 0.19 0.17 0.17 0.17 0.17 0.17 0.17 0.18 0.17 CIF Quebec City 83.64 115.47 113.26 105.48 95.78 94.10 95.49 97.15 98.80 100.39 101.43 102.01 Transportation Costs to Quebec City 2.34 2.36 2.38 2.13 2.29 2.46 2.68 2.83 2.93 2.99 3.04 3.05

Alberta Mixed Sweet (MSW) Delivery Costs FOB Edmonton 75.18 96.41 84.71 84.13 76.74 78.53 81.54 83.66 85.80 87.44 88.54 89.34 Transportation to Montreal, Low Toll 4.60 5.02 4.92 4.96 5.03 5.03 5.02 5.00 4.99 4.97 4.94 4.81 Transportation to Montreal, High Toll 5.35 6.56 7.08 7.10 7.14 7.11 7.09 7.08 7.05 7.03 7.00 6.81 Losses & Insurance ------Credit terms (1) ------CIF Montreal, Low Toll 79.78 101.43 89.63 89.09 81.76 83.56 86.55 88.67 90.79 92.41 93.48 94.15 CIF Montreal, High Toll 80.53 - 102.97 - 91.79 - 91.23 - 83.88 - 85.64 - 88.63 - 90.74 - 92.86 - 94.47 - 95.53 - 96.15 - Transportation to Quebec City 0.88 0.96 0.88 0.97 1.06 1.13 1.21 1.26 1.30 1.32 1.33 1.34 CIF Quebec City, Low Toll 80.66 102.39 90.51 90.06 82.82 84.69 87.76 89.93 92.09 93.72 94.81 95.48 CIF Quebec City, High Toll 81.41 103.93 92.67 92.20 84.94 86.77 89.84 92.00 94.16 95.79 96.87 97.48

Bonny Light-MSW Refining Economics Refining Value Differential (MSW-Bonny Light) (1.44) (2.64) (2.88) (2.63) (2.37) (2.53) (2.44) (2.46) (2.52) (2.58) (2.62) (2.74) Montreal Bonny Light-MSW, Quality Adjusted (Low) (3) 3.26 12.76 22.46 15.19 13.08 9.42 7.89 7.40 6.87 6.77 6.69 6.44 Bonny Light-MSW, Quality Adjusted (High) (3) 2.51 11.22 20.30 13.05 10.96 7.34 5.82 5.33 4.80 4.71 4.63 4.44 Quebec City Bonny Light-MSW, Quality Adjusted (Low) (3) 1.54 10.44 19.87 12.79 10.59 6.89 5.29 4.76 4.20 4.09 4.00 3.79 Bonny Light-MSW, Quality Adjusted (High) (3) 0.79 8.90 17.71 10.66 8.48 4.80 3.21 2.68 2.13 2.03 1.94 1.79

Notes: (1) Assumes Suezmax delivery from FOB load port to destination. Working capital costs have been excluded. Notes: (2) Includes applicable crude oil import duties, harbour fees and other charges. Notes: (3) Positive differential is indicative of favourable Line 9 crude delivery economics in eastbound operation. 1 Table 4 Crude Oil Delivery Costs to Montreal and Quebec City (Constant U.S. Dollars)

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APPENDIX C:

1 DATA TABLES

2 Figure 1 Quebec Crude Slate

3 Figure 2 Quebec Crude Sources

4 Figure 3 Quebec Crude Import Sources

5 Figure 4 Ontario Crude Slate

6 Figure 5 Atlantic Canada Crude Slate

7 Figure 6 PADD I Crude Slate

8 Figure 9 Crude Oil Price Forecast

1 FIGURE 1

FIGURE 1: QUEBEC CRUDE SLATE (1) (Thousand Barrels per Day) 2009 2010 2011 2012 Conventional Light 366 320 287 311 Conventional Heavy 44 69 42 33 Synthetic Crude 2 0 5 4 Crude Bitumen 0 0 0 0 Condensate and Pentanes 0 0 0 0 Total 412 388 334 348 Notes: (1) Source: Statistics Canada, Statistical Series 45-004 2

3 FIGURE 2

FIGURE 2: QUEBEC CRUDE SOURCES (1) (Thousand Barrels per Day) 2009 2010 2011 2012 Western Canada 2 0 3 1 Eastern Canada 38 52 24 26 Imports (2) 373 335 302 322 Total 413 387 329 349 Notes: (1) Source: Statistics Canada, statistical series 45-004 (2) Includes US imports, 0 2 0 0 and non-US imports 373 333 302 322 4

5 FIGURE 3

FIGURE 3: QUEBEC CRUDE IMPORT SOURCES (1) (Thousand Barrels per Day) 2009 2010 2011 2012 OPEC 163 148 163 158 North Sea (Norway & UK) 98 81 50 26 North America (US & Mexico) 22 20 14 22 Other 90 87 74 115 Total 373 335 302 322 Notes: (1) Source: Statistics Canada, statistical series 45-004 6

1 FIGURE 4

FIGURE 4: ONTARIO CRUDE SLATE (1) (Thousand Barrels per Day) 2009 2010 2011 2012 Conventional Light 186 234 214 246 Conventional Heavy 29 47 50 42 Synthetic Crude 81 60 69 71 Crude Bitumen 30 15 15 10 Condensate and Pentanes 11 6 4 2 Total 338 363 352 371 Notes: (1) Source: Statistics Canada, statistical series 45-004 2

3 FIGURE 5

FIGURE 5: ATLANTIC CANADA CRUDE SLATE (1) (Thousand Barrels per Day) 2009 2010 2011 2012 Conventional Light 407 432 414 442 Conventional Heavy 18 3 3 4 Synthetic Crude 0 0 0 0 Crude Bitumen 0 0 0 0 Condensate and Pentanes 0 0 0 0 Total 425 435 416 446 Notes: (1) Source: Statistics Canada, statistical series 45-004 4

5 FIGURE 6

FIGURE 6: PADD I CRUDE SLATE (1) (Thousand Barrels per Day) 2009 2010 2011 2012 Light Sweet 867 831 769 659 Light Sour 94 136 164 148 Heavy 299 151 160 137 Total 1,258 1,118 1,094 944 Notes: (1) Sources: U.S. Dept of Energy (EIA), IHS estimates 6

1 FIGURE 9

FIGURE 9: CRUDE OIL PRICE FORECAST (Current Dollars per Barrel) 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Dated Brent, FOB 28.50 24.44 25.02 28.83 38.27 54.52 65.14 72.39 97.26 61.67 79.50 111.26 111.67 WTI, Spot Cushing 30.37 25.93 26.16 31.06 41.49 56.59 66.04 72.20 100.06 61.92 79.45 95.04 94.13 Bonny Light, FOB 28.51 24.52 25.14 28.77 38.30 55.76 67.05 74.88 101.20 63.73 81.30 113.11 112.84 MSW, Edmonton 29.79 25.25 25.48 30.68 40.43 56.52 63.60 71.53 97.42 58.09 75.18 96.41 86.20

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Dated Brent, FOB 103.59 94.47 93.80 96.30 99.41 102.69 106.07 109.03 111.50 113.50 115.55 117.62 119.73 WTI, Spot Cushing 93.69 89.39 89.39 92.78 96.45 100.32 103.77 106.77 109.24 111.23 113.26 115.31 117.56 Bonny Light, FOB 106.58 98.14 97.68 100.43 103.60 107.01 110.50 113.52 116.10 118.20 120.33 122.50 124.73 MSW, Edmonton 86.76 80.55 83.71 88.23 91.90 95.77 99.20 102.15 104.56 106.48 108.43 110.41 112.59 2

APPENDIX D: RESUME OF PROFESSIONAL QUALIFICATIONS STEVEN J. KELLY

1 EDUCATION

2 B.Eng. Chemical Engineering from McMaster University (Hamilton, Ontario) in 1982.

3 M.Eng. Chemical Engineering from McMaster University (Hamilton, Ontario) in 1985.

4 M.B.A. from University of Calgary (Calgary, Alberta) in 1998.

5 PROFESSIONAL ASSOCIATIONS

6 Association of Professional Engineers and Geoscientists of Alberta (APEGA)

7 Canadian Heavy Oil Association

8 CURRENT POSITION

9 Vice President, Downstream Energy Consulting, IHS Calgary

10 WORK EXPERIENCE

11 Mr. Kelly joined Purvin & Gertz (acquired by IHS in 2011) in 1996, and has applied his 12 experience in the analysis of crude oil and petroleum markets as a consultant for more than 17 13 years. His focus has been on markets in Canada, the U.S. Midwest and the Pacific Rim. Mr. 14 Kelly has assisted numerous crude oil producers in the development of marketing strategies. 15 His experience includes projects for a variety of conventional light, heavy and synthetic crude 16 oils. Through these assignments, Mr. Kelly has developed significant expertise in heavy crude 17 upgrading. Mr. Kelly has significant experience with logistical issues, and has assisted clients in 18 a range of petroleum transportation studies. In addition, he has worked with Purvin & Gertz 19 study teams in the simulation and modeling of refineries and has assisted clients in a number of 20 competitive analysis studies.

21 Mr. Kelly managed the firm’s European market analysis activities while on a foreign 22 assignment (August 2001 through July 2005). He returned to Calgary in July 2005 and assumed 23 the role of Calgary office manager in January 2006.

24 Mr. Kelly joined Purvin & Gertz from Shell Canada Limited, where he was involved in 25 manufacturing and supply optimization activities at their corporate headquarters. In t hat 26 capacity, he identified short-term profitability opportunities for Shell’s Canadian refining 27 operations. He participated in several strategic planning and re-engineering studies, and has

1 extensive experience with the use and construction of optimization models. Mr. Kelly worked as 2 a refinery operations engineer at Shell’s Scotford Refinery. Mr. Kelly has a graduate degree in 3 process control, and has developed applications for a wide range of refinery units. Prior to 4 joining Shell Canada, Mr. Kelly was employed by Polysar Limited for two years at its Sarnia 5 manufacturing facility, as a process engineer.

6 REPRESENTATIVE MAJOR PROJECT EXPERIENCE

7 MARKET ANALYSIS

8  CRUDE OIL & OIL SANDS MARKET OUTLOOK – Mr. Kelly was a co-developer of 9 this service, which presented long range outlooks for North American crude oil 10 supply, disposition and pricing, with a focus on the Canadian oil sands. The service 11 included detailed crude balances and refining industry analysis, as well as regional 12 crude and refined products pricing and refining margins.

13  GLOBAL MARKETS FOR CANADIAN OIL SANDS CRUDES - Mr. Kelly directed this 14 major multiclient study, which investigated supply, disposition and pricing issues for 15 a range of crudes available from the Canadian oil sands. The study considered 16 markets in North America and selected Northeast Asian countries, economics of 17 various upgrading configurations, production and trade scenarios, and analysis of 18 infrastructure requirements for Canadian crude exports.

19  GLOBAL PETROLEUM MARKET OUTLOOK – Mr. Kelly has prepared many 20 contributions to this major multi-client service. The service covered refined product 21 demand projections for each country, trade balances, and refining industry analysis. 22 Mr. Kelly completed detailed analysis of petroleum demand projections for Europe 23 (while on an overseas posting), and contributed to the analysis of the North 24 American petroleum outlooks.

25  INTRODUCTION TO UPGRADING, REFINING & ECONOMICS COURSE – Mr. Kelly 26 developed the content and manages this two-day course, and participates as an 27 instructor. The course provides attendees with a unique introduction to the 28 downstream petroleum sector, with particular focus on issues of interest to 29 Canadian oil sands industry players. The course has been offered twice annually 30 since 2008.

31  EUROPEAN MARKET ANALYSIS – Mr. Kelly had responsibility for the European 32 edition of Purvin & Gertz’ monthly Crude Oil & Refining Outlook service while on an 33 overseas posting. This multi-client service provides ongoing analysis of European 34 products supply/demand trends and refining operations, and develops projections of 35 refining margins and crude oil and refined product prices.

36  OUTLOOK FOR RUSSIAN PETROLEUM TRADE TO EUROPE - Mr. Kelly directed this 37 multi-client study that investigated regional demand and trade issues for Europe 38 and adjacent CIS countries. Crude oil production and logistics in Russia were 39 evaluated, as a driver of refining activity and product surpluses. The study included

1 regional balances for Russia and the interface countries, as well as pricing 2 dynamics for crude oil and products at selected points within Russia.

3  CRUDE OIL & REFINING OUTLOOK – For five years, Mr. Kelly prepared the U.S. 4 Midwest/Canadian edition of this monthly multi-client service, which provided 5 in-depth analysis of the supply/demand balance for Canadian crudes, and 6 equilibrium pricing relationships between benchmark crudes. Mr. Kelly was 7 responsible for ongoing monitoring of U.S. Midwest petroleum product markets, 8 including supply/demand balances, pricing and refining margins.

9  INTERNATIONAL CONDENSATE SUPPLY/DEMAND – As part of a wide-ranging 10 study of LPG and condensate markets, carried out in support of a proposed 11 investment in North African exploration and production, Mr. Kelly analyzed 12 international condensate production projects, splitting/refining projects, and 13 condensate demand trends. Analysis included development of inter-regional trade 14 matrices, which were used in conjunction with other information to assess the price 15 setting mechanisms for various condensates.

16  HEAVY CRUDE MARKET STUDY - Mr. Kelly was the director of a large multiclient 17 study, which investigated supply, disposition and pricing issues for heavy crude. 18 The scope of the study covered Western Hemisphere production regions, and 19 considered the key market regions in Canada and the U.S. Strategic issues facing 20 market participants were investigated.

21  NATURAL GAS/NGL MARKET ANALYSIS - Mr. Kelly has been involved in a number 22 of studies related to natural gas and NGL markets. Studies have included an 23 evaluation of supply/demand fundamentals and forecasts of North American 24 regional natural gas prices. Mr. Kelly has also prepared long-range natural gas and 25 NGL price forecasts.

26 CRUDE OIL/REFINED PRODUCTS MARKETS AND LOGISTICS

27  WILLISTON BASIN CRUDE MARKET STUDY: The market and logistical forces 28 behind severe discounting of crude produced in the Williston Basin area of Montana 29 and North Dakota were studied for an industry group by a Purvin & Gertz team led 30 by Mr. Kelly. The study estimated the impact of proposed pipeline solutions and the 31 potential for restrictions on pipeline crude qualities.

32  NORTH DAKOTA REFINING CAPACITY ANALYSIS: Steven led PGI’s activities for 33 this study. Purvin & Gertz was part of a study team that evaluated the implications of 34 additional refining capacity potentially being developed in North Dakota. PGI’s 35 analysis included crude oil and refined products price impacts, and was based on 36 logistical optimization models developed for the assignment.

37  CRUDE EXPORT PIPELINE QUALITY BANK DESIGN - PGI advised a consortium on 38 the design of a quality bank for a major crude export pipeline. Mr. Kelly managed Purvin 39 & Gertz activities on this assignment, which included identification of potential crude oils

1 that may be served by the pipeline, and analysis of different options for the mechanism 2 of the quality bank and formulation of proposals to the consortium.

3  CRUDE OIL MARKETS AND PRICING FOR CASPIAN CRUDE - On behalf of a 4 consortium of crude oil producers in the Caspian region, Steven directed a study of the 5 likely markets for the potential export stream. Markets analyzed included Europe, the 6 Far East, the U.S. and Latin America. Pricing projections were based on full refining 7 value analysis from available crude assay data. Netback values to the assumed load 8 port were calculated.

9  CRUDE OIL VALUATION AND MARKETING – Steven has undertaken several 10 assignments to value new crude oil production streams relative to internationally traded 11 crudes. In many cases the value of the new crude has been developed both as a stand- 12 alone production stream and as a component of a commingled stream in a common 13 carrier pipeline system. This work has also involved assisting in developing marketing 14 strategies, identifying potential buyers with favorable logistics and appropriate refining 15 capacity.

16  CRUDE EVALUATION MODELLING - Mr. Kelly participated on a Purvin & Gertz study 17 team that prepared models of refining valuations for a major Middle Eastern crude 18 producer. His objective in this study was to define refinery configurations for the 19 European markets that could potentially process crude oil from the client, and develop 20 real-time models for refining value differentials against defined benchmark crude oils.

21  CRUDE OIL MARKET ANALYSIS - Mr. Kelly has developed refining values and 22 comparative economics for many North American, North Sea and various other 23 international crude oils. This work has been completed in numerous single client 24 projects. Through this work Mr. Kelly has developed specific expertise in the valuation of 25 synthetic crude oils.

26 REGULATORY ASSISTANCE

27  PIPELINE TOLL HEARING – Mr. Kelly acted as an independent expert in a toll 28 hearing before the National Energy Board, relating to the proposed tolling 29 methodology for a major capacity expansion to an existing pipeline system in 30 Western Canada. He prepared direct evidence, provided advice and input for 31 information requests, and provided oral testimony at the hearing.

32  THROUGHPUT ANALYSIS – Mr. Kelly led the firm’s activities in support of a 33 National Energy Board application being prepared by a pipeline company with 34 operations in Western Canada. PGI developed throughput forecasts for the pipeline 35 under a range of input premises.

36  PIPELINE TOLL HEARINGS – Mr. Kelly provided consulting assistance to an 37 intervenor in two separate regulatory applications relating to a crude oil pipeline in 38 Eastern Canada. He prepared direct evidence relating to alternative uses of the

1 pipeline facilities, and participated in the information request process. In each case, 2 the matter was resolved prior to proceeding to an NEB oral hearing.

3  PIPELINE TOLL HEARING – Mr. Kelly provided consulting assistance to an 4 intervenor in a regulatory application relating to a crude oil pipeline in British 5 Columbia. He prepared direct evidence relating to future utilization of the pipeline, 6 and participated in the information request process. The matter was resolved prior 7 to proceeding to an oral hearing.

8  PIPELINE FACILITIES HEARING – As part of a study team engaged by a group of 9 producers, Mr. Kelly participated as an independent expert in a facilities hearing 10 before the National Energy Board, relating to the proposed reversal of an oil 11 pipeline in Eastern Canada. He prepared direct evidence, provided advice and input 12 for information requests, and provided oral testimony.

13  LEADED GASOLINE ADDITIVES – Steven led the company’s activities in providing 14 consulting support to a legal firm, engaged in a dispute relating to a supply contract 15 for the leaded gasoline additive, tetraethyllead (TEL). This involved analysis of the 16 technical and commercial aspects of TEL production, and review of global markets 17 for leaded gasoline.

18 STRATEGIC BUSINESS ADVICE

19  PORT STRATEGIC PLAN – A North European port commissioned Purvin & Gertz to 20 conduct a strategic planning study. Mr. Kelly led the study. In light of potential 21 changes in the port’s business environment, the assignment focused on 22 identification and ranking of alternative businesses that could be developed at the 23 facility. Purvin & Gertz provided an analysis and ranking of a wide range of options, 24 after evaluating the business environment.

25  FUELS REFINERY INVESTMENT ANALYSIS – A European refiner facing significant 26 refinery investments to produce ultra-low sulfur fuels commissioned Purvin & Gertz 27 to evaluate several alternatives. Mr. Kelly led the company’s efforts to simulate 28 current refinery capabilities, using a proprietary optimization model. A detailed 29 analysis was completed, to assess the impact of each alternative on the forecast 30 refining margin.

31  CRITICAL REVIEW OF BUSINESS PLAN – As part of an independent review of a 32 proposed privatization, Steven was required to review the future earning projections 33 relating to petroleum retailing outlets in India. Opinions were developed to realistic 34 target penetrations that could be achieved and issues were raised concerning the 35 impact of delays in foreseen regulatory changes.

36  EUROPEAN LIGHT PRODUCTS MARKETS STUDY – In support of a client’s analysis 37 of condensate disposition options, Mr. Kelly was closely involved in an analysis that 38 studied a range of alternatives to process or to sell a new condensate stream. In 39 addition to analyzing refining investments and economics, the study examined the

1 outlook for markets for light products, and particularly for gasoline and naphtha 2 markets.

3  REFINING STRATEGIC STUDY - A refiner with multiple operations engaged Purvin & 4 Gertz to analyze its competitive position among its peer group. Detailed LP 5 analyses were used to assess crude slate and product yield profitability of refineries 6 in the study group. Study recommendations allowed the client to improve its 7 competitive position.

8  MIDWEST/CANADIAN REFINING STRATEGIC STUDY - As part of a study team, Mr. 9 Kelly was involved in an evaluation of U.S. Midwest and Ontario refiners in the 10 current and future business environment. Refineries were modeled using Purvin & 11 Gertz’ proprietary LP and operating cost models. Comparative margins were 12 developed for each refinery. Regional profitability rankings were compiled, and a 13 number of recommendations were tabled.

14  HEAVY OIL DILUENT STRATEGIC STUDY - Mr. Kelly was part of a Purvin & Gertz 15 study team engaged to evaluate strategic options for a heavy crude oil producer, 16 relative to the availability and pricing of diluent. The results of the study included 17 recommendations for strategic management of diluent supply.

18  CANADIAN REFINING INDUSTRY COMPETITIVENESS STUDY - Mr. Kelly worked as 19 part of a Purvin & Gertz study team, engaged to evaluate the competitiveness of the 20 Canadian refining industry, in the current business climate and with varying degrees 21 of fuel reformulation. Detailed LP models and operating cost models were prepared 22 for the refineries in the study group. Cash flow models were developed to assess 23 the impact of fuel sulphur reduction on these refineries. The strategic implications 24 of fuel reformulation were assessed, for individual refineries and regional segments 25 of the Canadian industry.

26  HEAVY CRUDE MARKET EVALUATION - A group of heavy crude producers retained 27 PGI to investigate potential market growth opportunities for heavy crude. Mr. Kelly 28 was responsible for evaluating comparative refining values for key grades. He also 29 estimated capital expenditures and processing economics for a number of refineries 30 that were identified as candidates to run heavy crude.

31  BITUMEN UPGRADING STUDY - Mr. Kelly developed a series of heavy oil upgrading 32 schemes that were analyzed for a study evaluating opportunities to expand bitumen 33 markets. The case studies were prepared for an industry group interested in a 34 variety of options ranging from no field upgrading to full upgrading to synthetic 35 crude. A key part of this assignment was the development of partial upgrading 36 options, integration with petroleum refiners, and identification of the technical and 37 economic issues associated with these types of projects.

38  SYNTHETIC CRUDE MARKET STUDY - Mr. Kelly has directed and participated in 39 numerous studies for current and potential Western Canadian synthetic crude 40 producers. The studies have investigated strategic options for the expansion of 41 existing refining markets for oil sands production. Through this work he has

1 considered markets across North America, and modeled all potential synthetic 2 crude refiners.

3  CLIMATE CHANGE OPTIONS PAPER - Mr. Kelly directed a study that analyzed the 4 cost and competitiveness impacts on the Canadian refining industry, of selected 5 technical options for greenhouse gas emission reductions. The analysis included 6 development of project capital and operating costs for all Canadian fuels refineries. 7 GHG reduction potential and regional economic impacts on the industry were 8 assessed, and an analysis of refinery viability under different policy options was 9 developed.