ENBRIDGE ENERGY, LIMITED PARTNERSHIP MINNESOTA...

59842350

ENBRIDGE ENERGY, LIMITED PARTNERSHIP

MINNESOTA PUBLIC UTILITIES COMMISSION

MPUC DOCKET NO. PL9/CN-14-916 OAH DOCKET NO. 65-2500-32764

DIRECT TESTIMONY OF NEIL EARNEST

January 31, 2017

Earnest Direct CN Testimony, Ex. ___

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I. BACKGROUND AND EXPERIENCE 1

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

A. My name is Neil K. Earnest. I am President of Muse, Stancil & Co. (“Muse”), assigned to the 3

firm’s corporate headquarters located at 5080 Spectrum Dr., Suite 600E, Addison, Texas 4

75001. 5

6

Q. Please briefly describe your educational and professional background. 7

A. I hold a Bachelor of Science degree in Chemical Engineering from Michigan State University 8

and an M.B.A. degree from the University of Houston – Clear Lake. I am a Texas-registered 9

Professional Engineer in the discipline of chemical engineering. My curriculum vitae is 10

attached as Schedule 1. 11

12

My 30+ years of professional experience has been primarily acquired in the crude oil refining 13

and other closely related industries. As a consultant, I have worked on a broad range of 14

refining assignments around the world. In recent years, I have directed a number of 15

engagements concerning the supply and demand for Western Canadian crude oils in the 16

North American market as well as studies considering the supply and demand for refined 17

petroleum products in North America. Prior to joining Muse in 1991, I was with Phillips 18

Petroleum Company for 11 years in a variety of refinery and headquarters positions. 19

20

Q. What is Muse? 21

A. Muse is an international energy consulting firm with its headquarters in the Dallas area with 22

additional offices in Houston and London. The company was established in 1984 and is 23

employee-owned. Most of the firm’s consultants are engineers with direct industry 24

experience and wide-ranging consulting expertise. 25

26

Muse professionals provide a combination of technical and economic services to assist 27

clients in the evaluation of issues and opportunities in the energy sector. Our engagements 28

include market analyses, project development, project feasibility analyses, mergers and 29

acquisition advisory, due diligence assessment, and litigation and regulatory support 30

services. The company is routinely retained to assist clients with interests in the 31

downstream energy industry including crude oil and natural gas marketing, hydrocarbon 32

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transportation, crude oil refining, gas processing, refined products distribution and 33

marketing, and gas transmission and distribution. 34

35

Q. What was your role in developing the Certificate of Need application (the 36

“Application”) to the Minnesota Public Utilities Commission for the Line 3 37

Replacement Program (the “L3R Program”)? 38

A. Enbridge engaged Muse to analyze both the supply and demand for crude oil and to 39

estimate the utilization of the Enbridge Mainline System to help determine if there is 40

sufficient need for the restored pipeline capacity to support construction of the L3R Program. 41

I prepared a report, “Enbridge Line 3 Replacement Project Market Analysis”, detailing my 42

analysis and conclusions, which can be found in Appendix C of the Application. 43

44

Q. Have you conducted additional analysis regarding the L3R Program since the 45

Application was filed? 46

A. Yes. Enbridge engaged Muse to update the analysis provided in the Application. I prepared 47

an updated report (the “Muse Report”), dated January 2017, which is attached as Schedule 48

2 to my testimony. 49

50

Q. What is the purpose of your testimony? 51

A. The purpose of my testimony is to summarize the analyses and conclusions contained in the 52

Muse Report. Topics that are specifically discussed in this testimony include: 53

• The historical and projected demand for refined petroleum products in 54 Minnesota, consistent with the requirements of Minn. R. 7853.0510; 55

• The historical and projected demand for refined petroleum products in the states 56 that neighbor Minnesota, consistent with the requirements of Minn. R. 57 7853.0510; 58

• The degree of interdependency between the Minnesota refineries and other 59 Midwestern refineries for the requirement to meet the need for key refined 60 products by the people of Minnesota; 61

• The current sources of crude oil supply for refineries in Minnesota and its 62 neighboring states; 63

• A comparison of Western Canadian crude oil supply forecast data between the 64 publicly-available independent sources. 65

• The regional submarkets for crude oil in North America that are served by the 66 Enbridge Mainline System, of which Line 3 is a part; and 67

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• The projected utilization of the two Enbridge Mainline System segments in 68 Minnesota with and without the L3R Program, and further provide a quantitative 69 assessment of the impact of the L3R Program on non-Enbridge crude oil 70 transportation modes and on the overall market disposition for crude oil in North 71 America. 72

II. DEMAND FOR PETROLEUM PRODUCTS IN MINNESOTA AND NEIGHBORING STATES 73

74

Q. What percentage of Minnesota’s energy requirements are derived from petroleum? 75

A. In 2014, the most recent year for which data are available at the state level, petroleum met 76

30.5 percent of total Minnesota energy supply. Figure 1 below provides the composition of 77

Minnesota energy supply over the last 20 years and, as can be observed, petroleum has 78

long been an essential supply source for Minnesota. 79

80

81

Figure 1 above illustrates that the proportion of total Minnesota energy supply representing 82

petroleum has been slowly declining over the last 20 years. However, this is more 83

attributable to total energy demand increasing with petroleum demand remaining relatively 84

constant, rather than petroleum demand itself significantly decreasing. These trends are 85

reflected in Figure 2 below, which restates total Minnesota energy supply in terms of trillions 86

of BTUs per year. 87

0%

20%

40%

60%

80%

100%

Composition of Minnesota Energy Supply

Petroleum Coal Net Electricity Imports Natural Gas Nuclear RenewablesSource: EIA

Figure 1

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88

89

Q. Minnesota is a leader in ethanol and other renewable and energy conservation 90

policies. Have these policies led to a decrease in the use of petroleum products in 91

Minnesota? 92

A. They undoubtedly have had an effect on petroleum demand, although the precise impact is 93

somewhat difficult to measure. For example, fuel ethanol in 2014 comprised about 94

1.3 percent of the total Minnesota energy supply, up from about 0.8 percent in 1994. Much 95

of the increase in fuel ethanol supply has likely been at the expense of petroleum-based 96

gasoline. 97

98

Q. Are renewable energy efforts anticipated to substantially reduce the use of petroleum 99

products in Minnesota over the forecast period? 100

A. No. In 2014, essentially all of the gasoline in Minnesota sold at the retail pump contained at 101

least 10 volume percent fuel ethanol. That volume comprised only about 1.3 percent of the 102

total Minnesota energy supply in 2014, whereas refined products constituted 30.8 percent. 103

Even if the fuel ethanol consumption were to triple in Minnesota, entirely at the expense of 104

petroleum consumption, refined products would still satisfy about 28 percent of the total 105

Minnesota energy supply. Petroleum would still be the single largest source of energy for 106

the people of Minnesota. 107

108

Q. Are electric vehicles anticipated to substantially reduce the use of petroleum 109

products in Minnesota over the forecast period? 110

Figure 2

0

500

1,000

1,500

2,000

2,500

Trill

ions

of B

TUs

per Y

ear

Sources of Minnesota Energy Supply


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A. No. There is no combination of renewable fuel or electrical car initiatives that promise to 111

reduce gasoline and diesel demand such that it could be met by local supply over the 112

forecast period. 113

114

Q. What are the primary uses of petroleum products in Minnesota? 115

A. The transportation sector consumes approximately 70 percent of the total Minnesota supply 116

of petroleum products, as shown in Figure 3 below. Most of the remainder (~20 percent) is 117

consumed by the industrial sector. Major uses of petroleum products in the industrial sector 118

include asphalt for road construction and agriculture-related diesel demand. 119

Q. Do Minnesota’s two refineries, Flint Hills Pine Bend and Northern Tier Energy St. Paul 120

Park, provide all of the petroleum products consumed in Minnesota? 121

A. No. For some specialty petroleum products, such as lubricants, refineries in other states (or 122

imports) satisfy the entire state demand, as the Minnesota refineries do not produce these 123

specialty products. Absent access to the private information of the two Minnesota refineries, 124

the proportion of Minnesota petroleum product demand that is specifically met by Minnesota 125

refineries cannot be precisely calculated. However, a rough estimate can be made of the 126

proportion of the Minnesota transportation fuel demand (gasoline and diesel) that is satisfied 127

by the two local refineries. 128

129

During a 2013 interview with a Minnesota House of Representative legislative analyst, the 130

director of communications for the privately-held Flint Hills company disclosed that the Pine 131

Figure 3

0100200300400500600700800

Trill

ions

of B

TUs

per

Year

Sources of Minnesota Petroleum Demand

Transportation Commercial Industrial Electric Power Generation ResidentialSource: EIA

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Bend refinery is estimated to produce about half of gasoline and diesel consumed in 132

Minnesota. The Northern Tier Energy 2014 Form 10-K report indicates that in 2014 133

approximately 81 percent of the gasoline and distillate (diesel plus jet fuel) production from 134

the St. Paul Park refinery was sold within Minnesota. The 10-K report also discloses the 135

total production volume of gasoline and distillate produced by the refinery. Since the total 136

sales of gasoline and diesel in Minnesota are known (from EIA statistics), a simple 137

calculation indicates that in 2014 the St. Paul Park refinery satisfied about 23 and 30 138

percent of the Minnesota gasoline and diesel demand, respectively. Accordingly, by 139

difference, non-Minnesota refineries supplied about 27 and 20 percent of the gasoline and 140

diesel, respectively, consumed in Minnesota in 2014. 141

142

More generally, state boundaries have little to do with the distribution patterns of refined 143

products in the U.S. All refined products move freely across state boundaries and refined 144

product distribution patterns are mostly dictated by the location of the major refining centers, 145

the major demand centers (typically large cities), and the installed network of refined product 146

pipelines. Based upon my industry experience, refiners are constantly seeking to sell their 147

products into the markets that generate the highest prices (net of transportation costs). For 148

example, the director of communications for the Flint Hills Pine Bend refinery indicated that 149

the refinery satisfies 30 to 40 percent of transportation fuel demand in the neighboring state 150

of Wisconsin. Northern Tier Energy, in its 2014 Form 10-K report, commented that it sells 151

gasoline and diesel produced at the St. Paul Park refinery in Iowa, Nebraska, Oklahoma, 152

South and North Dakota, and Wisconsin. 153

154

Q. What other states did you evaluate in your Report? 155

A. In addition to Minnesota itself, I evaluated the supply and demand for refined products in 156

PADD II (the Midwest and Midcontinent). I also provide a focused analysis of refined 157

product supply and demand in Wisconsin, North Dakota, South Dakota, and Iowa. These 158

are the states that directly neighbor Minnesota. I collectively refer to Minnesota and its 159

neighbors as the “Five-State Area.” 160

161

There are also some imports and exports of petroleum products between Minnesota and 162

Canada. However, these volumes are small, and I believe that they can be reasonably 163

ignored for any supply and demand analysis of the Five-State Area. 164

165

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Q. Why did you include these neighboring states in your analysis? 166

A. The consideration of the neighboring states flows from my understanding that Minnesota 167

Rule 7853.0130(A) requires the consideration of the probable result of denial of the L3R 168

Program on the adequacy, reliability, or efficiency of energy supply to the people of 169

Minnesota and neighboring states. Thus, I understand the regulation to explicitly require the 170

consideration of the impact of denial of the L3R Program on neighboring states, as these 171

impacts may possibly affect Minnesota, either directly or indirectly. 172

173

Q. What is the demand for refined products in Minnesota and its neighboring states? 174

A. Figure 4 below provides the demand for refined products in Minnesota over the last 20 175

years. This figure is generated from the EIA State Energy Data System. At this point in 176

time, the data are available only through 2014. The 2015 final data are scheduled to be 177

released in June 2017. It should be noted that Figure 4 provides the demand data in terms 178

of kb/d, whereas the previous graph of Minnesota demand was in units of trillions of BTUs 179

per year. 180

181

182 Figure 4

- 50

100 150 200 250 300 350 400

kb/d

Minnesota Refined Product Demand

Asphalt Diesel Jet/Kero Gasoline OtherSource: EIA

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Figure 5 below shows the demand of refined products in the Five-State Area. Minnesota 183

demand is about one-third of the total Five-State Area demand, with a considerably higher 184

proportion of regional jet fuel demand and somewhat lower proportion of diesel demand. 185

Q. Since the state-level petroleum product demand data stops in 2014, what have been 186

the petroleum product demand trends at a regional or national level post-2014? 187

A. In PADD II, the 2015 demand for gasoline was up (53 kb/d), jet fuel demand was essentially 188

flat (up 4 kb/d,) and diesel demand decreased (-34 kb/d, or -2.7 percent). For the period 189

January to October 2016 versus the same period in 2015, gasoline demand was up 52 kb/d, 190

jet demand increased slightly, and diesel demand dropped by 40 kb/d. At the national level, 191

the EIA Short Term Energy Outlook (STEO) is projecting that gasoline demand will increase 192

in 2017 by 54 kb/d, distillate by 100 kb/d, and a 30 kb/d decrease for jet fuel demand. 193

194

Q. What proportion of the Five-State Area demand is met by local refineries? 195

A. Within the Five-State Area, there are refineries located in Minnesota, North Dakota, and 196

Wisconsin. South Dakota and Iowa have no refineries. Figure 6 illustrates the volume of 197

refined products produced within the Five-State Area, including the contribution from fuel 198

ethanol, through 2015. Approximately 55 percent of the total demand for refined products in 199

the Five-State Area is satisfied by the local refineries within the area itself. 200

Figure 5

- 100 200 300 400 500 600 700 800 900

1,000

kb/d

Five-State Refined Product Demand


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Among the major types of refined products, the proportion satisfied by the local refineries 201

differs. In recent years, the region has begun to produce an excess of asphalt. Local 202

refineries currently meet all of the jet demand, mostly due to a decrease in jet demand 203

rather than an increase in local production. Roughly 50 percent of the Five State Area 204

demand for gasoline and diesel is supplied from local refineries. 205

206

Q. Due to energy conservation or other measures, is the demand for petroleum products 207

in the states that neighbor Minnesota expected to decline during the forecast period 208

such that transfers in from other U.S. states will not be required? 209

A. No. For the key products of gasoline and diesel, demand would have to be cut 210

approximately in half in the Five State Area before it could be met by local supply. 211

212

Q. How is the deficit in local petroleum product supply met in the Five-State Area? 213

A. In the case of Wisconsin, the deficit is met primarily by pipeline deliveries from the large 214

refineries located in the Chicago area, supplemented by additional supply from refineries 215

located in southern Illinois. Iowa is also partially supplied out of the Chicago area, as well 216

as from refineries located in the Midcontinent (Kansas, Oklahoma). The supply from the 217

Midcontinent also is the primary means by which supply deficits in South Dakota and 218

Minnesota itself are met. North Dakota is also supplied from a refinery in central Montana. 219

Figure 6

-

100

200

300

400

500

600

kb/d

Five-State Area Refinery Production

Fuel Ethanol Gasoline ex EtOH Jet Diesel Asphalt/HFO OtherSource: EIA, Muse

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Q. Is refined product supply from these refineries in other states important to the 220

adequacy, reliability, or efficiency of the energy supply to the people of Minnesota? 221

A. For example, when the Five-State Area cannot obtain refined product supply from other 222

refineries in the Midwest and the Midcontinent, there will be almost an immediate reaction in 223

the fuel prices in Minnesota. On August 8, 2015, the large BP Whiting refinery in the 224

Chicago area unexpectedly shut down its largest crude oil distillation unit. Gasoline prices 225

in the Midwest reacted almost immediately. Chicago bulk spot prices for regular gasoline 226

climbed 16.35¢/gal on August 10 (Monday), and rose another 44.72¢/gal on Tuesday. 227

Retail gasoline prices also reacted as well to the BP refinery outage in both Chicago and 228

Minnesota, as shown in Figure 7, before prices retreated as additional gasoline supplies 229

entered the market in subsequent days.1 230

Q. Since states outside of the Five-State Area play a crucial role in satisfying refined 231

product demand in Minnesota and its neighboring states, are these other states 232

relevant to the Commission’s evaluation of the merits of the L3R Program? 233

A. The refineries in other PADD II states play an essential role in satisfying refined product 234

demand in the Five-State Area. This point has been previously made by Laura Otis with the 235

Minnesota Department of Commerce. In her written testimony for a recent MPUC hearing, 236

1 The retail gasoline prices were obtained from GasBuddy.com. Retail prices are only available at the state level for Minnesota from this source. The crude oil distillation unit at the BP Whiting refinery was restarted on August 25.

2.30

2.50

2.70

2.90

3.10

3.30

3.50

3.70

Dolla

rs p

er G

allo

n

Retail Gasoline Prices

Minnesota ChicagoSource: Gasbuddy.com

Figure 7

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she stated that: “It is clear that there exists a strong interdependence between Minnesota 237

and other states in the region for refined petroleum product supply.”2 Department of 238

Commerce witness Otis further elaborated on this point in the following question and 239

answer:3 240

“Q. Please further elaborate on the negative consequences Minnesota consumers 241 would experience as a result of supply shortages in connected markets such as 242 Chicago. [Emphasis added.] 243

A. Refiners could divert petroleum product supplies from the Minnesota market to take 244 advantage of higher prices in the Chicago market, thus decreasing supply available to 245 Minnesotans. As a result, the market would adjust prices upward to keep supply and 246 demand in balance. As a consequence of market interconnection, Minnesota has an 247 interest in the adequacy of supply to other parts of PADD II with petroleum and 248 petroleum pipeline connections to our area.” 249

The importance of regional petroleum infrastructure, beyond the borders of Minnesota, is 250

further highlighted by the fact that inventories of refined product are maintained on a “just-in-251

time” basis, meaning that refineries operate “at or near the lower operational inventories for 252

all products.”4 Accordingly, the market has some difficulty in adjusting to changes in 253

demand.5 Limited inventory increases price uncertainty and reduces supply resilience on 254

the market. As a result, the market is not buffered from supply problems caused by refinery 255

issues, such as fires, outages, or routine maintenance.6 As noted in the 2012 Quad Report, 256

these events cause upward price pressure in all areas of the country, not just regional 257

impacts.7 258

259

Accordingly, to the extent that the L3R Program influences the adequacy and security of the 260

crude oil supply to the PADD II refineries, the broader impact of the L3R Program 261

throughout PADD II does appear to be relevant to any consideration of the merits of the L3R 262

Program. The L3R Program connects the crude oil resources in Western Canada and, to a 263

degree, North Dakota, to most of the refineries in PADD II. 264

2 Direct Testimony of Laura B. Otis on behalf of The Minnesota Department of Commerce, Division of Energy Resources, MPUC Docket No. PL-9/CN-13-153OAH, February 18, 2014, pg. 11. 3 Ibid., pg. 15. 4 2012 Minnesota Department of Commerce Energy Policy and Conservation Quadrennial Report (2012 Quad Report), pg. 34. 5 Ibid. 6 Ibid., pg. 35. 7 Ibid.

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III. SUPPLY OF CRUDE OIL IN MINNESOTA AND NEIGHBORING STATES 265

266

Q. Does Minnesota produce any of the crude oil that is refined in Minnesota? 267

A. No. Minnesota is one of the 19 U.S. states that does not produce any crude oil. 268

269

Q. What are the sources of the crude oil serving the refineries in Minnesota and its 270

neighboring states? 271

A. The U.S. and Canada. EIA statistics indicate that 2008 was the last time that Minnesota 272

refineries imported crude oil from a country other than Canada (1 kb/d, from Venezuela). In 273

fact, the only pipeline by which non-Canadian crude oil imports could be delivered to 274

Minnesota refineries was taken out of service in early 2013. The refineries in Wisconsin and 275

North Dakota have never had pipeline access to non-Canadian imports. 276

277

Q. What are the sources of crude oil supply for the other refineries in the Midwest and 278

the Midcontinent? 279

A. Essentially, the U.S. and Canada. Through September 2016, EIA statistics indicate that 280

PADD II refineries imported 2,222 kb/d of crude oil, of which only 41 kb/d was from a country 281

other than Canada. 282

283

Q. Has the demand for crude oil in the Five-State Area and in the rest of the Midwest and 284

the Midcontinent been changing? 285

A. Yes. Figure 8 provides the total refinery capacity by region in PADD II. In the last 5 years, 286

total refinery capacity has been increasing in all four of the regions shown on Figure 26. 287

Total refinery capacity is up 213 kb/d over this period. Figure 26 also displays the actual 288

crude oil runs in PADD II. Crude oil runs have increased by 237 kb/d between 2011 to 289

September 2016. All of the refineries in PADD II can be served directly or indirectly by the 290

Enbridge Mainline System. Figure 8 also displays the actual crude oil runs in PADD II. 291

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Q. Does the Enbridge Mainline System serve these regional refining submarkets shown 292

in Figure 8? 293

A. Yes. Table 8.3.E-2 of the Application lists the refineries served directly or indirectly from the 294

Enbridge Mainline System. 295

296

Q. What are the primary transportation modes used to deliver crude oil to the refineries 297

that satisfy petroleum product demand in Minnesota and its neighboring states? 298

A. Pipeline transportation is the predominant means by which crude oil is delivered to the 299

refineries in Minnesota, its neighboring states, and throughout the Midwest and the 300

Midcontinent. Figure 9 below displays the proportion of domestic and foreign crude oil that 301

was delivered by pipeline to PADD II refineries since 1998. As a practical matter, nearly all 302

foreign crude oil is delivered to PADD II refineries by pipeline, with a small volume of rail 303

deliveries being a very recent development. The situation is similar for domestic crude oil 304

deliveries, although most of the non-pipeline receipts are via barge and truck, rather than 305

rail. 306

Figure 8

- 500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

2010 2011 2012 2013 2014 2015 2016

kb/d

PADD II Refining Capacity and Crude Oil Runs

Five-State Area Upper Midwest Lower Midwest

Midcontinent PADD II Crude RunsSource: EIA

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Q. Are pipelines likely to remain the predominant delivery system for crude oil to the 307

PADD II refineries? 308

A. Yes. Current pipeline crude oil deliveries to PADD II refineries exceed 3,500 kb/d, and this 309

volume will never be predominately supplanted by an alternative delivery mode. However, 310

rail is becoming a more important delivery mode for the Canadian crude oil producers. 311

Figure 10 below provides the monthly deliveries of Canadian crude oil to the Midwest and 312

the Midcontinent (PADD II), the East Coast (PADD I), and the Gulf Coast (PADD III).8 As 313

can be observed, rail deliveries have been climbing steadily over the last several years 314

because of the lack of pipeline capacity. Due to the layout of the U.S. railway system, much 315

of the Canadian rail volume to the regions shown on Figure 10 can be expected to transit 316

Minnesota. 317

8 The EIA statistics capture only deliveries to U.S. destinations. Western Canadian crude oil is also railed to Canadian destinations.

Figure 9

93%94%95%96%97%98%99%

100%

Proportion of Pipeline Receipts for PADD II Refineries

Domestic Crude Oil Receipts by Pipeline

Foreign Crude Oil Receipts by PipelineSource: EIA

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0

50

100

150

200

250

300

kb/d

Canadian Crude Oil Deliveries by Rail to U.S.

PADD I PADD II PADD III PADD IV/VSource: EIA

IV. CRUDE OIL SUPPLY FORECASTS 318

319

Q. What crude supply forecast did you rely on for your analysis of the expected 320

utilization of the Enbridge Mainline System provided in the Muse Report? 321

A. There are several authoritative public long-term forecasts of Western Canadian crude oil 322

production. The National Energy Board (NEB), which is an independent federal, quasi-323

judicial regulator, provides Canadian crude oil production outlooks every other year. The 324

Canadian Association of Petroleum Producers (CAPP) releases crude oil supply and 325

production forecasts annually, and the associated report contains a great deal of information 326

regarding the basis for the Canadian crude oil supply outlook and of crude oil market 327

developments. The Alberta Energy Regulator (AER), a quasi-judicial regulatory agency of 328

the Government of Alberta, provides annual crude oil production outlooks for Alberta, which 329

constitutes the preponderance of Western Canadian crude oil production. 330

331

Q. Why did you select these forecasts for use in your analysis? 332

A. The CAPP and NEB forecasts are publicly available, provide considerable detail regarding 333

the methodology used to develop the forecast, and, in my experience, are well-regarded by 334

industry and regulatory bodies. I also considered the AER outlook because it is an 335

authoritative independent source and Alberta produces most of the crude oil in Western 336

Figure 10

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Canada. In my experience, the CAPP crude oil supply forecasts are commonly used for 337

pipeline regulatory purposes in Canada and the U.S. I have personally used the CAPP 338

crude oil supply forecast for expert reports to the NEB, the Federal Energy Regulatory 339

Commission, and various state regulatory agencies. 340

341

Q. Please provide additional detail concerning the NEB forecast. 342

A. The NEB released its long-term energy outlook, Canada’s Energy Future 2016, in January 343

2016. The report is intended to provide Canadians with a key reference point to discuss the 344

country’s energy future, and relies upon the extensive energy market expertise of the NEB’s 345

technical staff. In addition, energy experts from government, industry, environmental 346

organizations, and academia across Canada provided input on the preliminary assumptions 347

and results of the report. In October 2016, the NEB released a report update that captured 348

several recently announced climate policies, and revised the crude oil price assumptions 349

used for the outlook. For the outlook, the NEB utilizes three crude oil price scenarios that it 350

terms Reference, High, and Low Price Cases. 351

352

Q. How does the CAPP forecast compare with the NEB’s reference case? 353

A. A comparison of the CAPP 2016 forecast to all three of the updated NEB price scenarios 354

(Reference, Low, and High) is shown below in Figure 11. The CAPP forecast is virtually 355

identical to the NEB Low Price scenario until about 2028, at which point the CAPP crude oil 356

production forecast is about 4 percent higher than the NEB Low Price scenario. Crude oil 357

production under the NEB High Price Scenario is about 13 percent higher than the 358

Reference Price Scenario in 2030, and production under the Low Price Scenario is about 10 359

percent lower. However, the crude oil prices in 2030 for the High and Low Price Cases are 360

37 percent above and 47 percent below the Reference Case price, respectively. This 361

indicates that the Western Canadian crude oil production volume is comparatively resistant 362

to changes in the absolute crude oil price. 363

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364

Q. How does the AER forecast compare to the CAPP and NEB forecasts? 365

A. A comparison of the latest available NEB, AER, and CAPP outlooks is shown on Figure 12 366

below.9 The outlooks are similar through 2020, and the CAPP bitumen production forecast 367

is generally the lowest of the four. Figure 12 also provides some perspective the historical 368

growth rate of Western Canadian bitumen production. 369

370

371 9 The AER outlook is provided in ST98-2016; Alberta’s Energy Reserves 2015 and Supply/Demand Outlook 2016-2025; Figure S3.8; pg. 3-21. The AER forecast ends in 2025.

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1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

kb/d

Western Canadian Bitumen Production

CAPP 2016 NEB Oct 2016 Reference Case AER 2016Source: NEB, CAPP, AER

Figure 12

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

kb/d

Western Canadian Crude Oil Production

CAPP 2016 NEB Reference NEB Low NEB HighSource: NEB, CAPP

Figure 11

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Q. Based on your review of these supply forecasts, what conclusions do you reach 372

regarding the demand for the L3R Program? 373

A. The NEB, CAPP, and AER forecasts differ in the details, but more broadly communicate the 374

same message — the forward outlook for Western Canada is one of significant increases in 375

crude oil supply. As a practical matter, such increases must be transported to the market by 376

some combination of pipeline and rail. The L3R Program represents a small portion of the 377

incremental transportation capacity that will have to be added over the next decade and 378

beyond. 379

380

V. ESTIMATED UTILIZATION OF THE ENBRIDGE MAINLINE SYSTEM 381

382

Q. Please summarize the methodology you used to estimate the expected utilization of 383

the Enbridge Mainline System. 384

A. I used a mathmatical model of the North American crude oil distribution system, including 385

rail and water transportation modes, to predict the flow of crude oil to various markets. An 386

optimization solver is coupled to the model to generate the crude oil distribution pattern that 387

acts to maximize the crude oil price received by the U.S. and Canadian crude oil producers. 388

In essence, the model is attempting to replicate an efficiently operating crude oil market 389

place. Optimization algorithms are used to generate the most efficient crude oil distribution 390

pattern that acts to maximize the crude oil price received by the U.S. and Canadian crude oil 391

producer, thus mimicing the behavior of the North American oil industry. Consequently, the 392

model is well-suited for assessing the market implications of changes in the logistical 393

infrastructure that enables Western Canadian and U.S. crude oil to reach the market. I refer 394

to the model as the “Muse Crude Oil Market Optimization Model.” 395

396

The Muse Crude Oil Market Optimization Model is used to evaluate the market impact of two 397

scenarios concerning the Enbridge Mainline System. The first scenario considers the 398

market implications of not replacing Line 3 (Current Status Scenario) using the existing 399

capacities and capabilities of the Enbridge Mainline System. The second scenario (Line 3 400

Replacement Scenario) evaluates the implications of replacing Line 3 with the 401

corresponding changes in Enbridge Mainline System capacity and capabilities. The 402

replacement of Line 3 acts to increase the overall capacity of the Enbridge Mainline System 403

by 370 kb/d, and further provides it with the capability to swing up to 760 kb/d between light 404

and heavy crude oil transportation service. 405

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Q. Why did Muse analyze the expected utilization of the entire Enbridge Mainline 406

System, rather than focus on utilization of the L3R Program only? 407

A. The Enbridge Mainline System has six crude oil pipelines that cross the international border. 408

The pipelines composing the Enbridge Mainline System operate as an integrated system 409

and transport multiple grades of light and heavy crude oil. Consequently, trying to estimate 410

the utilization of a single line in isolation, without considering the capacity that may be 411

available on the other five pipelines, is a meaningless exercise. Accordingly, I first estimate 412

the required total crude oil throughput of the Enbridge Mainline System, and then assess if 413

the L3R Program is needed to satisfy that throughput requirement. 414

415

VI. CONCLUSIONS 416

417

Q. Based on your analysis, what is the expected utilization of the Enbridge Mainline 418

System? 419

A. The estimated year-by-year throughput on the Enbridge Mainline System with the L3R 420

Program as of 2019 is shown in Table 1 below. The Enbridge Mainline System is projected 421

to operate at capacity in all years, except for 2021. In this year, the amount of surplus 422

capacity is approximately 2 kb/d. 423

Q. Based on your comparison of the NEB, CAPP, and AER forecasts, what is your 424

conclusion regarding the outlook for Western Canadian crude oil supply? 425

A. The NEB, CAPP, and AER forecasts differ in the details, but more broadly communicate the 426

same message — the forward outlook for Western Canada is one of significant increases in 427

crude oil supply. As a practical matter, such increases must be transported to the market by 428

some combination of pipeline and rail. The L3R Program represents a small portion of the 429

incremental transportation capacity that will have to be added over the next decade and 430

beyond. 431

Table 1 ENBRIDGE MAINLINE THROUGHPUT ― GRETNA TO CLEARBROOK

LINE 3 REPLACEMENT SCENARIO

(Thousands of Barrels per Calendar Day, Unless Noted)

Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Light Crude Oil PipelinesCanadian Light Crude Oil 538.3 674.4 585.0 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 U.S. Bakken Crude Oil 188.8 52.7 143.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 Heavy Synthetic 40.0 40.0 40.0 - - - - - - - - - - - - - - - - -

Subtotal 767.1 767.1 768.8 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7

Heavy Crude Oil PipelinesCanadian Heavy Crude Oil 1,468.3 1,468.3 1,468.3 1,969.8 1,953.7 1,971.0 1,971.0 1,963.9 1,956.8 1,968.7 1,972.7 1,991.9 2,000.2 2,007.2 2,006.9 1,939.3 1,926.6 1,968.7 1,974.5 1,976.3 Light Crude Oil to Line 3 - - - 197.7 213.8 195.0 196.5 203.6 210.7 198.8 194.9 175.6 167.3 160.3 160.6 228.2 240.9 198.9 193.0 191.2

Subtotal 1,468.3 1,468.3 1,468.3 2,167.5 2,167.5 2,165.9 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5

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Q. Based on your expertise and analysis, is it your opinion that the L3R Program will 432

improve the adequacy, reliability, or efficiency of energy supplies in Minnesota and 433

the surrounding region? 434

A. Yes. 435

436

Q. Does this conclude your direct testimony? 437

A. Yes. 438

NEIL K. EARNEST SUMMARY OF EXPERIENCE: Neil has over 30 years of experience focused on the downstream sector of the energy business, and has played key roles in major international arbitrations, multi-billion dollar downstream asset acquisitions, and Canadian crude marketing and upgrading programs totaling hundreds of thousands of barrels per day. As a consultant, he has worked on a broad range of assignments around the world with an emphasis on asset acquisition and divestitures, crude and refined product marketing analyses, expert testimony in support for highly complex arbitrations and major pipeline projects, and project feasibility assessment. Neil began his career at Phillips Petroleum Company, where he spent 11 years in a variety of roles at Phillips’ largest refinery and petrochemical plant and in corporate planning/engineering.

REPRESENTATIVE CONSULTING EXPERIENCE: Asset Acquisition and Divestitures As director of the M&A practice area, has frequently headed Muse’s teams that have assisted clients contemplating downstream acquisitions or divestitures. Over the years, dozens of detailed valuations of North American refineries for a variety of clients have been completed. Several representative assignments follow:

1. Provided a detailed technical and economic assessment of the range of options available to a Canadian heavy crude producer commencing a downstream integration strategy. Assistance included board-level presentations and assistance negotiating the purchase-sales agreements and the joint-venture operating agreements.

2. Developed a detailed valuation of the combined sales value of the European downstream assets of a major oil company. Included projecting refinery cash flow considering the evolving environmental, product demand, and product specification issues regarding Europe.

3. Provided economic, technical, and LP modeling assistance to a corporate team considering entry into the Asia-Pacific refining industry.

4. Conducted due diligence of, and assessed the potential for, investment in four state-owned African refineries.

5. Assisted a U.S. client considering the merger of their refining assets with another refiner. The assistance included an assessment of the competitive position of the potential merger partner.

Market, Strategic, and Competitive Analysis Have provided a broad range of market and competitive analyses in support of client’s strategy objectives. Clients include pipeline companies, refiners, and crude producers. Several representative examples include:

1. Assisted a number of Canadian crude producers with their development strategy, including detailed market and potential customer assessments, for their synthetic and heavy sour crude programs.

Earnest Direct CN Testimony, Ex. ___, Schedule 1 Page 1 of 8

2. On behalf of several refiners, developed a detailed assessment of their competitive position versus domestic and foreign competition.

3. Generated a detailed assessment, considering multiple market scenarios, of the expected prices for a range of potential synthetic crude formulations that was instrumental in finalizing the design basis for a multi-billion dollar Canadian oil sands upgrader.

4. Assisted a client with the development of a marketing program for a new, high acid, North Sea crude.

5. Provided the market analysis in support of a new proposed product pipeline in the Rockies.

6. Assisted several clients with quantifying the value of their equity crude to specific purchasers. The purchasers were either being considered for term contracts or were large volume buyers.

7. Provided the Government of Alberta, Ministry of Energy, detailed analysis of bitumen blends and targeted markets.

Project Feasibility Analysis

Representative project and refinery feasibility analyses include:

1. In-depth evaluation of resid upgrading options for a large Middle East refinery.

2. Provided a detailed assessment of the value of a partial-upgraded biofuel to the refining industry on behalf of the biofuel manufacturer.

3. Provided an detailed technical and economic assessment of a heavy crude partial upgrader, including certifying field-scale performance tests.

4. Developed the configuration, yields, and operating costs for a proposed Middle East refinery.

5. Performed a detailed study for a U.S. client considering various resid upgrading options.

6. Assisted a South American client with process optimization in connection with a major upgrade of their lube manufacturing facilities.

7. Performed a technical and economic analysis for a South American client considering the construction of a resid FCC unit.

Expert Testimony

1. Private Arbitration (1998): Koch Shipping Inc., Koch Supply & Trading Company, and Koch Refining Company, L.P. v. Mobil Shipping and Transportation Company.

2. Provided expert report, in 2006, on behalf of Enbridge Pipelines regarding the market demand for Canadian crude oils and quantified the benefits that would flow to Illinois and other U.S. consumers regarding the Southern Access Pipeline. Report filed with the Illinois Commerce Commission.

3. Provided expert report and direct testimony before the National Energy Board (Canada) regarding the Southern Lights Project, on behalf of Enbridge Pipelines, Inc., with hearings held in Calgary, Alberta, in 2007.


4. Expert report and direct testimony before the National Energy Board (Canada) regarding the Alberta Clipper Project, on behalf of Enbridge Pipelines, Inc., with hearings held in Calgary, Alberta, in 2007.

5. Provided expert report, in 2007, on behalf of Enbridge Pipelines to the National Energy Board (Canada) regarding the crude supply and demand for Ontario and Montréal refineries.

6. Provided expert reports, in 2007, to the U.S. Federal Energy Regulatory Commission on

behalf of Enbridge Pipelines regarding the expected utilization of the Southern Access Extension pipeline, as well as other non-rate shipper benefits that ensued from the commissioning of the pipeline. Also provided written affidavit in response to intervener’s expert.

7. Provided direct testimony, in 2008, before the Minnesota Public Utilities Commission

regarding the Alberta Clipper Project, on behalf of Enbridge Pipelines, Inc.

8. Direct testimony, in February 2008, before the International Court of Arbitration, with hearings held in Zurich, Switzerland, on behalf of Louis Dreyfus S.A.S. (Respondent) against Ronald W. de Ruuk, as Bankruptcy Administrator for Holding Tusculum B.V., (Claimant). Testifying expert at hearings on behalf of the respondent regarding the value of the Wilhelmshaven, Germany, refinery. Also co-authored valuation report and responses to claimant’s experts.

9. Provided expert report, in May 2009, and oral testimony to the International Court of

Arbitration on behalf of Mobil Cerro Negro, Ltd (Claimant) against Petroleos de Venezuela, SA regarding the expropriation of assets.

10. Expert report and direct testimony before the National Energy Board (Canada) regarding the

Keystone XL Project, on behalf of Enbridge Pipelines, Inc., with hearings held in Calgary, Alberta, in 2009.

11. Provided expert and reply report, in 2009, on behalf of Enbridge Pipelines to the National

Energy Board (Canada) regarding the medium-term prospects for Line 9 in westbound service.

12. Provided expert and reply reports, in 2010 and 2011, to the International Centre for

Settlement of Investment Disputes on behalf of Venezuelan Holdings B.V., et.al. (Claimant) against the Bolivarian Republic of Venezuela, and oral testimony at the hearing held in Paris in 2012 regarding the expropriation of assets.

13. Provided expert oral testimony in 2011 on behalf of Enbridge Inc. to the National Energy

Board (Canada) regarding the Southern Lights Pipeline.

14. Provided expert report, in 2011, on behalf of Enbridge Bakken Pipeline Company to the National Energy Board (Canada) regarding the market prospects for North Dakota crude oil.

15. Submitted export report in January 2012 to the Michigan Public Service Commission

regarding the public need and local economic benefits of Enbridge Line 17, on behalf of Enbridge Pipelines (Toledo) Inc.

16. In 2011, submitted expert and rebuttal reports to the U.S. Federal Energy Regulatory Commission on behalf of Enbridge Pipelines regarding the Southern Lights Pipeline followed by oral testimony at the hearing in Washington, D.C., in 2012.


17. Provided expert and rebuttal reports to the Joint Review Panel (Canada) regarding the Northern Gateway Pipeline project, followed by oral testimony at hearing held in Edmonton, Alberta in September 2012, on behalf of the Northern Gateway Pipeline.

18. Provided expert report to the National Energy Board (Canada) regarding the market

prospects for the Enbridge Edmonton-to-Hardisty pipeline project in November 2012, followed by direct testimony in October 2013, on behalf of Enbridge Pipelines.

19. Provided expert report, rebuttal, and surrebuttal testimony in 2013 and 2014 before the

Minnesota Public Utilities Commission regarding the Line 67 Station Expansion Project – Phase 2, on behalf of Enbridge Pipelines, Inc.

20. Provided expert report and rebuttal testimony in 2014 to the U.S. Federal Energy Regulatory

Commission on behalf of North Dakota Pipeline Company LLC regarding the Sandpiper pipeline.

21. In June 2014, provided written and oral expert testimony in the English High Court of Justice

– Commercial Court, on behalf of Innospec Inc. versus Jalal Bezee Mejel Al-Gaood & Partner regarding issues in the Iraqi refining sector.

22. Provided expert and rebuttal testimony to the National Energy Board (Canada) regarding

Trans Mountain Pipeline nomination verification procedures in 2014, on behalf of Tesoro Canada.

23. Provided expert reports and oral testimony in August 2014 through January 2015 before the

Minnesota Public Utilities Commission regarding the Sandpiper Pipeline Project on behalf of North Dakota Pipeline Company LLC.

24. Provided expert report and rebuttal report, followed by oral testimony in February, 2016, in

the U.S. District Court for the Central District of California, on behalf of Southern California Edison Company versus ExxonMobil Oil Corporation.

25. Provided reply report in October 2014 to the International Centre for Settlement of

Investment Disputes on behalf of ConocoPhillips Petrozuata B.V., et.al. (Claimant) against the Bolivarian Republic of Venezuela regarding the expropriation of assets.

26. Proved an expert report in November 2014 to the National Energy Board (Canada) regarding

the expected utilization of the Enbridge Mainline for the Enbridge Line 3 Replacement Program.

27. Provided expert report and oral testimony in June and December, 2015 to the ICC

International Court of Arbitration on behalf of Wallis Trading Inc. versus SGS Societe Generale de Surveillance SA for a case regarding issues relating to a collateral management agreement at an Albanian storage facility.

28. Provided expert report in September 2015 to the National Energy Board (Canada) regarding the expected utilization of and the Canadian crude oil producer benefits from the Trans Mountain Expansion Project.

29. Provided expert report to the U.S. Federal Energy Regulatory Commission in November 2015 on behalf of Colonial Pipeline Company regarding revisions to its Rules and Regulations tariff.


30. Provided an expert report and oral testimony in May and December 2016 to the ICC International Court of Arbitration on behalf of ConocoPhillips Petrozuata B.V., et.al. (Claimant) against Petróleos de Venezuala, S.A. regarding the expropriation of assets.

WORK EXPERIENCE: Muse, Stancil & Co. 1991 - Present Current Position: President Phillips Petroleum Company 1981-1991 Positions: Process Senior Engineer Economics Engineer Staff Process Engineer

EDUCATION: B.S. Chemical Engineering - 1981 Michigan State University M.B.A. - 1986 University of Houston – Clear Lake

PROFESSIONAL REGISTRATION: Chemical Engineer, Texas, #75398

PUBLICATIONS/PRESENTATIONS:

1. “Refinery-Profitability Statistics Begin” Oil & Gas Journal January 2001

2. “Canadian Crude Market Outlook” Alberta Department of Energy Workshop #2 March 2002

3. “View from the Market: The Refiner’s Perspective” CERI 2003 World Oil Conference January 2003

4. “Traditional Markets and New Opportunities” CERI 2004 World Oil Conference March 2004

5. “Independent Views on Markets for Oil Sands and Pipeline Capacity” TD Newcrest Oil Sands Forum 2004 July 2004

6. “Independent Views of Markets for Oil Sands and Pipeline Capacity” 2004 National Petrochemical & Refiners Association July 2004


7. “The Canadian Crude Market”

2005 Canadian Crude Oil Conference September 2005

8. “The Canadian Crude Market” 3rd Annual Canadian Oil Sands Summit January 2006

9. “Bigger is Better” 4th Annual Oil Sands Forum – Oil Sands Market Overview July 2006

10. “U.S. Market for Canadian Crude – Oil Sands Market Overview” Crude Oil Quality Group General Meeting November 2006

11. “Future Markets for Canadian Crude” 4th Annual Canadian Oil Sands Summit January 2007

12. “Canadian Crude Market Outlook” 3rd Annual Enbridge Mid-Continent Shippers Conference January 2007

13. “New Market Outlook for Canadian Crude” 42nd Annual Enbridge Jasper Conference June 2007

14. “Canadian Oil Market – Opportunities and Challenges” 5th Annual Canadian Oil Sands Summit January 2008

15. “Canadian Crude Market and Outlook” Argus US/Canada Asphalt Conference 2008 April 2008

16. “Oil Sands Integration with the U.S. Market – A Revised Perspective” 20th Annual Canadian Crude Oil Conference September 2008

17. “The Economy and Oil Demand: Where are They Taking the Oil Market?” CERI 2009 Oil Conference April 2009

18. “Oil Sands Integration with the Global Markets – A Revised Perspective” TD Newcrest London Oil Sands Forum 2009 January 2009

19. “Oil Sands Integration with the Global Markets” TD Newcrest Canadian Unconventional Oil Forum 2009 July 2009


20. “Implications of Expanding Canadian Pipeline Infrastructure”

Argus Americas Crude Summit 2010 January 2010

21. “Counter-Party Risk” T.D. Newcrest – Unconventional Oil & Gas Forum July 2010

22. “U.S. Downstream in the New Economic Reality” Annual Canadian Crude Oil Conference September 2010

23. “The Road to Recovery” Argus 4th Annual Americas Asphalt Summit March 2011

24. “Crack Spreads are Back: Which PADDs Stand to Benefit and How Long Will It Last?” TD Securities – Unconventional Energy Conference T.D. Newcrest – 2011 Calgary Unconventional Energy Conference July 2011

25. “Overall Market Landscape for Canadian Crude Oil” Argus – Americas Crude Summit 2012 January 2012

26. “Canadian Crude Landscape and Market Expansion Prospects” Argus – Americas Asphalt Summit 2012 March 2012

27. “The Changing Crude Supply Landscape – The Refiner’s Perspective” TD Securities July 2012

28. “Rail vs. Pipeline: What Projects are Being Developed to Accommodate Growing Shale Crude Production?” Argus Americas Crude Summit January 2013

29. “Implications of the North American Oil Renaissance” American Fuel & Petrochemical Manufacturers January 2013

30. “Implications of the Evolving North American Crude Supply Outlook” TD Securities – 2013 TD Calgary Energy Conference July 2013

31. “Implications of the Evolving North American Crude Supply Outlook” AICHE –5th Southwest Process Technology Conference October 2013


32. “Renaissance of the North American Energy Sector” Lloyds Register – Energy Conference October 2013

33. “Changing Topography of U.S. Crude” Argus – Americas Crude Summit 2014 January 2014

34. “Canadian Tidewater Access – Implications for the U.S.” American Fuels & Petrochemical Manufacturers Annual Meeting 2014 March 2014

35. “Dealing with an Oversupply of Light Crudes in a World of Heavy Crude Refineries” Canadian Energy Research Institute 2014 Oil Conference April 2014

36. “Update on Market Access by Pipeline” Argus Canadian Crude Summit 2015 June 9, 2015

37. “North American Crude Market Outlook” Enbridge 50th Annual Liquids Pipelines Conference 2015 June 11, 2015

38. “Crude Oil Market Dynamics for 2016” Canadian Heavy Oil Association Annual Luncheon January 7, 2016

39. “Survival Outlook for Canadian Oil” 8th Argus Americas Crude Summit January 21, 2016


ENBRIDGE LINE 3

REPLACEMENT PROGRAM

MARKET ANALYSIS

January 2017

5080 Spectrum Drive Suite 600E

Addison, TX 75001 Phone: 214-954-4455

Fax: 214-954-1521

One City Centre 1021 Main Street, Suite 1560

Houston, TX 77002 Phone: 713-890-1182

Fax: 214-954-1521

Tower 42 25 Old Broad Street London EC2N 1HN

United Kingdom Phone: 44-0-207-374-8994

9 Temasek Boulevard #09-01 Suntec Tower 2

Singapore 038989 Phone: 65-6407-1379

Fax: 65-6407-1501


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TABLE OF CONTENTS

Page INTRODUCTION ............................................................................................... 4

EXECUTIVE SUMMARY AND CONCLUSIONS .............................................. 7 TRANSPORTATION FUEL SUPPLY AND DEMAND .................................. 7 COMPARISON OF INDEPENDENT CANADIAN CRUDE OIL

SUPPLY FORECASTS ............................................................................ 8 UTILIZATION OF THE ENBRIDGE MAINLINE ............................................ 8 COMPARISON OF PIPELINE CAPACITY TO CRUDE OIL SUPPLY ......... 11 L3R PROGRAM IMPACT ON RAIL SHIPMENTS OF CRUDE OIL ............. 12 OVERALL CONCLUSIONS ......................................................................... 13 MINNESOTA PRODUCT SUPPLY AND DEMAND ......................................... 15 FIVE-STATE PRODUCT SUPPLY AND DEMAND .......................................... 23 MIDWESTERN SUPPLY INTERDEPENDENCIES ........................................... 26 SUPPLY OF CRUDE OIL IN MINNESOTA AND NEIGHBORING STATES ...................................................................................................... 38 CANADIAN SUPPLY FORECAST COMPARISON.......................................... 42 CRUDE OIL MARKET OVERVIEW .................................................................. 48 UPPER MIDWEST ....................................................................................... 49 LOWER MIDWEST ...................................................................................... 50 ONTARIO / QUEBEC ................................................................................... 52 MIDCONTINENT .......................................................................................... 52 GULF COAST .............................................................................................. 54 RELATIONSHIP BETWEEN REFINERY RUNS AND PRODUCT DEMAND .............................................................................. 56

FORECAST ANALYTICAL METHODOLOGY ................................................. 59 MODEL INPUT: CRUDE OIL SUPPLY ....................................................... 61 MODEL INPUT: CRUDE OIL TRANSPORTATION

INFRASTRUCTURE .................................................................... 61 MODEL INPUT: REFINERY CAPACITY ..................................................... 69 MODEL INPUT: CRUDE OIL REFINING VALUES ..................................... 70


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FORECAST OF MAINLINE UTILIZATION ....................................................... 71 CURRENT STATUS SCENARIO ................................................................. 72 LINE 3 REPLACEMENT SCENARIO ........................................................... 76 ANALYSIS OF L3R PROGRAM ON NORTH AMERICAN CRUDE OIL FLOWS ............................................................................................. 81 DESTINATION OF INCREMENTAL ENBRIDGE MAINLINE SYSTEM THROUGHPUT ....................................................................................... 83 ANALYTICAL CONCLUSIONS .................................................................... 87

APPENDIX 1 ─ SCHEMATIC OF THE ENBRIDGE MAINLINE SYSTEM APPENDIX 2 ─ MAJOR CRUDE OIL PIPELINES IN NORTH AMERICA APPENDIX 3 ─ ENBRIDGE MAINLINE THROUGHPUT

GRETNA TO CLEARBROOK – CURRENT STATUS SCENARIO

APPENDIX 4 – ENBRIDGE MAINLINE THROUGHPUT – GRETNA TO CLEARBROOK – LINE 3 REPLACEMENT SCENARIO

APPENDIX 5 – AVOIDED RAIL SHIPMENTS OF WESTERN CANADIAN CRUDE

OIL – CURRENT STATUS SCENARIO LESS LINE 3 REPLACEMENT SCENARIO

APPENDIX 6 – DISPOSITION OF INCREMENTAL ENBRIDGE MAINLINE

THROUGHPUT – LINE 3 REPLACEMENT SCENARIO LESS CURRENT STATUS SCENARIO

APPENDIX 7 – ENBRIDGE MAINLINE SYSTEM CAPACITY UTILIZATION ANALYSIS SUPPORTING DATA


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INTRODUCTION Enbridge Line 3 is a 1,031-mile pipeline that originates at Edmonton, Alberta, and

terminates at Superior, Wisconsin. The Line 3 Replacement Program (the L3R

Program) will replace the existing pipeline between Hardisty, Alberta, and Superior with

a 36-inch diameter pipeline for most of the route. The approximate pipeline location is

shown in Figure 1. Muse, Stancil & Co. (Muse) has been advised by Enbridge that the

Line 3 annualized average daily capacity will be 760 thousand barrels per day (kb/d)

once the L3R Program is completed. For purposes of this report, the assumed in-

service date for the L3R Program is January 1, 2019.

Figure 1


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Muse has been asked to provide the following information and analyses in support of

the Certificate of Need Application (CN-14-916) for the Minnesota Public Utilities

Commission (the MPUC):

• Describe the historical and projected demand for refined petroleum

products in Minnesota, consistent with the requirements of Minn. R.

7853.0510;

• Describe the historical and projected demand for refined petroleum

products in the states that neighbor Minnesota, consistent with the

requirements of Minn. R. 7853.0510;

• Describe and quantify the degree of interdependency between the

Minnesota refineries and other Midwestern refineries for the requirement

to meet the need for key refined products by the people of Minnesota;

• Describe and quantify the current sources of crude oil supply for refineries

in Minnesota and its neighboring states;

• Describe and quantify the regional submarkets for crude oil in North

America that are served by the Enbridge Mainline System, of which Line 3

is a part;

• Provide a quantitative analysis of the projected utilization of the two

Enbridge Mainline System segments in Minnesota with and without the

L3R Program, and further provide a quantitative assessment of the impact

of the L3R Program on non-Enbridge crude oil transportation modes and


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on the overall market disposition for crude oil in North America; and

• Provide a comparison of Western Canadian crude oil supply forecast data

between the publicly-available independent sources.

Appendix 1 provides an overview of the Enbridge Mainline System, of which Line 3 is a

component. As noted in Appendix 1, the individual pipelines within the Enbridge

Mainline System transport a variety of crude oil grades, and individual pipelines tend to

be dedicated to specific crude oil grades to maximize operational efficiency. The

capacity of the individual pipelines within the Enbridge Mainline System, including Line

3, is influenced by the physical characteristics (density, viscosity, etc.) of the fluids being

transported.

This report was written by Neil K. Earnest, President of Muse. Established in 1984,

Muse is an independent consultancy that specializes in the provision of economic and

technical consulting services in combination with a wide-ranging understanding of the

commercial aspects of the downstream sector of the energy industry. Other employees

of Muse assisted with the preparation of this report.

A report by Muse had been previously submitted to the MPUC on April 24, 2015.

Because of the length of time that has passed since this previous filing, this report

replaces the previous Muse report in its entirety, rather than acting as an update to the

April 2015 report. It is my professional judgment that the key assumptions used to

develop the conclusions and opinions presented in this report are reasonable and well

founded.


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EXECUTIVE SUMMARY AND CONCLUSIONS

The L3R Program will enhance the existing ability of the Enbridge Mainline System to

transport crude oil from Western Canada to the crude oil markets in Minnesota, the

Upper Midwest, and Ontario. Other downstream pipelines provide connectivity from the

Enbridge Mainline System to important crude oil markets in Quebec, the Midcontinent,

Lower Midwest, and the Gulf Coast.

TRANSPORTATION FUEL SUPPLY AND DEMAND

A comparison is shown on Figure 2 between transportation fuel demand (gasoline,

diesel, jet) and local supply for the Five-State Area.1 Since 1993, the refineries in the

Five-State Area have supplied slightly less than 50 percent of the total transportation

fuel requirement of the people of Minnesota and its neighboring states, and the

Minnesota refineries themselves supplied an estimated 24 percent of this requirement.

Consequently, refineries located in other Midwestern states act as key suppliers of

transportation fuels to the Five-State Area, and the security, adequacy, and reliability of

crude oil supplies to these refineries has a direct bearing on meeting the overall energy

needs of Minnesota and its neighboring states. Western Canada is a vital crude oil

supply source for almost all of the Midwestern refineries. The Canadian crude oil that is

transported via Line 3 will be used, in part, to satisfy the refined product requirements of

Minnesota and its neighboring states. Accordingly, the L3R Program significantly helps

ensure the future adequacy and reliability of the energy supplies of the people of

Minnesota and its neighboring states.

1 The “Five-State Area” consists of Minnesota and its neighboring states of North Dakota, South Dakota,

Wisconsin, and Iowa.


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COMPARISON OF INDEPENDENT CANADIAN CRUDE OIL SUPPLY FORECASTS

Forecasts of Western Canadian crude oil production generated by authoritative,

independent sources differ in the details, but communicate the same message — the

forward outlook for Western Canada is one of large increases in crude oil supply. As a

practical matter, these increases must be transported to the market by some

combination of pipeline and rail. The L3R Program represents a small portion of the

additional transportation capacity that will have to be utilized over the next decades.

Finally, the L3R Program itself does not change the supply volume of Western

Canadian crude oil.

UTILIZATION OF THE ENBRIDGE MAINLINE SYSTEM

There are two Enbridge Mainline System segments in Minnesota: Gretna to Clearbrook

(which crosses the international border); and, Clearbrook to Superior. Both segments

include multiple pipelines (including Line 3) and transport a combination of U.S. and

Canadian crude oils, as Bakken crude oil produced in the U.S. is injected into the

Enbridge Mainline System upstream of Gretna at Regina and Cromer. Additional

Bakken crude oil is injected into the Enbridge Mainline System at Clearbrook via the

Figure 2

0100200300400500600700800900

1,000

kb/d

Comparison of Five-State Transportation Fuel Supply-Demand

Five-State Demand Five-State ProductionSource: EIA


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Enbridge North Dakota pipeline. The two Minnesota refineries obtain all of their pipeline

crude oil supplies at Clearbrook, either from the Enbridge Mainline System or the

Enbridge North Dakota pipeline. This latter pipeline enables them to access Bakken

crude oil production in North Dakota.

Gretna to Clearbrook Segment

Figure 3 provides the estimated throughput for the aggregate light crude oil pipelines for

the Gretna to Clearbrook segment, and Figure 4 provides the corresponding throughput

for the aggregate heavy crude oil pipelines without the L3R Program. It is noteworthy

that the heavy crude oil pipelines are projected to operate at capacity throughout the

forecast period. In this circumstance, the heavy crude oil pipelines will be in

apportionment. Consequently, all refineries downstream of Gretna, including those in

Minnesota, will need to source a portion of their heavy crude oil from other locations or

utilize rail transport to ship Western Canadian crude oil to their refineries (or do some

combination).

Figures 5 and 6 illustrate the impact of the L3R Program on the utilization of the Gretna

to Clearbrook segment. Total light crude capacity drops in 2019 because the existing

Line 3 is decommissioned, and the total capacity of the heavy crude oil pipelines

increases by 760 kb/d due to the start up of the new Line 3 capacity.2 Given that the

2 The 760 kb/d capacity is before the application of a utilization factor (92 percent).

Figure 3 Figure 4

0100200300400500600700800900

1,000

kb/d

Enbridge Gretna to Clearbrook Light Crude Oil

Canadian Light Crude Oil U.S. Bakken

Heavy Syn to Line 3 Light Crude Oil CapacitySource: Muse

0

200

400

600

800

1,000

1,200

1,400

1,600

kb/d

Enbridge Gretna to Clearbrook Heavy Crude Oil

Heavy Crude Oil Light Crude Oil to Line 3 Heavy Crude Oil CapacitySource: Muse


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new Line 3 has the operational capability to transport both light and heavy crude oil if

desired, Figure 6 illustrates that an average of about 200 kb/d of light crude oil will be

shipped on the new Line 3. Consequently, post completion of the L3R Program in

2019, there no longer is unused capacity in the light crude oil pipelines (Figure 5), the

volume of heavy crude oil capacity appreciably increases (Figure 6), and the total light

crude oil shipments are about the same as they were in the Current Status Scenario.

Clearbrook to Superior Segment

Without the L3R Program, the pipeline utilization situation for the Clearbrook to Superior

segment, downstream of the Minnesota refineries, is essentially the converse of that for

the Gretna to Clearbrook segment. Figure 7 provides the projected utilization for the

light crude oil pipelines, whereas Figure 8 shows the projected utilization for the heavy

crude oil pipelines without the L3R Program. The light crude oil pipelines are full, and

therefore in apportionment, and the heavy crude oil pipelines have available capacity.

Figure 5 Figure 6

0100200300400500600700800900

1,000

kb/d




0

500

1,000

1,500

2,000

2,500

kb/d



Figure 7 Figure 8

0100200300400500600700800900

kb/d

Enbridge Clearbrook to Superior Light Crude Oil



0

200

400

600

800

1,000

1,200

1,400

1,600

kb/d

Enbridge Clearbrook to Superior Heavy Crude Oil



-11-

With the L3R Program in service, both the light crude oil pipelines (Figure 9) and the

heavy crude oil pipelines (Figure 10) are projected to operate essentially at capacity.

The light crude oil capacity drops by 390 kb/d, and the heavy crude oil capacity

increases by 760 kb/d. Figure 10 also demonstrates the swing capability of the new

Line 3, which can transport 100 percent light crude oil, 100 percent heavy crude oil, or

some proportion in between. This flexibility better enables both the light and heavy

pipelines to be fully utilized. Post 2019, an average of about 470 kb/d of light crude oil

is being shipped on the new Line 3 (Figure 10).

COMPARISON OF PIPELINE CAPACITY TO CRUDE OIL SUPPLY

Figure 11 provides a comparison of the total volume of crude oil that must leave

Western Canada to the total outbound pipeline capacity if the L3R Program is

completed. The crude oil volume shown is net of that consumed by the refineries in

Western Canada itself. At the point in time that the L3R Program is completed in 2019,

there is no significant excess in outbound crude oil transportation capacity by pipeline.

It should be noted that this comparison further assumes that the large Trans Mountain

Expansion Project has been commissioned in 2021, which results in a moderate degree

of nominally excess pipeline capacity for a few years. It is not a certainty that the Trans

Mountain Expansion Project will be completed in 2021, or completed at all; this is just

an analytical assumption used for the overall analysis.

Figure 9 Figure 10

0100200300400500600700800900

kb/d




0

500

1,000

1,500

2,000

2,500

kb/d




-12-

L3R PROGRAM IMPACT ON RAIL SHIPMENTS OF CRUDE OIL

The impact that the Project has on rail shipments of crude oil from Western Canada is

sizable. Figure 12 provides the delta between rail shipments without the L3R Program

and with the L3R Program. The L3R Program is projected to reduce rail shipments by

up to about 500 kb/d. The change in rail volumes is greater than the nominal

incremental capacity of the L3R Program (370 kb/d) because the swing capability of the

L3R Program enables about 180 kb/d of currently unused capacity in the Enbridge

Mainline System is to be utilized. The large drop in avoided rail shipments in 2021 is

attributable to the assumed start up in 2021 of a large, non-Enbridge pipeline project

that transports crude oil to the west coast of Canada. Absent the L3R Program, much

of the additional rail shipments can be expected to transit Minnesota to such

destinations as the Midwest, East Coast, and the Gulf Coast.

Figure 11

0

1,000

2,000

3,000

4,000

5,000

6,000

kb/d

Western Canadian Crude Oil Disposition

Heavy Crude Oil Light Crude Oil U.S. Bakken Pipeline CapacitySource: Muse


-13-

OVERALL CONCLUSIONS The key conclusions of the analysis are:

• The increase in nominal Enbridge Mainline System capacity of 370 kb/d

created by the L3R Program will be fully utilized throughout the forecast

period;

• The L3R Program has a minor initial impact on the other pipelines that exit

Western Canada, and likely will have no impact within a few years of its

commissioning;

• The L3R Program will reduce the volume of Canadian crude oil shipped

via rail by between 110 and 500 kb/d, much of which will otherwise transit

Minnesota by train;

Figure 12

-

100

200

300

400

500

600

kb/d

Avoided Rail Shipments from Canada

Gulf Coast Puget Sound Minnesota Chicago Lower Midwest East CoastSource: Muse


-14-

• The refineries in Minnesota and its neighboring states cannot satisfy the

local demand for transportation fuels, and this shortfall in local supply is

primarily met by transfers from other Midwestern states;

• The crude oil that is transported via the L3R Program will be delivered to

refineries that directly or indirectly supply Minnesota and its neighboring

states, and thus help meet the needs of the people of Minnesota and its

neighboring states for refined petroleum products and help ensure the

adequacy and reliability of energy supply to Minnesota;

• The crude oil throughput of Midwestern and other U.S. refineries is not

dependent upon the demand for refined products in either the Midwest or

the U.S., as the U.S. is a large exporter of refined product to other parts of

the world; and

• The L3R Program represents a small portion of the additional

transportation capacity that will have to be utilized over the next decades.

The basis for those conclusions is set forth in the body of this report.


-15-

MINNESOTA PRODUCT SUPPLY AND DEMAND

In 2014, the most recent year for which data are available at the state level, petroleum

met 30.5 percent of the total Minnesota energy supply. Figure 13 below provides the

composition of Minnesota energy supply over the last 20 years and, as can be

observed, petroleum has long been an essential supply source for the people of

Minnesota.

As Figure 13 above illustrates, the proportion of total Minnesota energy supply

representing petroleum has been slowly declining over the last 20 years. However, this

is more attributable to total energy demand increasing with petroleum demand

remaining relatively constant, rather than petroleum demand itself significantly

decreasing. These trends are reflected in Figure 14 below, which restates total

Minnesota energy supply in terms of trillions of BTUs per year.

Figure 13

0%

20%

40%

60%

80%

100%

Composition of Minnesota Energy Supply



-16-

Minnesota has long been a leader in ethanol and other renewable and energy

conservation policies, and such policies can reduce the use of refined products in

Minnesota. They undoubtedly have had an effect on petroleum demand, although the

precise impact is somewhat difficult to measure. For example, fuel ethanol in 2014

comprised about 1.3 percent of the total Minnesota energy supply, up from about

0.8 percent in 1994. Much of the increase in fuel ethanol supply has likely been at the

expense of petroleum-based gasoline.

However, renewable energy efforts are not anticipated to substantially reduce the use of

refined products in Minnesota over the forecast period. In 2014, essentially all of the

gasoline in Minnesota sold at the retail pump contained at least 10 volume percent fuel

ethanol. That volume comprised only about 1.3 percent of the total Minnesota energy

supply in 2014, whereas refined products constituted 30.8 percent. Even if the fuel

ethanol consumption were to triple in Minnesota, entirely at the expense of petroleum

consumption, refined products would still satisfy about 28 percent of the total Minnesota

energy supply. Petroleum would still be the single largest source of energy for the

people of Minnesota.

Figure 14

0

500

1,000

1,500

2,000

2,500

Trill

ions

of B

TUs

per Y

ear

Sources of Minnesota Energy Supply



-17-

The transportation sector consumes slightly over 70 percent of the total Minnesota

supply of refined products, as shown in Figure 15 below. Most of the remainder

(~20 percent) is consumed by the industrial sector. Major uses of refined products in

the industrial sector include asphalt for road construction and agriculture-related diesel

demand.

Minnesota has two refineries: the Flint Hills Pine Bend and the Northern Tier Energy

St. Paul Park facilities. However, these two refineries do not provide all of the refined

products consumed in Minnesota. For some specialty refined products, such as

lubricants, refineries in other states (or imports) satisfy the entire state demand, as the

Minnesota refineries do not produce these specialty products. Absent access to the

private information of the two Minnesota refineries, the proportion of Minnesota refined

product demand that is specifically met by Minnesota refineries cannot be precisely

calculated. However, an approximate estimate can be made of the proportion of the

Minnesota transportation fuel demand (gasoline and diesel) that is satisfied by the two

local refineries.

Figure 15

0100200300400500600700800

Trill

ions

of B

TUs

per

Year

Sources of Minnesota Petroleum Demand

Transportation Commercial Industrial Electric Power Generation ResidentialSource: EIA


-18-

During a 2013 interview with a Minnesota House of Representative legislative analyst,

the director of communications for the privately-held Flint Hills company disclosed that

the Pine Bend refinery is estimated to produce about half of the gasoline and diesel

consumed in Minnesota.3 The Northern Tier Energy 2014 Form 10-K report indicates

that in 2014 approximately 81 percent of the gasoline and distillate (diesel plus jet fuel)

production from the St. Paul Park refinery was sold within Minnesota.4 The 10-K report

also discloses the total production volume of gasoline and distillate produced by the

refinery. Since the total sales of gasoline and diesel in Minnesota are known (from EIA

statistics), a simple calculation indicates that in 2014 the St. Paul Park refinery satisfied

about 23 and 30 percent of the Minnesota gasoline and diesel demand, respectively.

Accordingly, by difference, non-Minnesota refineries supplied about 27 and 20 percent

of the gasoline and diesel, respectively, consumed in Minnesota in 2014.

More generally, state boundaries have little to do with the distribution patterns of refined

products in the U.S. All refined products move freely across state boundaries and

refined product distribution patterns are mostly dictated by the location of the major

refining centers, the major demand centers (typically large cities), and the installed

network of refined product pipelines. Based upon my industry experience, refiners are

constantly seeking to sell their products into the markets that generate the highest

prices (net of transportation costs). For example, the director of communications for the

Flint Hills Pine Bend refinery indicated that the refinery satisfies 30 to 40 percent of

transportation fuel demand in the neighboring state of Wisconsin.5 Northern Tier

Energy, in its 2014 Form 10-K report, commented that it sells gasoline and diesel

3 Information Brief, Research Department, Minnesota House of Representatives, Minnesota’s Petroleum

Infrastructure: Pipelines, Refineries, Terminals, June 2013, pg. 6. 4 Northern Tier Energy LP, 2014 Form 10-K report, pg. 7. The latest year that state-level gasoline

consumption data are available is 2014. 5 Information Brief, Research Department, Minnesota House of Representatives, Minnesota’s Petroleum

Infrastructure: Pipelines, Refineries, Terminals, June 2013, pg. 6.


-19-

produced at the St. Paul Park refinery in Iowa, Nebraska, Oklahoma, South and North

Dakota, and Wisconsin.6

Figure 16 below provides the demand for refined products in Minnesota over the last 20

years.7 This figure is generated from the EIA State Energy Data System. At this point

in time, the data are available only through 2014. The 2015 final data are scheduled to

be released in June 2017. It should be noted that Figure 16 provides the demand data

in terms of kb/d, whereas the previous graph of Minnesota demand was in units of

trillions of BTUs per year.

Minnesota refined product demand increased steadily until about 2005, when higher oil

prices and various energy conservation measures began to curtail total refined product

demand. Since 2005, the demand trends for the different types of refined products

have varied. Asphalt, LPG, and heavy fuel oil (the latter is in the “Other” category in

Figure 16 above) have all experienced significant decreases in demand, whereas

diesel/No. 2 fuel oil demand in 2013 established a new demand peak. Gasoline, the

6 Northern Tier Energy LP, 2014 Form 10-K report, pg. 7. 7 Although it is a petroleum product, liquefied petroleum gas (LPG) demand is not included in Figure 15

because most LPG demand is met from non-refinery sources.

Figure 16

- 50

100 150 200 250 300 350 400

kb/d

Minnesota Refined Product Demand



-20-

single largest component of overall refined product demand, is down about 7 percent

from its mid-2000s peak, although in the last few years gasoline demand has been

relatively constant.

There is also significant variability in Minnesota product demand on a month-to-month

basis. Figure 17 illustrates the monthly Minnesota demand patterns for the key

transportation fuels (gasoline, diesel, and jet) since 2010. The source of the data for

Figure 17 is the EIA Prime Supplier survey for sales of refined products, which captures

a subset of the total sales in a state, but it also is the only source of monthly demand

data at the state level.

From the monthly demand data, any seasonality in product demand can also be

ascertained. Figure 18 shows the seasonal demand patterns for the transportation fuels

in Minnesota over the last 5 years. This figure is derived from the data found in

Figure 17 above. For example, gasoline demand in the spring is about 95 percent of

the Minnesota annual average, whereas summer gasoline demand is about 106 percent

of the annual average. Diesel exhibits the greatest seasonal demand patterns, primarily

due to the consumption patterns in the agricultural sector. Both the monthly and

Figure 17

020406080

100120140160180200

Jan-

10

May

-10

Sep

-10

Jan-

11

May

-11

Sep

-11

Jan-

12

May

-12

Sep

-12

Jan-

13

May

-13

Sep

-13

Jan-

14

May

-14

Sep

-14

Jan-

15

May

-15

Sep

-15

Jan-

16

May

-16

Sep

-16

kb/d

Monthly Minnesota Refined Product Demand

Gasoline Diesel/No. 2 FO JetSource: EIA


-21-

seasonal variability in refined product demand act to increase the supply-chain

complexity required to satisfy ongoing refined product requirements of the people of

Minnesota. In part because of the demand variability, the U.S. refining industry relies

heavily on inter-state shipments of refined products to meet the needs of all of the

individual U.S. states.

The EIA subdivides the country into a number of Refining Districts, and the district that

Minnesota falls into consists of the states of Minnesota, Wisconsin, North Dakota, and

South Dakota (hereafter referred to as the “Minnesota Refining District” for

convenience).8 The two Minnesota refiners comprise about 77 percent of the total

refining capacity in the Minnesota Refining District, based upon the EIA 2016 Refinery

Capacity Report. Accordingly, the preponderance of refined product supply in the

Minnesota Refining District is produced by the two Minnesota refineries.

The monthly transportation fuel production patterns for the Minnesota Refining District

are provided below in Figure 19. There is considerable volatility in the local supply of

transportation fuel in the Minnesota Refining District, and the local supply volume 8 The EIA generally refers to the district as the MN, WI, ND, SD Refining District.

Figure 18

7580859095

100105110115120125

Gasoline Diesel/No. 2 FO Jet

Perc

ent o

f Ann

ual A

vera

ge

Seasonality of Minnesota Product Demand

Spring Summer Fall WinterSource: EIA, Muse


-22-

occasionally changes by as much as 25 percent over a period of just a couple months.

A seasonality analysis (not shown) indicates that the lowest production levels are

typically in the spring, at about 90 percent of the annual average, likely due to the timing

of refinery maintenance turnarounds. This variability in local supply requires the refining

industry in the Minnesota Refining District to rely upon a combination of storage facilities

and inter-connectivity, primarily by pipeline, with refineries elsewhere in the U.S. to meet

the refined product requirements of the people of Minnesota and of its neighboring

states.

The exclusive use of storage facilities (or inventory) to accommodate the inevitable

mismatch between local demand and the immediately available local supply is only

possible if the local supply equals, or exceeds, the local demand for refined products.

However, the transportation fuel demand in Minnesota and its neighboring states

(Wisconsin, North and South Dakota, and Iowa) exceeds the local refinery supply.

Figure 19

0

100

200

300

400

500

600

kb/d

Minnesota Refining District Transportation Fuel Production

Gasoline Diesel/No. 2 FO JetSource: EIA


-23-

FIVE-STATE PRODUCT SUPPLY AND DEMAND

In addition to Minnesota itself, an analysis of petroleum supply and demand in

Wisconsin, North Dakota, South Dakota, and Iowa is also provided, as these are the

states that directly neighbor Minnesota. Minnesota and its neighbors are collectively

referred to as the Five-State Area. There are also some imports and exports of refined

products between the Five-State Area and Canada. However, these volumes are small,

and they can be reasonably ignored for any supply and demand analysis of the Five-

State Area.

The consideration of the neighboring states flows from my understanding that

Minnesota Rule 7853.0130(A) requires the consideration of the probable result of denial

of the L3R Program on the adequacy, reliability, or efficiency of energy supply to the

people of Minnesota and neighboring states. Thus, I understand the regulation to

explicitly require the consideration of the impact of denial of the L3R Program on

neighboring states, as these impacts may possibly affect Minnesota, either directly or

indirectly.

Figure 20 below shows the demand of refined products in the entire Five-State Area.

Minnesota demand is about one-third of the total Five-State Area demand, with a

considerably higher proportion of regional jet fuel demand and somewhat lower

proportion of diesel demand.


-24-

Demand data at the state level ends in 2014, but there are more recent data available

for regional demand trends. In PADD II, the 2015 demand for gasoline was up

(53 kb/d), jet fuel demand was essentially flat (up 4 kb/d,) and diesel demand decreased

(-34 kb/d, or -2.7 percent).9 For the period January to October 2016 versus the same

period in 2015, gasoline demand was up 52 kb/d, jet demand increased slightly, and

diesel demand dropped by 40 kb/d. At the national level, the EIA Short-Term Energy

Outlook (STEO) is projecting that gasoline demand will increase in 2017 by 54 kb/d,

distillate by 100 kb/d, and a 30 kb/d decrease for jet fuel demand.10

Within the Five-State Area, there are refineries located in Minnesota, North Dakota, and

Wisconsin. South Dakota and Iowa have no refineries. Figure 21 illustrates the volume

of refined products produced within the Five-State Area, including the contribution from

fuel ethanol, through 2015. Approximately 55 percent of the total demand for refined

products in the Five-State Area is satisfied by the local refineries within the area itself.

9 PADD is the term that the EIA uses for its regional segmentation of the U.S. PADD stands for

“Petroleum Administration for Defense District.” PADD II encompasses the Midwest and the Midcontinent.

10 EIA Short-Term Energy Outlook, October 2016, pg. 7. In the EIA’s terminology, “distillate” refers to both diesel and heating oil.

Figure 20

- 100 200 300 400 500 600 700 800 900

1,000

kb/d

Five-State Refined Product Demand



-25-

Among the major types of refined products, the proportion satisfied by the local

refineries differs. In recent years, the region has begun to produce an excess of

asphalt. Local refineries currently meet all of the jet demand, mostly due to a decrease

in jet demand rather than an increase in local production. Roughly 50 percent of the

Five-State Area demand for gasoline and diesel is supplied from local refineries. One

implication of the Five-State Area supply-demand balance is that for the key products of

gasoline and diesel, demand would have to be cut approximately in half in the

Five-State Area before it could be met by local supply. There is no combination of

renewable fuel or electrical car initiatives that promise to reduce gasoline and diesel

demand to this degree over the forecast period.

-

100

200

300

400

500

600

kb/d

Five-State Area Refinery Production

Fuel Ethanol Gasoline ex EtOH Jet Diesel Asphalt/HFO OtherSource: EIA, Muse

Figure 21


-26-

MIDWESTERN SUPPLY INTERDEPENDENCIES

In addition to the Five-State Area being net short for key refined products, the entire

Midwest historically has been significantly net short refined product, and this shortfall is

generally met by refineries located on the Gulf Coast. Although the Midwestern

supply-demand balance has become more balanced in recent years, the Midwest

continues to receive sizable volumes of refined product from the Gulf Coast. Figure 22

illustrates the complex network of refined product pipelines that link the neighboring

regions of Minnesota, Midwest, Midcontinent, and the Gulf Coast, plus the approximate

locations of the refineries that directly or indirectly supply the Five-State Area. In

addition to the high-capacity pipelines that deliver refined product from the Gulf Coast

into the inland markets, there is also an extensive network of smaller refined product

pipelines that link the neighboring states within the Midwest itself, thus creating

significant interdependencies between Minnesota, its neighboring states, and the

regions.


-27-

Muse has used its North American Refined Product Distribution model to quantify the

interdependencies within the Midwest itself and between the Midwest and other U.S.

regions. This proprietary analytical tool enables Muse to estimate the refined product

flows into and out of each individual state and each region of the U.S. and eastern

Canada. The model incorporates estimates of the refined product yield of all U.S. and

eastern Canadian refineries, state-level demand for refined products, and the costs and

capacities of the refined product pipelines and relevant barge and tanker routes.11

11 For greater accuracy, the state-level demand estimate for most states is further divided into two to eight

areas that are centered on refined product terminals that are pipeline connected or accessible to waterborne transport. Minnesota is divided into eight areas.

Figure 22

`

Magellan Pipeline Explorer Pipeline NuStar Energy TEPPCO Pipeline Sunoco Logistics (Inland) Buckeye Pipeline West Shore Pipeline Wolverine Pipeline Refinery

Refined Product Pipelines


-28-

To estimate the refined product yield of individual refineries, Muse first develops an

estimate of the refined product yield for each refinery based upon its crude oil capacity

and process configuration. The resultant yields for all refineries in each Refining District

is summed and compared to the EIA data for the respective Refining Districts, and then

any needed adjustments are made to the individual refinery estimates to reconcile back

to the EIA data.

The state-level demand for gasoline is estimated from historical data reported by the

states to the U.S. Federal Highway Administration.12 State-level jet fuel consumption is

estimated from the prime supplier data provided by the EIA supplemented by further

analysis by Muse, and the state-level diesel consumption is estimated from the EIA

Adjusted Sales of Fuel Oil and Kerosene report.13

Table 1 provides the estimated refined product supply-demand balance for Minnesota.

The analysis indicates that Minnesota is somewhat net long refined product.14 It is also

noteworthy that Minnesota simultaneously imports refined product from neighboring

states, while exporting refined product to neighboring states. In the U.S., this is not an

unusual situation, because the U.S. refined product distribution system seeks to

efficiently connect the refineries with the various demand centers to minimize

transportation costs without regard to state boundaries. The neighboring states of North

Dakota and Wisconsin also simultaneously import and export refined product. These

state-level refined product balances illustrate the high degree of interdependence

between neighboring states for the delivery of refined product from the refineries to the

consuming public. 12 Department of Transportation, Federal Highway Administration, Office of Highway Policy Information,

Monthly Motor Fuel Reported by States, Table MF-33GA, 2015 Reporting Period, available at http://www.fhwa.dot.gov/policyinformation/motorfuelhwy_trustfund.cfm.

13 EIA Prime Supplier Sales Volumes of Kerosene-Type Jet Fuel, available at http://www.eia.gov/dnav/pet/pet_cons_prim_a_epjk_p00_mgalpd_a.htm, and Adjusted Sales of Distillate Fuel Oil by End Use, available at http://www.eia.gov/dnav/pet/pet_cons_821dsta_a_EPD0_VAA_Mgal_a.htm.

14 Muse has assessed only the Minnesota supply-demand balance for refined product (as defined), not all petroleum products. The gasoline supply and demand estimates are net of ethanol. For other petroleum products, such as lubricants, Minnesota is a net importer.


http://www.fhwa.dot.gov/policyinformation/motorfuelhwy_trustfund.cfm

http://www.eia.gov/dnav/pet/pet_cons_prim_a_epjk_p00_mgalpd_a.htm

http://www.eia.gov/dnav/pet/pet_cons_821dsta_a_EPD0_VAA_Mgal_a.htm

-29-

Table 1 MINNESOTA SUPPLY - DEMAND BALANCE

ALL MINNESOTA REFINERIES IN OPERATION


Conv. and CBOB RFG Jet Diesel Total

Minnesota Supply

Refinery Production 178.1 9.9 27.8 115.4 331.2

Inbound Pipeline Origin DestinationAmoco Whiting, IN Minneapolis, MN - - - - - Magellan Tulsa, OK Minneapolis, MN - - - - - Magellan Tulsa, OK Mankato, MN - - - - - Magellan Tulsa, OK Marshall, MN - - - - - Magellan Tulsa, OK Alexandria/Sauk Centre, MN - - - - - Magellan Tulsa, OK Fargo, ND - - - - - Magellan Tulsa, OK Grand Forks, ND - - - - - Magellan Superior, WI Duluth, MN 11.6 - - 9.3 20.9 Nustar Mandan, ND Fargo, ND 2.3 - - - 2.3 Nustar Mandan, ND Alexandria/Sauk Centre, MN 19.5 - 1.5 10.5 31.4

Subtotal Inbound 33.4 - 1.5 19.8 54.6

Imports Canada - - - - -

Total Supply 211.4 9.9 29.3 135.2 385.8

Minnesota Demand

State Demand 153.5 - 24.7 78.8 256.9

Outbound Pipeline Origin DestinationKoch Minneapolis, MN Junction City, WI 8.1 - 0.1 8.8 17.1 Koch Minneapolis, MN Madison, WI 20.3 - - 14.7 35.0 Koch Minneapolis, MN Milwaukee, WI 18.5 9.9 3.1 4.6 36.1 Magellan Minneapolis, MN Wausau, WI - - - - - Magellan Minneapolis, MN Fargo, ND - - 0.3 9.1 9.4 Magellan Minneapolis, MN Grand Forks, ND 8.3 - 0.8 14.3 23.5 Magellan Minneapolis, MN Watertown, SD 2.8 - 0.3 4.8 7.8 Magellan Minneapolis, MN Sioux Falls, SD - - - - - Magellan Minneapolis, MN Des Moines, IA - - - - -

Subtotal Outbound 58.0 9.9 4.6 56.4 128.8

Exports Canada - - - - -

Total Demand 211.4 9.9 29.3 135.2 385.8

Source: Muse

Note: CBOB, RBOB, and ULSD are Conventional Gasoline Before Oxygenate Blending, Reformulated Gasoline Before Oxygenate Blending, and Ultra Low Sulfur Diesel, respectively.


-30-

The deficit in local refined product supply in the wider Five-State Area is met via a

variety of measures. In the case of Wisconsin, the deficit is met primarily by pipeline

deliveries from the large refineries located in the Chicago area, supplemented by

additional supply from refineries located in southern Illinois. Iowa is also partially

supplied out of the Chicago area, as well as from refineries located in the Midcontinent

(Kansas, Oklahoma). The supply from the Midcontinent also is the primary means by

which supply deficits in South Dakota and Minnesota itself are met. North Dakota is

also supplied from a refinery in central Montana.

There is also a high degree of interdependence between the neighboring regions of the

Midwest, Midcontinent, and the Gulf Coast. The first two regions have sizable inbound

and outbound refined product flows, and the Gulf Coast ships large volumes of refined

product to other regions of the U.S. Moreover, the highly integrated refined product

distribution system, particularly between the Midwest, Midcontinent, and the Gulf Coast,

provides a great deal of flexibility to respond to unscheduled refinery outages anywhere

in these regions. To illustrate this dynamic, the Muse Refined Product Distribution

model has been run a second time with the larger of the two Minnesota refineries shut

down.15 As might be expected, Minnesota’s refined product supply-demand balance

shifts from one that is somewhat net long to one that is significantly net short. Table 2

displays the resultant refined product supply-demand balance for Minnesota.

15 Refineries routinely schedule shut downs for maintenance reasons, and also occasionally experience

unscheduled shut downs due to electricity outages and other events.


-31-

The refined product supply shortfall is met by inbound pipeline deliveries, primarily on

the Magellan pipeline system, combined with a decrease of refined product shipments

Table 2 MINNESOTA SUPPLY - DEMAND BALANCE

FLINT HILLS PINE BEND REFINERY SHUTDOWN


Conv. and CBOB RFG Jet Diesel Total

Minnesota Supply

Refinery Production 48.9 2.4 6.0 16.7 74.0

Inbound Pipeline Origin DestinationAmoco Whiting, IN Minneapolis, MN 32.4 - 5.6 - 38.0 Magellan Tulsa, OK Minneapolis, MN 25.7 - 9.0 42.6 77.3 Magellan Tulsa, OK Mankato, MN 6.4 - 0.5 5.3 12.3 Magellan Tulsa, OK Marshall, MN 4.5 - 0.5 6.8 11.7 Magellan Tulsa, OK Alexandria/Sauk Centre, MN - - - - - Magellan Tulsa, OK Fargo, ND 0.3 - 0.6 4.6 5.5 Magellan Tulsa, OK Grand Forks, ND 4.8 - 1.0 5.7 11.4 Magellan Superior, WI Duluth, MN 13.1 - - 7.8 20.9 Nustar Mandan, ND Fargo, ND 6.0 - 0.1 1.1 7.2 Nustar Mandan, ND Alexandria/Sauk Centre, MN 19.5 - 1.5 10.5 31.4

Subtotal Inbound 112.6 - 18.8 84.3 215.8

Imports Canada - - - - -

Total Supply 161.6 2.4 24.8 101.0 289.8

Minnesota Demand

State Demand 153.5 - 24.7 78.8 256.9

Outbound Pipeline Origin DestinationKoch Minneapolis, MN Junction City, WI 8.1 - 0.1 8.8 17.1 Koch Minneapolis, MN Madison, WI - - - - - Koch Minneapolis, MN Milwaukee, WI - 2.4 - 13.3 15.8 Magellan Minneapolis, MN Wausau, WI - - - - - Magellan Minneapolis, MN Fargo, ND - - - - - Magellan Minneapolis, MN Grand Forks, ND - - - - - Magellan Minneapolis, MN Watertown, SD - - - - - Magellan Minneapolis, MN Sioux Falls, SD - - - - - Magellan Minneapolis, MN Des Moines, IA - - - - -

Subtotal Outbound 8.1 2.4 0.1 22.2 32.8

Exports Canada - - - - -

Total Demand 161.6 2.4 24.8 101.0 289.8

Source: Muse

Note: CBOB, RBOB, and ULSD are Conventional Gasoline Before Oxygenate Blending, Reformulated Gasoline Before Oxygenate Blending, and Ultra Low Sulfur Diesel, respectively.


-32-

Minnesota

ChicagoNew York

Houston

Tulsa

Imports+50

Exports-210

+105

into Wisconsin from Minnesota. The resultant Wisconsin supply shortfall is in turn met

by increased flows from refined product pipelines that originate in the Chicago area (not

shown in Table 2). A portion of the demand in western Wisconsin continues to be met

from shipments from Minnesota, as this area is not pipeline-connected to Chicago.

It is notable that the shut down of a large Minnesota refinery results in significant shifts

in the inter-regional flows in the U.S.16 Figure 23 displays the change in the inter-

regional refined product flows that result from a single refinery shut down in Minnesota.

The loss of refined product production in the Midwest results in increased flows from the

large Gulf Coast refining complex. At the national level, the shut down of a Minnesota

refinery results in higher refined product imports on the East Coast and lower exports

from the Gulf Coast.

16 In the short-term, the refined product shortfall of a Minnesota refinery shut down would be partially met

by the drawdown of refined product inventories in the Midwest. However, Midwestern refineries are currently operating close to, or at, their maximum capacity. Ultimately, any Midwestern production losses must be replaced by higher flows from the Gulf Coast.

Figure 23

Source: Muse


-33-

Figure 23 above also illustrates the fundamental price setting mechanism for refined

product in the Midwest. The northbound flows of refined product act to link the

Midwestern prices primarily to those on the Gulf Coast, rather than to the local refinery

margins. Midwestern refined product prices typically trade at a premium to those on the

Gulf Coast, but the Midwestern prices must be higher than those on the Gulf Coast

since the transportation costs must be paid, or no one would ship refined product north.

The linkage to the Gulf Coast acts to moderate the refined product pricing volatility that

would be otherwise experienced in the Midwest when the local refineries experience

unexpected outages. The Gulf Coast has the largest concentration of refining capacity

in the world, which enables the region to quickly supply additional refined product to the

Midwest when needed.

Figure 24 shows the historical pricing differentials between Minnesota retail (at the

pump) conventional regular gasoline and the bulk spot price for conventional regular

gasoline on the Gulf Coast.17 The bulk spot price is representative of market

transactions of gasoline quantities of about 1 million gallons. As can be observed, the

Minnesota retail price for gasoline falls into a band that is typically 60 to 80 cents per

gallon (¢/gal) over the Gulf Coast bulk spot price. It should be noted that the differential

shown on Figure 24 captures the northbound pipeline costs, the trucking costs between

the Minnesota refined product terminals and retail stations, the entire marketing margin

between retail prices and the bulk spot prices, federal and state taxes (Minnesota taxes

plus the Federal excise tax total to 47 ¢/gal), and any specification differences between

the Minnesota and Gulf Coast gasoline grades.

17 The EIA data are obtained from the Minnesota Gasoline and Diesel Retail Prices report, available at

http://www.eia.gov/dnav/pet/pet_pri_gnd_dcus_nus_m.htm. Muse obtains bulk spot prices from Argus Media via a paid subscription service.


http://www.eia.gov/dnav/pet/pet_pri_gnd_dcus_nus_m.htm

-34-

The potential for an outage at a refinery in Minnesota or one of its neighboring states is

not just a hypothetical scenario. The public in Minnesota and the other states in the

Five-State Area will experience periodic shortfalls in refined product supply with the

corresponding price spikes when local supply falls short of local demand. Only the

refined product pipeline interconnectivity with neighboring regions enables Minnesota

and its neighboring states to manage such periodic supply shortfalls and minimize the

resultant refined product pricing volatility. For example, when the Five-State Area

cannot obtain refined product supply from other refineries in the Midwest and the

Midcontinent, there will be almost an immediate reaction in the fuel prices in Minnesota.

On August 8, 2015, the large BP Whiting refinery in the Chicago area unexpectedly shut

down its largest crude oil distillation unit. Gasoline prices in the Midwest reacted almost

immediately. Chicago bulk spot prices for regular gasoline climbed 16.35 ¢/gal on

August 10 (Monday), and rose another 44.72 ¢/gal on Tuesday.18 Retail gasoline prices

in both Chicago and Minnesota also reacted to the BP refinery outage as shown in

18 The spot pricing data are from Argus.

Figure 24

- 20 40 60 80

100 120 140

Cen

ts p

er G

allo

nMinnesota Retail Gasoline less Gulf Coast Spot

Minnesota less Gulf Coast 3-Month AverageSources: Argus Media, EIA


-35-

Figure 25, before prices retreated as additional gasoline supplies entered the market in

subsequent days.19

The refineries throughout the Midwest play an essential role in satisfying refined product

demand in the Five-State Area, and are thus relevant to the Commission’s evaluation of

the merits of the L3R Program. This point has been previously made by Laura Otis with

the Minnesota Department of Commerce. In her written testimony for a MPUC hearing,

she stated that: “It is clear that there exists a strong interdependence between

Minnesota and other states in the region for refined product supply.”20 Department of

Commerce witness Otis further elaborated on this point in the following question and

answer:21

“Q. Please further elaborate on the negative consequences Minnesota consumers would experience as a result of supply shortages in connected markets such as Chicago. [Emphasis added.]

19 The retail gasoline prices were obtained from GasBuddy.com. Retail prices are only available at the

state level for Minnesota from this source. The crude oil distillation unit at the BP Whiting refinery was restarted on August 25.

20 Direct Testimony of Laura B. Otis on behalf of The Minnesota Department of Commerce, Division of Energy Resources, MPUC Docket No. PL-9/CN-13-153OAH, February 18, 2014, pg. 11.

21 Ibid, pg. 15.

Figure 25

2.30

2.50

2.70

2.90

3.10

3.30

3.50

3.70

Dolla

rs p

er G

allo

n

Retail Gasoline Prices

Minnesota ChicagoSource: Gasbuddy.com


-36-

A. Refiners could divert petroleum product supplies from the Minnesota market to take advantage of higher prices in the Chicago market, thus decreasing supply available to Minnesotans. As a result, the market would adjust prices upward to keep supply and demand in balance. As a consequence of market interconnection, Minnesota has an interest in the adequacy of supply to other parts of PADD II with petroleum and petroleum pipeline connections to our area.”

The importance of the regional petroleum infrastructure, beyond the borders of

Minnesota, is further highlighted by the fact that inventories of refined product are

maintained on a “just-in-time” basis, meaning that refineries operate “at or near the

lower operational inventories for all products.”22 Accordingly, the market has some

difficulty in adjusting to changes in demand.23 Limited inventory increases price

uncertainty and reduces supply resilience on the market. As a result, the market is not

buffered from supply problems caused by refinery issues, such as fires, outages, or

routine maintenance.24 As noted in the 2012 Quad Report, these events cause upward

price pressure in all areas of the country, not just regional impacts.25

The refined product distribution interdependencies between Minnesota and its

neighboring states, and between the Midwest and its neighboring regions, directly

address why the L3R Program is needed to better ensure the adequacy, reliability, and

efficiency of the refined product supply to the people of Minnesota. Refineries must

have adequate and reliable access to crude oil to produce the refined product required

by the Minnesota public, and the L3R Program better ensures that refineries in

Minnesota, in neighboring states, and neighboring regions have that access. As

discussed in the Crude Oil Demand and Disposition section of this report, crude oil

transported by the L3R Program will be ultimately delivered to refineries in Minnesota,

refineries in its neighboring states, and refineries in neighboring regions. To help meet

the transportation fuel needs of the Minnesota and its neighboring states, it is vitally

important that other Midwestern refineries receive crude oil from safe, reliable supply 22 2012 Minnesota Department of Commerce Energy Policy and Conservation Quadrennial Report (2012

Quad Report), pg. 34. 23 Ibid. 24 Ibid, pg. 35. 25 Ibid.


-37-

sources. The refined product produced from the crude oil transported by the L3R

Program will be available to the Minnesota public from Minnesota refineries, refineries in

neighboring states, and refineries in neighboring regions. Consequently, the L3R

Program significantly helps ensure the future adequacy and reliability of the energy

supply of the people of Minnesota and its neighboring states.


-38-

SUPPLY OF CRUDE OIL IN MINNESOTA AND NEIGHBORING STATES

Minnesota is one of 19 U.S. states that does not produce any crude oil. Today,

Minnesota obtains all of the crude oil processed in its refineries from either the U.S. or

Canada. EIA statistics indicate that 2008 was the last time that Minnesota refineries

imported crude oil from a country other than Canada (1 kb/d, from Venezuela). In fact,

the only pipeline by which non-Canadian crude oil imports could be delivered to

Minnesota refineries was taken out of service in early 2013. The refineries in Wisconsin

and North Dakota have never had pipeline access to non-Canadian imports.

Elsewhere in the Midwest, the crude oil sources are essentially limited to the U.S. and

Canada. Through September 2016, EIA statistics indicate that PADD II refineries

imported 2,222 kb/d of crude oil, of which only 41 kb/d was from a country other than

Canada. Both refinery capacity and crude oil runs in PADD II have been increasing in

recent years. Figure 25 provides the total refinery capacity by region in PADD II. In the

last 5 years, total refinery capacity has been increasing in all four of the regions shown

on Figure 26. Total refinery capacity is up 213 kb/d over this period. Figure 26 also

displays the actual crude oil runs in PADD II. Crude oil runs have increased by

237 kb/d between 2011 to September 2016. All of the refineries in PADD II can be

served directly or indirectly by the Enbridge Mainline System.


-39-

Pipeline transportation is the predominant means by which crude oil is delivered to the

refineries in Minnesota, its neighboring states, and throughout the Midwest and the

Midcontinent. Figure 27 below displays the proportion of domestic and foreign crude oil

that was delivered by pipeline to PADD II refineries since 1998. As a practical matter,

nearly all foreign crude oil is delivered to PADD II refineries by pipeline, with a relatively

small volume of rail deliveries being a very recent development. The situation is similar

for domestic crude oil deliveries, although some of the non-pipeline receipts are via

barge and truck, rather than rail.

Figure 26

- 500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

2010 2011 2012 2013 2014 2015

kb/d

PADD II Refining Capacity and Crude Oil Runs

Five-State Area Upper Midwest Lower Midwest

Midcontinent PADD II Crude RunsSource: EIA


-40-

It is certain that pipelines will remain the predominant delivery system for crude oil to the

PADD II refineries. Current pipeline crude oil deliveries to PADD II refineries exceed

3,500 kb/d, and this volume will never be predominately supplanted by an alternative

delivery mode. However, rail is becoming a more important transportation mode for the

Canadian crude oil producers. Figure 28 below provides the monthly deliveries of

Canadian crude oil to the Midwest and the Midcontinent (PADD II), the East Coast

(PADD I), the Gulf Coast (PADD III), and the balance of the U.S. 26 As can be

observed, rail deliveries have been climbing steadily over the last several years

because of the lack of pipeline capacity. Due to the layout of the U.S. railway system,

much of the Canadian crude oil rail shipments to all but PADD IV/V shown on Figure 28

can be expected to transit Minnesota.

26 The EIA statistics capture only deliveries to U.S. destinations. Western Canadian crude oil is also

railed to Canadian destinations.

Figure 27

93%

94%

95%

96%

97%

98%

99%

100%

Proportion of Pipeline Receipts for PADD II Refineries

Domestic Crude Oil Receipts by Pipeline Foreign Crude Oil Receipts by PipelineSource: EIA


-41-

Figure 28

0

50

100

150

200

250

300

kb/d




-42-

CANADIAN SUPPLY FORECAST COMPARISON

There are several authoritative public long-term forecasts of Western Canadian crude

oil production. The NEB, which is an independent federal, quasi-judicial regulator,

provides Canadian crude oil production outlooks every other year. CAPP releases

crude oil supply and production forecasts annually, and the associated report contains a

great deal of information regarding the basis for the Canadian crude oil supply outlook

and of crude oil market developments. The Alberta Energy Regulator (AER), a

quasi-judicial regulatory agency of the Government of Alberta, provides annual crude oil

production outlooks for Alberta, which constitutes the preponderance of Western

Canadian crude oil production. In Muse’s experience, the CAPP crude oil supply

forecasts are commonly used for pipeline regulatory purposes in Canada and the U.S.

Only CAPP releases both a production and a supply forecast. A production forecast

provides the volume of crude oil that is expected to be extracted from the underground

crude oil reservoirs, whereas a supply forecast is projecting the volume of crude oil that

will be supplied (or delivered) to the market. In most areas of the world, a production

forecast and a supply forecast would be identical. However, in Western Canada, the

volume of individual grades (e.g., light, heavy) of crude oil produced can differ

significantly from the volume of the individual crude oil grades that are supplied to the

market. This is attributable to the following factors:

• The need to add diluent to the heavy crude oil grades to enable them to

be transported by pipeline, as in their natural state they are too viscous to

be economically transported via pipeline.27 The use of diluent can

27 The need to use diluents to transport heavy crude oils by pipeline is not a uniquely Canadian issue.

Heavy crude oils produced in Venezuela, Colombia, and central California all require the use of diluents to enable pipeline transport.


-43-

increase the volume of crude oil that must be transported to the market by

over 40 percent.

• A considerable volume of heavy crude oil is upgraded to a lighter, more

valuable crude oil at a number of facilities in Western Canada. The

upgrading of heavy crude oil to lighter crude oils in the Canadian

upgraders changes the respective volume of light and heavy crude oil

supplied to the market.

• A volumetric loss typically occurs when a heavy crude oil is upgraded to a

lighter crude oil. The magnitude of the volumetric loss depends upon the

specific processing technology used in the upgrader.

• Finally, some light crude oil is used as a diluent to enable heavy crude oil

to be transported by pipeline, which also influences the ultimate volume of

light versus heavy crude oil supplied to the market.

Consequently, the assumptions used by individual forecasters regarding the amount of

upgrader capacity added over time, the type of upgrading capacity, and the amount of

light crude oil used as diluent will result in somewhat different forecasts of the volume of

crude oil supplied to the market, even if the underlying crude oil production forecast is

identical.

The June 2016 CAPP supply forecast is the fundamental basis for the Western

Canadian crude oil supply outlook used for this analysis.28 It is the only one that

specifically provides a crude oil supply outlook for Western Canada, and it is very

current. The others provide only a crude oil production outlook. In addition, CAPP

describes its 2016 crude oil supply forecast as being one that is reflective of the current

crude oil price environment. In the introduction of the report, CAPP states:

28 CAPP Crude Oil Forecast, Markets and Transportation, June 2016.


-44-

The 2016 edition of this publication examines the impact of current oil prices

on production and reports the latest regulatory delays in the pipeline approval

process as well as other pertinent developments. 29

The NEB released its long-term energy outlook, Canada’s Energy Future 2016, in

January 2016. The report is intended to provide Canadians with a key reference point

to discuss the country’s energy future, and relies upon the extensive energy market

expertise of the NEB’s technical staff. In addition, energy experts from government,

industry, environmental organizations, and academia across Canada provided input on

the preliminary assumptions and results of the report. In October 2016, the NEB

released a report update that captured several recently announced climate policies, and

revised the crude oil price assumptions used for the outlook.30 For the outlook, the NEB

utilizes three crude oil price scenarios that it terms Reference, High, and Low Price

Cases.

Figure 29 below provides a comparison of the NEB 2016 Updated Reference Case

production forecast to the CAPP production forecast of the same year.31 Until about

2020, the production forecasts are very close. Post-2020, the NEB growth rate of crude

oil production is slightly higher than that of CAPP, and over the last 5 years of the

forecast period shown in Figure 29 the NEB crude oil production averages 323 kb/d

over the CAPP production forecast.

29 Ibid, pg. 1. 30 National Energy Board; Canada’s Energy Future 2016 Update; pg. 5. 31 The data for the NEB crude oil production outlook were obtained at the following link: https://apps.neb-

one.gc.ca/ftrppndc4/dflt.aspx?GoCTemplateCulture=en-CA. The CAPP report is: Crude Oil: Forecast, Markets and Transportation, June 2016.


https://apps.neb-one.gc.ca/ftrppndc4/dflt.aspx?GoCTemplateCulture=en-CA

https://apps.neb-one.gc.ca/ftrppndc4/dflt.aspx?GoCTemplateCulture=en-CA

-45-

A comparison of the CAPP 2016 forecast to all three of the updated NEB price

scenarios (Reference, Low, and High) is shown below in Figure 30. The CAPP forecast

is virtually identical to the NEB Low Price scenario until about 2028, at which point the

CAPP crude oil production forecast is about 4 percent higher than the NEB Low Price

scenario. Crude oil production under the NEB High Price Scenario is about 13 percent

higher than the Reference Price Scenario in 2030, and production under the Low Price

Scenario is about 10 percent lower. However, the crude oil prices in 2030 for the High

and Low Price Cases are 37 percent above and 47 percent below the Reference Case

price, respectively. This indicates that the Western Canadian crude oil production

volume is comparatively resistant to changes in the absolute crude oil price.

Figure 29

-

1,000

2,000

3,000

4,000

5,000

6,000

kb/d


CAPP 2016 NEB Oct 2016 Reference CaseSource: NEB, CAPP


-46-

The final comparison is of Western Canadian bitumen (extra-heavy crude oil)

production, which comprises the preponderance of the total Western Canadian crude oil

production. A comparison of the latest available NEB, AER, and CAPP outlooks is

shown on Figure 31 below.32 The outlooks are similar through 2020, and the CAPP

bitumen production forecast is generally the lowest of the four. Figure 31 also provides

some perspective on the historical growth rate of Western Canadian bitumen

production.

32 The AER outlook is provided in ST98-2016; Alberta’s Energy Reserves 2015 and Supply/Demand

Outlook 2016-2025; Figure S3.8; pg. 3-21. The AER forecast ends in 2025.

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

kb/d


CAPP 2016 NEB Reference NEB Low NEB HighSource: NEB, CAPP

Figure 30


-47-

In summary, the NEB, CAPP, and AER forecasts differ in the details, but more broadly

communicate the same message — the forward outlook for Western Canada is one of

significant increases in crude oil supply. As a practical matter, such increases must be

transported to the market by some combination of pipeline and rail. The L3R Program

represents a small portion of the incremental transportation capacity that will have to be

added over the next decade and beyond.

Figure 31

- 500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

kb/d

Western Canadian Bitumen Production

CAPP 2016 NEB Oct 2016 Reference Case AER 2016Source: NEB, CAPP, AER


-48-

CRUDE OIL MARKET OVERVIEW

To analyze the North American crude oil markets, Muse generally aggregates the

150+ individual North American refineries into regional submarkets that share similar

crude oil transportation options.33 Five submarkets are accessible to Canadian crude

oil transported via the Mainline: Upper Midwest; Lower Midwest; Ontario/Quebec;

Midcontinent; and the Gulf Coast.34 Figure 32 provides the geographical definition of

the five refinery submarkets accessible, directly or indirectly, via the Enbridge Mainline

System, and Appendix 2 shows the major crude oil pipelines throughout the U.S.

33 For purposes of this report, North America consists of Canada and the United States. 34 In addition to these markets, crude oil can also be delivered to Montreal and then potentially

transported via small tankers to the global crude oil market. In the context of the total North American crude oil supply and demand balance, these potential shipments are immaterial.

Mobil Cenex

met-Great Falls

lips 66 Tesoro-Mandan

Sinclair-Casper

HollyFrontier-CheyenneSinclair-Rawlins

vron

rontierSuncor-Denver

Phillips 66-Ponca City

Northern Tier-St. PaulFlint Hills-Pine Bend

United-Warren

BP-WhitingBP/HuskyCitgo-Lemont

WRB-Borger

Alon-Big Spring

HollyFrontier-Artesia Delek-Tyler

Alon

Valero-Memphis

Valero

CITGO

Flint Hills

Marathon

Valero

MAPValero Petrobras

Phillips 66

ShellPlacid

Shell

Chalmette

CITGO

Monroe

Heavy Sour

Medium Sour

Light Sweet

REFINERY CRUDESLATE

Suncor-Montreal

Harvest

us y

Western

Chevron

Philadelphia Energy

CRC

Phillips 66

Billings

Valero

Valero

MarathonDeer ParkMotiva

Sarnia

UPPER MIDWEST

ONTARIO / QUEBEC

MIDCONTINENT

GULF COAST

LOWER MIDWEST

Imperial Oil

Savannah-Nustar

MotivaMarathon

MotivaPhillips 66Valero

PBF Energy

ExxonMobil

Marathon

ExxonMobil

PBF EnergyPBF Energy

Marathon-CatlettsburgWBR-Wood River

Marathon-RobinsonHusky-Lima

Marathon-Canton

Imperial-Nanticoke

Valero-Lévis

NCRA-McPherson

HollyFrontier-El Dorado

CVR-Coffeyville

CVR-WynnewoodHollyFrontier-Tulsa

Valero-Ardmore

Valero-McKee

Hunt-Tuscaloosa

Flint Hills

Valero

Western-El Paso

ExxonMobil-Joliet

ImperialShellSuncor

Superior-Calumet

Calumet-Shreveport

ExxonMobilLyondell

Valero

Phillips 66

Marathon-Detroit

Lion-El Dorado

Capacity indicatedby size

PADD VPADD IV

PADD IPADD IIPADD III

Figure 32


-49-

The Upper Midwest and Ontario/Quebec submarkets are primarily accessible from

Western Canada via the Enbridge Mainline System.35 The rest of the submarkets can

be accessed via both the Enbridge Mainline System and the Keystone pipeline. This

latter pipeline originates at Hardisty, Alberta. The Midcontinent and Gulf Coast can be

accessed from the Enbridge Mainline System via the Flanagan South and Spearhead

pipelines.

UPPER MIDWEST

The Upper Midwest is a major demand center for Canadian light and heavy crude oil

today, and will remain so for the foreseeable future. Table 3 provides the capacities of

the refineries located in the Upper Midwest.36

35 Quebec is reached via Enbridge Line 9, which is owned by Enbridge but is not part of the Mainline

system. 36 The U.S. refinery capacities in this report section are obtained from the EIA Refinery Capacity Report,

June 25, 2014, available at http://www.eia.gov/petroleum/refinerycapacity/. Two small North Dakota refineries that are in the planning or construction phase are not shown.

Table 3

State kb/d

BP Whiting Indiana 413.5 BP-Husky Toledo Ohio 153.0 Calumet Superior Wisconsin 38.0 CITGO Lemont Illinois 175.9 ExxonMobil Joliet Illinois 238.6 Flint Hills Pine Bend Saint Paul 290.0 Marathon Detroit Michigan 132.0 Western Refining St. Paul Minnesota 88.9 PBF Toledo Ohio 160.0 Tesoro Mandan North Dakota 73.9

Total 1,763.8

UPPER MIDWEST

Refinery


http://www.eia.gov/petroleum/refinerycapacity/

-50-

Figure 33 provides the volume of Western Canadian crude oil delivered to this

submarket over the last 7 years. Canadian crude oil supply has been growing steadily,

and now the volume of Canadian crude oil supply exceeds that supplied from U.S.

sources.

LOWER MIDWEST

Total refinery capacity for this region is almost 1,300 kb/d, as shown in Table 4.

Marathon is currently engaged in constructing two condensate splitters at its Canton

and Catlettsburg refineries with a capacity of 25 and 35 kb/d, respectively. The

incremental capacity of the splitters is included in the refinery capacities shown in

Table 4. In addition, Marathon is expanding its light crude oil capacity by 30 kb/d at its

Robinson refinery.37

37 Marathon Petroleum Company Investor Presentation, May 2014, slide 26.

Figure 33

-

200

400

600

800

1,000

1,200

1,400

2007 2008 2009 2010 2011 2012 2013 2014 2015 Jan-Oct2016

kb/d

Canadian Crude Oil Runs in Upper Midwest

Source: EIA, Muse


-51-

Table 4

Western Canadian crude oil runs in this submarket are provided in Figure 34. The

relatively recent increase in Canadian crude oil runs is attributable to the start up in the

summer of 2010 of the Keystone pipeline to this region. The Keystone pipeline delivers

Canadian crude oil to the large WRB Wood River, Illinois, refinery and the Patoka,

Illinois, pipeline hub. This latter location is connected to a number of refineries in the

Lower Midwest.

Figure 34

State kb/d

CountryMark Mt. Vernon Indiana 27.1 Husky Lima Ohio 152.0 Marathon Canton Ohio 93.0 Marathon Catlettsburg Kentucky 273.0 Marathon Robinson Illinois 212.0 Valero Memphis Tennessee 190.0 WRB Wood River Illinois 314.0

Total 1,261.1

Refinery

LOWER MIDWEST

- 50

100 150 200 250 300 350 400 450

2007 2008 2009 2010 2011 2012 2013 2014 2015 Jan-Oct2016

kb/d

Canadian Crude Oil Runs in Lower Midwest

Source: EIA, Muse


-52-

ONTARIO/QUEBEC

Table 5 provides the current capacity of the refineries located in the Ontario/Quebec

submarket.38 The United Warren refinery, located in western Pennsylvania, is also

included in this submarket because it receives its crude oil supplies via Ontario on the

Enbridge Mainline System, and has substantially the same crude oil transportation

economics as the Ontario refineries.

MIDCONTINENT

Table 6 provides the refinery capacities in the Midcontinent submarket. Muse’s

definition of the Midcontinent submarket includes the Valero McKee and the WRB

Borger refineries in the Texas Panhandle, as well as the HollyFrontier Artesia refinery in

southeastern New Mexico. These three refineries can receive crude oil via the Cushing

pipeline hub.

38 The Canadian refinery capacities are obtained from the Oil & Gas Journal, 2016 Worldwide Refining

Survey, December 7, 2015.

State/Province kb/d

Nova Corunna Ontario 80.0 Imperial Nanticoke Ontario 113.5 Imperial Sarnia Ontario 119.0 Shell Sarnia Ontario 71.0 Suncor Sarnia Ontario 85.0 Suncor Montreal Quebec 137.0 Valero Levis Quebec 235.0 United Warren Pennsylvania 65.0 Total 905.5

ONTARIO/QUEBEC

Refinery

Table 5


-53-

Figure 35 shows the Canadian crude oil runs at the Midcontinent refineries. Runs have

approximately doubled in the last few years, reflecting the start up of the Keystone

pipeline to Cushing, Oklahoma, in early 2011.

Table 6

Figure 35

State kb/d

CVR Energy Coffeyville Kansas 115.0 CVR Energy Wynnewood Oklahoma 70.0 HollyFrontier El Dorado Kansas 138.0 HollyFrontier Artesia New Mexico 102.0 Holly Frontier Tulsa Oklahoma 155.3 CHS McPerson Kansas 86.0 Phillips 66 Ponca City Oklahoma 200.0 Valero Ardmore Oklahoma 86.0 Valero McKee Texas 168.0 WRB Borger Texas 146.0

Total 1,266.3

Refinery

MID-CONTINENT

- 20 40 60 80

100 120 140 160 180

2007 2008 2009 2010 2011 2012 2013 2014 2015 Jan-Oct2016

kb/d

Canadian Crude Oil Runs in Midcontinent

Source: EIA, Muse


-54-

GULF COAST

Total Gulf Coast refining capacity is approximately 8,000 kb/d, and this area has the

greatest concentration of refining capacity in the world. The Gulf Coast is further

subdivided by Muse into the Corpus Christi, Houston, Beaumont/Port Arthur/Lake

Charles, and Louisiana/Mississippi submarkets, reflecting the somewhat different

logistical costs and constraints associated with reaching these areas from Western

Canada.

Historically, the Canadian crude oil runs on the Gulf Coast have not been appreciable

relative to the amount of refining capacity on the Gulf Coast. Figure 36 provides the

historical volumes.39 Table 7 details the crude oil distillation capacity of the individual

Gulf Coast refineries.

39 It is possible that some of the Canadian crude oil supply to the Gulf Coast shown on Figure 33

originated from the fields offshore Atlantic Canada, rather than Western Canada. The EIA also reports some relatively small deliveries of Canadian crude oil to various terminals on the Gulf Coast, but not the refinery that ultimately processed the barrels.

Figure 36

-

50

100

150

200

250

300

2007 2008 2009 2010 2011 2012 2013 2014 2015 Jan-Oct2016

kb/d

Canadian Crude Oil Runs on Gulf Coast

Source: EIA, Muse


-55-

State kb/d

Corpus Christi EIACITCO Corpus Christi Texas 157.5 Flint Hills Corpus Christi Texas 295.6 Valero Corpus Christi Texas 293.0 Valero Three Rivers Texas 89.0

Subtotal 835.1 Houston

ExxonMobil Baytown Texas 560.5 LyondellBasell Houston Texas 263.8 Marathon Galveston Bay Texas 459.0 Marathon Texas City Texas 86.0 Pasadena Refining Pasadena Texas 112.2 Phillips 66 Sweeny Texas 247.0 Deer Park Refining Deer Park Texas 285.5 Valero Houston Texas 100.0 Valero Texas City Texas 225.0

Subtotal 2,339.0 Beaumont/Port Arthur/Lake Charles

CITGO Lake Charles Louisiana 427.8 ExxonMobil Beaumont Texas 344.6 Motiva Port Arthur Texas 603.0 Phillips 66 Westlake Louisiana 260.0 Total Port Arthur Texas 225.5 Valero Port Arthur Texas 335.0

Subtotal 2,195.9 Louisiana/Mississippi/Alabama

Alon Krotz Springs Louisiana 80.0 Chalmette Refining Louisiana 192.5 Chevron Pascagoula Mississippi 330.0 ExxonMobil Baton Rouge Louisiana 502.5 Hunt Tuscaloosa Alabama 36.0 Marathon Garyville Louisiana 539.0 Motiva Convent Louisiana 235.0 Motiva Norco Louisiana 237.7 Phillips 66 Alliance Louisiana 247.0 Placid Port Allen Louisiana 75.0 Shell Saraland Alabama 91.6 Valero Mereaux Louisiana 125.0 Valero Norco Louisiana 215.0

Subtotal 2,906.3

Grand Total 8,276.3

Refinery

GULF COAST

Table 7


-56-

RELATIONSHIP BETWEEN REFINERY RUNS AND PRODUCT DEMAND

The volume of crude oil processed by the U.S. refining industry is not dependent upon

domestic demand for refined product. Figure 37 illustrates the relationship between

U.S. light refined product demand and refinery crude oil runs.40 As shown by Figure 37,

the rate of growth in crude oil runs has considerably exceeded the rate of growth for

domestic product demand.

U.S. crude oil runs have been increasing because of rising volumes of refined product

exports. Figure 38 provides the volume of U.S. light refined product exports over the

same time period as Figure 37 above. Light product exports currently exceed

2,000 kb/d. From a global perspective, U.S. refiners are highly competitive due to their

size, operational efficiency, and the comparatively low cost of energy (primarily natural

gas) in the U.S. relative to other global refining centers.

40 “Light refined product” means “gasoline, jet fuel, and diesel/light heating oil” throughout this report.

Figure 37

- 2,000 4,000 6,000 8,000

10,000 12,000 14,000 16,000 18,000

kb/d

U.S. Light Refined Product Demand versus Crude Runs

Gasoline Jet Diesel Crude Oil RunsSource: EIA


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It is the same situation in PADD II as it is in the U.S. as a whole. Light refined product

demand growth is relatively flat, with some recent growth, but PADD II refiners have

been steadily increasing their crude oil runs. Figure 39 provides these historical trends.

Figure 39

Figure 38

-

500

1,000

1,500

2,000

2,500

kb/d

U.S. Light Refined Product Exports

Gasoline Jet DieselSource: EIA

- 500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000

kb/d

PADD II Light Refined Product Demand versus Crude Oil Runs

Gasoline Jet Diesel Crude Oil RunsSource: EIA


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However, PADD II refineries do not have to physically export their refined product to

increase crude oil runs. This is because higher refined product production in the

PADD II refineries results in reduced transfers of light refined product from other parts of

the country. Figure 40 displays the net light refined product receipts for PADD II, which

have fallen by roughly half in the last 5 years. This demonstrates that PADD II refiners

have the capability to increase their crude oil runs without a need to physically export

refined product. Accordingly, PADD II crude oil runs can increase without a need for a

corresponding rise in local product demand.

In summary, the U.S. and Midwestern refiners do not require refined product demand

growth to increase their crude oil runs or their crude oil processing capacity. They have

clearly and quantitatively demonstrated this at both the national and regional level by

increasing their crude oil runs with stagnant or modest light refined product demand

growth. By the same measure, an increase of throughput on crude oil pipelines, such

as the Enbridge Mainline System, is not limited to just the amount required to satisfy an

increase in regional or national refined product demand.

Figure 40

-

100

200

300

400

500

600

700

800

kb/d

PADD II Net Light Refined Product Receipts

Gasoline Jet DieselSource: EIA


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FORECAST ANALYTICAL METHODOLOGY

The Muse Crude Oil Market Optimization Model has been used to quantify the expected

throughput on the Enbridge Mainline System, using a reasonable scenario of Canadian

crude oil supply and of Canadian export pipeline developments. The following

discussion describes the methodology and assumptions used for this analysis.

The Crude Oil Market Optimization Model is a mathematical representation of the North

American crude oil distribution system, including rail and water transportation modes,

that predicts the flow of crude oil to various markets and the crude oil prices that result

from such flows. Optimization algorithms are used to generate the most efficient crude

oil distribution pattern that acts to maximize the crude oil price received by the U.S. and

Canadian crude oil producer, thus mimicking the behavior of the North American oil

industry. Consequently, the model is well-suited for assessing the market implications

of changes in the logistical infrastructure that enables Western Canadian and U.S.

crude oil to reach the market.

The model uses linear programming (LP) techniques to allocate all North American

crude oil production among Canadian, U.S., Northeast Asian, European, and Indian

refineries, within the confines of existing and expected pipeline, rail loading and

unloading, barge, and refinery capacity constraints. The model is seeking to maximize

the North American crude oil netback price at the point of injection into the

transportation system.41 Said differently, the model is seeking to route all North

American crude oil to the refineries that will pay the most for the crude oil, taking into

consideration the transportation costs from the injection point to the refinery, while

41 The netback price is the price that a specific grade of crude oil is sold for at its market-clearing point,

less the transportation cost between the injection point and the market-clearing point. The market-clearing point is also frequently referred to as the parity point. The parity point can, and does, differ between crude oil grades (heavy sour, light sweet, etc.).


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simultaneously having due regard for the finite capacities of the pipeline and rail routes

(and the refineries themselves). In essence, the model attempts to mirror the crude oil

distribution pattern that would arise from an efficiently operating crude marketplace.

The model is not seeking to maximize or minimize the throughput of the Enbridge

Mainline System or any other pipeline.

The inputs to the model include:

1. The supply of Western Canadian and U.S. crude oil (by major production

area) by individual crude oil grade (heavy sour, light sweet, etc.);

2. The capacity of each pipeline and barge route (by segment, where

necessary);

3. Rail loading and unloading capacity by supply source (loading) and

submarket (unloading);42

4. Where applicable, pipeline volume commitments;

5. The pipeline tolls/rates and other transportation costs (e.g., tanker, barge,

and rail costs);

6. The crude oil capacity of each refinery as well as refinery-specific

constraints; and

7. The refining value of the crude oil grades at each refinery, expressed as a

function of crude oil throughput.

42 Muse does not attempt to model the capacity of the rail network itself.


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Once the variables are input into the model, LP techniques are used to maximize the

desired outcome, which in this case is the aggregate crude oil netback, while

simultaneously satisfying all of the constraints imposed upon the solution.

MODEL INPUT: CRUDE OIL SUPPLY

The June 2016 CAPP forecast is the basis for the Western Canadian crude oil supply

projection.43 As the CAPP forecast ends in 2030, Muse has extended the CAPP

forecast for 5 years using an extrapolation of the trends in the last 5 years (2025-2030)

of the CAPP forecast. For U.S. crude oil production, Muse uses the latest EIA Annual

Energy Outlook supply forecast, with the exception of North Dakota crude oil

production. For the latter, the most recent forecast by the North Dakota Pipeline

Authority is used.

MODEL INPUT: CRUDE OIL TRANSPORTATION INFRASTRUCTURE

The North American crude oil pipeline network modeled is that which exists today plus

all non-Enbridge pipeline projects in development that are reasonably expected, by

Muse, to proceed to completion.44 For Enbridge or Enbridge-affiliated pipeline projects

in development, Muse has used assumptions from Enbridge regarding the capacity and

timing of such projects. The Enbridge pipeline assumptions are considered by Muse to

be reasonable. Details regarding the pipeline assumptions as of 2019 follow:

• Enbridge Mainline System and Affiliated Pipelines. The Enbridge

Mainline System is a multi-line system which transports both light and

heavy crude oils, refined products, and natural gas liquids (NGLs). As is

the case today, no volume commitments have been assumed for the

Enbridge Mainline System. For modeling purposes, the following

assumptions have been made about the capacity and capability of the

43 CAPP, Crude Oil Forecast, Markets and Transportation, June 2016. 44 California and offshore Gulf of Mexico crude oil pipelines are not included in the model, as they have

little influence on the distribution of crude oil elsewhere in North America.


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Enbridge Mainline System. These assumptions have been vetted with

Enbridge.

- Line 1: The practicable light crude oil capacity of Line 1 is 13 kb/d.

This pipeline primarily transports refined product to Gretna (from

which the refined product is delivered to Winnipeg) and NGLs that

are ultimately delivered to Michigan and Ontario.

- Line 2: Capacity of 442 kb/d in light crude oil service.

- Line 3: Current total capacity is 390 kb/d primarily in light crude oil

service. Enbridge can generally transport 30 to 40 kb/d of sour

synthetic on Line 3, which otherwise would have to be transported

on one of the Enbridge heavy crude oil pipelines. Sour synthetic is

produced in limited volumes in Western Canada. For modeling

purposes, it is assumed that up to 40 kb/d of sour synthetic can be

transported on Line 3 prior to the L3R Program. It should be noted

that the volume assumption about sour synthetic transportation

capacity does not change the total capacity of Line 3. Once the

L3R Program is completed, Line 3 will have the capability to ship up

to 760 kb/d in mixed (light or heavy crude oil) service.

- Line 4: Capacity of 796 kb/d in heavy crude oil service.

- Line 65: Capacity of 186 kb/d in light crude oil service. Line 65

terminates at Clearbrook.

- Line 67: Capacity of 800 kb/d in heavy crude oil service.

The unadjusted aggregate capacity of the Gretna to Clearbrook segment, and the

Clearbrook to Superior segment, is provided in Table 8. For example, prior to the

completion of the L3R Program, the Gretna to Clearbrook segment has a light crude oil

capacity of 1,031 kb/d, and a heavy crude oil capacity of 1,596 kb/d. A total of 40 kb/d


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of heavy crude oil can be shifted to a light crude oil pipeline (Line 3) if desired.45

However, the effective aggregate capacity of the Enbridge Mainline System is less than

the sum of the individual pipeline capacities. Accordingly, a utilization factor is applied

to the sum of the individual line capacities. For both the heavy and light crude oil

pipelines, the utilization factor is 92 percent. The effective utilization factor is based

upon historical experience of Enbridge of the impact of operational issues such as late

crude oil receipts from shippers, refineries unable to accept deliveries because of their

own operational problems, and various crude oil terminal constraints. The effective

utilization factor was provided by Enbridge. The utilization factors are the same for the

Gretna to Clearbrook segment and the Clearbrook to Superior segment for the

respective light and heavy crude oil pipelines. Thus, prior to the L3R Program, the

effective light and heavy crude oil capacities of the Gretna to Clearbrook segment are

949 and 1,468 kb/d, respectively, as shown in Table 8 below.

Following the completion of the L3R Program, the nominal light crude oil capacity

(before application of the utilization factor) is 641 kb/d, and the heavy crude oil capacity

is 2,356 kb/d for the Gretna to Clearbrook segment. The total nominal capacity is

2,997 kb/d, an increase of 370 kb/d. However, because the L3R Program enables Line

45 For example, if the heavy crude oil pipelines were in apportionment, but the light crude oil pipelines

were not, then it generally would be desirable to shift as much heavy crude oil to the light crude oil pipelines as possible.

Table 8

SUMMARY OF ENBRIDGE MAINLINE CAPACITY

Thousands of Barrels per Day

Gretna to Clearbrook Clearbrook to SuperiorPre-Project Post-Project Pre-Project Post-Project

Light Heavy Swing Light Heavy Swing Light Heavy Swing Light Heavy Swing

Line 1 13 - - 13 - - 13 - - 13 - - Line 2 442 - - 442 - - 442 - - 442 - - Line 3 390 - 40 - 760 760 390 - 40 - 760 760 Line 4 - 796 - - 796 - - 796 - - 796 - Line 65 186 - - 186 - - NA NA NA NA NA NALine 67 - 800 - - 800 - - 800 - - 800 -

Subtotal 1,031 1,596 40 641 2,356 760 845 1,596 40 455 2,356 760

w/ Utilization Factor 949 1,468 590 2,168 777 1,468 419 2,168


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3 to operate in a 100 percent heavy crude oil service, or 100 percent light crude oil

service, or any proportion in between, it provides a much greater capability to maximize

total crude oil shipments to Minnesota, Midwestern, and other North American

refineries. Prior to the L3R Program, the swing capacity is 40 kb/d, and post-L3R

Program the swing capacity will be the entire capacity of Line 3 (760 kb/d).

• Other Enbridge Mainline System Segments and Affiliated Pipelines. - Superior to Chicago – Total capacity of 973 kb/d in mixed

light/heavy crude oil service;

- Superior to Flanagan – Total capacity of 1,200 kb/d in mixed

light/heavy crude oil service;

- Superior to Sarnia (Line 5) – Effective capacity of 458 kb/d in

dedicated light crude oil service;46

- Chicago to Stockbridge (Line 6B) – Total capacity of 570 kb/d in

mixed light/heavy crude oil service;

- Sarnia to Westover and Montreal (Line 9) – Total capacity of

300 kb/d, with heavy crude oil capacity of 50 kb/d; and

- Southern Access Extension – Total capacity of 300 kb/d in mixed

light/heavy crude oil service.

• Enbridge Flanagan South. The Enbridge Flanagan South pipeline

project was commissioned in 2014 with a capacity of 585 kb/d with a

sizable volume commitment. An expansion is scheduled in 2021 to

increase capacity to 785 kb/d. The Flanagan South pipeline originates at

the Enbridge Flanagan terminal in the Chicago area and terminates at

Cushing, Oklahoma. To provide transportation service from Cushing to

the Gulf Coast, capacity is leased from the Seaway pipeline (see below).

46 In 2019, Line 5 capacity is reduced by approximately 70 kb/d to account for shipments of NGLs in the

pipeline. NGL shipments are assumed to remain constant until 2030, and thereafter decrease by about 2 percent per year. The Line 5 capacity available for crude oil shipments increases commensurately.


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• Seaway System. The Seaway pipeline provides southbound crude oil

capacity between Cushing and Houston, Texas, of 850 kb/d, with a

600 kb/d extension from Houston to the Beaumont/Port Arthur, Texas,

area. (As noted, a portion of the capacity of the Seaway system will be

leased to Flanagan South.) There are volume commitments for both

Seaway and Flanagan South associated with the Seaway system.47

• Enbridge North Dakota System. The following capacities have been

used for the Enbridge North Dakota system:

- To Clearbrook – 210 kb/d; and

- To Cromer – 145 kb/d.

• Dakota Access and Energy Transfer Crude Oil Pipeline (ETCOP). The

Dakota Access pipeline connects North Dakota to Patoka, Illinois, with a

capacity of 450 kb/d. ETCOP originates at Patoka and terminates in the

Beaumont, Texas, area. ETCOP capacity is 450 kb/d.

• Kinder Morgan Trans Mountain. As of 2019, total pipeline capacity is

300 kb/d, less an estimated 50 kb/d of refined product shipments. The

Westridge dock capacity is 79 kb/d. In 2021, an expansion (the Trans

Mountain Expansion Project) is assumed to be commissioned that will

increase the total Trans Mountain crude oil capacity to 840 kb/d, with a

maximum heavy crude oil capacity of 540 kb/d. The post-expansion

Westridge dock capacity is 625 kb/d. This project has received regulatory

approval, with conditions, from both the NEB and the Canadian Federal

Government. As of the date of this report, the project was not yet under

construction.

47 The Flanagan South volume commitments, at their peak, will total 537 kb/d according to the Petition

for Declaratory Order for that project filed in FERC Docket No. OR14-5-000. Seaway had volume commitments of 100,000 kb/d as of 2013; the ultimate level of Seaway volume commitments has not been publicly disclosed.


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• Rockies. Total crude oil export pipeline capacity from Canada to the

Rockies (PADD IV) is estimated to be 460 kb/d throughout the forecast

period. The Crude Market Optimization Model does not individually model

the various export pipelines that connect Alberta with the Rockies. The

outbound (from the Rockies) capacity of the Platte pipeline is estimated to

be 145 kb/d. The White Cliffs and Saddlehorn pipelines are modeled as a

single system with a total capacity of 555 kb/d.48 The Butte/Belle Fourche

pipeline system has a capacity of 316 kb/d.

• Other U.S. Pipeline Projects. - The Magellan Longhorn pipeline connects West Texas and the

Houston area with a total capacity of 275 kb/d with volume

commitments;

- The Magellan BridgeTex pipeline has a capacity of 300 kb/d with

volume commitments;

- The Sunoco West Texas Expansion, Permian Express, and Amdel

pipelines have a total capacity of 260 kb/d;

- The Plains Cactus pipeline has a capacity of 297 kb/d; and

- The Shell Zydeco pipeline is reversed to transport crude oil from

the Houston area to Louisiana with an origination capacity at

Houston of 300 kb/d and 375 kb/d at Beaumont.

• Rail, Barge, and Tanker. Barges are currently being used to transport

Western Canadian crude down the Mississippi River, and rail has

emerged as a credible transportation mode for large volumes of crude oil.

For example, by 2019, an estimated 825 kb/d of effective rail loading

capacity will be in place in the Williston Basin, mostly in North Dakota.

Assumptions regarding barge and rail transport follow:

48 Both pipelines originate in the Niobrara tight oil area, and terminate at Cushing, Oklahoma.


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- Barge capacity is assumed to be 110 kb/d in 2019. The barge

route is via the Mississippi River from the Wood River area to

Louisiana.

- Total rail loading capacity in Western Canadian crude oil to all

destinations is estimated to be 700 kb/d in 2019. If economically

desirable relative to deliveries within North America, Western

Canadian crude oil can be railed to the Gulf Coast for export to

Europe, Asia, and India.

- For crude oil exports from the Gulf Coast, costs for Very Large

Crude Carriers (VLCCs) are used for deliveries to Asia and India,

and Suezmax tankers are used for exports to Europe. The total

VLCC transportation cost includes a lightering expense, because

there are no Gulf Coast ports capable of accommodating VLCCs.

- The estimated tank car capacities are: Canadian light crude oil –

660 barrels; Canadian heavy crude oil – 540 barrels; Bakken –

700 barrels.

Pipeline tolls and rates are obtained from the NEB, Federal Energy Regulatory

Commission (FERC), and state tariff filings. For the Enbridge Mainline System that

extends from Alberta to the Midwest and Ontario, the model uses the tariff rates as

detailed in the Competitive Toll Settlement entered into by Enbridge before the NEB in

Canada, adjusted using information from Enbridge regarding the toll impact of the L3R

Program that is not yet in service. The barge and rail costs are largely based on Muse’s

industry experience and research. The Crude Oil Market Optimization Model uses

constant real (versus nominal) crude oil prices and pipeline rates in 2016 dollars.

Consistent with our practice in other studies, all volume commitments are modeled as

shipments that can take place at discounted tolls, rather than as minimum throughput

obligations. This more closely mimics actual market behavior, in that it recognizes that

committed shippers incur low incremental cash costs to ship, but are not obligated to

physically ship the barrels if they choose to pay the deficiency instead.


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There are three other major potential Canadian export crude oil pipeline projects that

have not been modeled in this analysis for various reasons. These projects are

Northern Gateway, Energy East, and Keystone XL. Brief comments about these

potential projects follow:

• Northern Gateway: This project was to originate in the Edmonton,

Alberta, area and terminate at Kitimat, British Columbia. The Canadian

federal government recently directed the NEB to dismiss the Northern

Gateway application. Absent a reversal of this decision by a future

Canadian government, it appears that this project will not proceed.

• Energy East: This project originates at Hardisty, Alberta, and terminates

in St. John, New Brunswick. This project requires approval by the NEB

and the Canadian Federal Government. The NEB regulatory process has

recently begun, and will not complete until at least 2018. If approved,

commissioning is currently scheduled for early 2022. Opposition to the

project in eastern Canadian provinces is significant. Any completion

probability opinion by an analyst requires an assessment of the Canadian

political dynamics surrounding this project. In Muse’s opinion, ultimate

approval and construction cannot be taken to be a certainty and,

moreover, some of the commercial terms concerning the toll structure also

are not clear to Muse.

• Keystone XL: This project originates at Hardisty and terminates at

Cushing. In 2016, the U.S. Government, following a long review process,

declined to issue a permit to cross the international border. Recent

political developments in the U.S. have appeared to revive the prospects

for this project. Nonetheless, a number of regulatory actions must be

completed before the project can proceed. The Keystone XL project was

authorized, with conditions, by the NEB in March 2010. One of the

certificate conditions was that construction had to begin by March 2011.


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As this has not taken place, it appears that TransCanada will have to

reapply to the NEB and further obtain approval from the Canadian Federal

Government, which recently directed the NEB to dismiss the Northern

Gateway application. It is also likely that the construction permits will have

to reapplied for in many, if not all, of the U.S. states transited by

Keystone XL. Any completion probability opinion by an analyst requires

an assessment of the Canadian, U.S. federal, and U.S. state political

dynamics surrounding this project. Finally, the transportation services

agreements (TSAs) that underpinned the commercial structure of the

project are believed by Muse to have expired. Consequently,

TransCanada likely will have to negotiate new TSAs before beginning the

regulatory process. Accordingly, the toll structure is not known, and would

require speculation by the analyst, as would the ultimate commissioning

date of the project.

MODEL INPUT: REFINERY CAPACITY

Within the Crude Oil Market Optimization Model, most refineries located in Canada, the

Puget Sound area, the Midwest, the Midcontinent, and the U.S. East Coast are

individually represented. Most refineries located in Northern China, Southern China,

Japan, Korea, Taiwan, Europe, India, U.S. Gulf Coast, the Rockies, and California are

represented as a number of aggregates, rather than as individual refineries, mostly due

to the large number of refineries in these areas. For U.S. refineries, crude capacities

are obtained from the EIA Refinery Capacity 2016 Report, adjusted by Muse as

appropriate to incorporate known capacity expansions.49 Capacity information for other

refineries is obtained from the Oil & Gas Journal 2016 Worldwide Refining Survey,

frequently supplemented with information from company and other public sources.50

49 EIA, Refinery Capacity 2016, Table 3, “Capacity of Operable Petroleum Refineries by State as of

January 1, 2016.” 50 Oil & Gas Journal, December 7, 2015.


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Muse has applied utilization factors, which vary somewhat by region and refinery, to the

indicated calendar day capacities within the Crude Oil Market Optimization Model.

MODEL INPUT: CRUDE OIL REFINING VALUES

A key input variable to the Crude Oil Market Optimization Model is the value of various

North American crude oils to the potential refinery customers, which Muse refers to as

the crude oil refining value. The refining values are developed by Muse via the use of

highly complex refinery LP models. Muse licenses the AspenTech PIMS® modeling

system, which is the same system used by over half of the North America refiners to

optimize their refinery operations. The refiner’s optimization objectives include crude

selection, determining process unit run rates, and selecting the mix of refined products

to be produced. The PIMS® models used by Muse are substantially identical to those

used by the refiners themselves.


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FORECAST OF MAINLINE UTILIZATION

There are two Enbridge Mainline System segments in Minnesota: Gretna to Clearbrook

(which crosses the international border); and Clearbrook to Superior. Both segments

transport a combination of U.S. and Canadian crude oils, as Bakken crude oil produced

in North Dakota is injected into the Enbridge Mainline System upstream of Gretna at

Regina and Cromer. Additional Bakken crude oil is injected into the Mainline at

Clearbrook via the Enbridge North Dakota pipeline. This latter pipeline originates in

North Dakota.

The Muse Crude Oil Market Optimization Model is used to evaluate the market impact

of two scenarios concerning the Enbridge Mainline System. The first scenario

considers the market implications of not replacing Line 3 (Current Status Scenario)

using the existing capacities and capabilities of the Enbridge Mainline System. The

second scenario (Line 3 Replacement Scenario) evaluates the implications of replacing

Line 3 with the corresponding changes in Enbridge Mainline System capacity and

capabilities. The replacement of Line 3 acts to increase the overall capacity of the

Enbridge Mainline System by 370 kb/d, and further provides it with the capability to

swing up to 760 kb/d between light and heavy crude oil transportation service.

The analysis also will specifically assess the implications of the L3R Program for the

two Minnesota refineries. To this end, the capacity utilization of the Gretna to

Clearbrook and the Clearbrook to Superior segments will be individually evaluated.

Since the two Minnesota refineries receive crude oil at Clearbrook, apportionment on

the Gretna to Clearbrook segment is generally their primary concern, whereas they may

be little affected by Enbridge Mainline System capacity constraints downstream of

Clearbrook.


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Figure 41 shows the historical volumes of Canadian light and heavy crude oil processed

by the Minnesota refineries. Since 2011, the heavy crude oil imports have comprised

92 percent of the total Canadian crude oil imports for these refineries, and in no year

has the proportion been less than 87 percent. Figure 41 thus highlights the criticality of

sufficient heavy crude oil capacity on the Gretna to Clearbrook segment for the

Minnesota refineries. The Minnesota refineries, in aggregate, have been customized

over the years to process a high proportion of Canadian heavy crude oil, and I am

aware of no reason why these refineries would shift to a substantially lighter crude oil

slate.

CURRENT STATUS SCENARIO

Figure 42 provides the estimated throughput for the aggregate light crude oil pipelines

for the Gretna to Clearbrook segment, and Figure 43 provides the corresponding

throughput for the aggregate heavy crude oil pipelines. It is noteworthy that the forecast

indicates that there will be unused capacity on the Enbridge light crude oil pipelines,

even with 40 kb/d of sour synthetic shifted to Line 3 (which is primarily a light crude oil

Figure 41

0

50

100

150

200

250

300

350

400

kb/d

Canadian Crude Oil Imports by Minnesota Refiners

Heavy Crude Oil Light Crude OilSource: EIA, Muse


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line prior to the L3R Program). In contrast, the heavy crude oil pipelines are projected

to continue to operate at capacity throughout the forecast period. In this circumstance,

the heavy crude oil pipelines will be in apportionment. Consequently, all refineries

downstream of Gretna, including those in Minnesota, will need to source a portion of

their heavy crude oil from other locations, or utilize rail transport to ship Western

Canadian crude oil to their refineries (or do some combination).51 Appendix 3 provides

the projected year-by-year throughput of the light and heavy crude oil pipelines

delivering crude oil to Clearbrook for the Current Status Scenario.

The pipeline utilization situation for the Clearbrook to Superior segment, downstream of

the Minnesota refineries, is essentially the converse of that for the Gretna to Clearbrook

segment. Figure 44 provides the projected utilization for the light crude oil pipelines,

whereas Figure 45 shows the projected utilization for the heavy crude oil pipelines. The

light crude oil pipelines are full, and therefore in apportionment, and the heavy crude oil

pipelines have available capacity. This is not an unexpected result. The capacities of

the heavy crude oil pipelines inbound to Clearbrook and outbound are the same, but, as

Figure 41 above demonstrates, the Minnesota refineries consume about 250 kb/d of

heavy crude oil. If the inbound heavy crude oil pipelines are full, then there necessarily

51 Refineries in the Chicago area and Detroit can obtain heavy crude oil on the Gulf Coast or at a crude oil

transportation hub in southern Illinois (Patoka) and ship it north by pipeline if desired. The Minnesota refineries are not pipeline connected to the Gulf Coast or Patoka. They can only obtain additional heavy crude oil via rail.

Figure 42 Figure 43

0100200300400500600700800900

1,000

kb/d




0

200

400

600

800

1,000

1,200

1,400

1,600

kb/d




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will be excess outbound heavy crude oil pipeline capacity. It is a considerably different

situation for the light crude oil pipelines. At Clearbrook, Enbridge Line 65, a light crude

oil pipeline, terminates, resulting in the loss of 186 kb/d of capacity, and significant

volumes of Bakken light crude oil are received at Clearbrook via the Enbridge North

Dakota pipeline and are injected into the Enbridge Mainline System. Thus, due to the

combination of less outbound light crude oil capacity and additional light crude oil

receipts at Clearbrook, the light crude oil pipelines fill downstream of Clearbrook.

A comparison of the total volume of crude oil that must leave Western Canada versus

the outbound pipeline capacity is shown on Figure 46. This volume is net of that

consumed by the refineries located within Western Canada itself, which is about

600 kb/d.52 The pipeline capacity on Figure 46 increases in 2021 because it has been

assumed that the Trans Mountain Expansion Project will be commissioned in that year.

As shown by Figure 46, without the L3R Program, the volume of Western Canadian

crude oil is projected to exceed total outbound pipeline capacity essentially throughout

the forecast period, even with the assumed start up of the Trans Mountain Expansion

Project in 2021. However, even though the outbound volume exceeds the nominal

aggregate pipeline capacity, this does not mean that all of the outbound pipelines

52 The crude oil volume consumed in Western Canada does not include the Chevron Burnaby refinery,

located in the Vancouver, British Columbia, area. Although it is located in Western Canada, it nonetheless must be supplied by via pipeline (or rail) due to its location.

Figure 44 Figure 45

0100200300400500600700800900

kb/d




0

200

400

600

800

1,000

1,200

1,400

1,600

kb/d




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necessarily will be full in all years. For example, the Enbridge Mainline System light

crude oil pipelines are full today, and are not projected to fill without the L3R Program.

The pipelines delivering crude oil into the Rockies are also projected to be somewhat

underutilized, particularly as crude oil production in the Rockies grows late in the

forecast period.

Figures 47 through 50 below provide an overview of the other pipelines that ship crude

oil out of Western Canada, plus the forecast volume of rail shipments for the Current

Status Scenario. The Keystone pipeline (Figure 47) and the Trans Mountain pipeline

(Figure 48) are projected to operate at, or close to, their capacity through the forecast

period. The pipelines that connect Western Canada with the Rockies (Figure 49)

generally are not projected to be full, particularly in the latter years of the forecast. Light

crude oil production in the Rockies is projected to grow significantly over this time

period, and constraints on the outbound (from the Rockies) crude oil pipelines act to

reduce inbound Canadian light crude oil shipments. However, the degree of excess

capacity in the pipelines to the Rockies is not large. Figure 50 provides the projected

shipments of Canadian crude oil via rail. In all years, there is projected to be significant

Figure 46

0

1,000

2,000

3,000

4,000

5,000

6,000

kb/d




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volumes of both Canadian light and heavy crude oil moving by rail, and these volumes

dwarf the notionally available capacity in the pipelines to the Rockies.


Figures 51 and 52 illustrate the impact of the L3R Program on the utilization of the

pipelines inbound to Clearbrook. Total light crude capacity drops in 2019 because

Line 3 shifts from light crude oil service to heavy crude oil service. The total capacity of

the heavy crude oil pipelines increases by 760 kb/d (the new Line 3 capacity).53

However, the new Line 3 has the operational capability to transport both light and heavy

crude oil if desired, and Figure 52 illustrates that an average of about 200 kb/d of light

53 The 760 kb/d capacity is before the application of the utilization factor (92 percent).

0

100

200

300

400

500

600

700

800

900

kb/d

Trans Mountain

Heavy Crude Oil Light Crude Oil CapacitySource: Muse

0

200

400

600

800

1,000

1,200

1,400

1,600

kb/d

Rail

Heavy Crude Oil Light Crude OilSource: Muse

0

100

200

300

400

500

600

700

kb/d

TransCanada Keystone


050

100150200250300350400450500

kb/d

Express/Milk/Rangeland


Figure 47 Figure 48

Figure 49 Figure 50


-77-

crude oil will be shipped on the new Line 3. Consequently, once the L3R Program is

completed in 2019, there no longer is unused capacity in the light crude oil pipelines

(Figure 51), the volume of heavy crude oil shipped appreciably increases (Figure 52),

and the total light crude oil shipments are about the same as they were in the Current

Status Scenario. Appendix 4 provides the projected year-by-year throughput of the light

and heavy crude oil pipelines delivering crude oil to Clearbrook for the Line 3

Replacement Scenario.

For the Clearbrook to Superior segment, both the light crude oil pipelines (Figure 53)

and the heavy crude oil pipelines (Figure 54) are projected to operate essentially at

capacity once the L3R Program is commissioned. The light crude oil capacity drops by

390 kb/d, and the heavy crude oil capacity increases by 760 kb/d. The swing capability

of the new Line 3 allows the previously unused heavy crude oil capacity to be utilized.

The swing capability of the L3R Program is illustrated on Figure 54, as post 2019 an

average of about 470 kb/d of light crude oil is being shipped on the new Line 3.

Figure 51 Figure 52

0100200300400500600700800900

1,000

kb/d




0

500

1,000

1,500

2,000

2,500

kb/d




-78-

The overall balance between pipeline capacity exiting Western Canada and Canadian

crude oil supply is provided by Figure 55. The commissioning of the L3R Program itself

does not create surplus pipeline capacity, as can observed in 2019 and 2020 on Figure

55. Notional excess pipeline capacity appears in 2021, but this is related to the Trans

Mountain Expansion Project, and the notionally excess capacity persists for just a few

years. In any event, there are significant operational and market benefits from a

moderate degree of excess pipeline capacity. The crude oil producers have more

market optionality, and refiners benefit because their crude oil supply is less affected by

unscheduled pipeline outages, since the pipelines have more sprint capacity and the

refiners frequently have an improved ability to use alternative pipeline routes.

Figure 53 Figure 54

0100200300400500600700800900

kb/d




0

500

1,000

1,500

2,000

2,500

kb/d



Figure 55

0

1,000

2,000

3,000

4,000

5,000

6,000

kb/d




-79-

Figures 56 through 59 illustrate the impact of the L3R Program on the other pipelines

exiting Western Canada, and only the years 2019 and 2020 are specifically relevant to

an assessment of the impact of the L3R Program on these pipelines because of the

assumed start up of the Trans Mountain Expansion Project in 2021. The effect on

Trans Mountain is zero, and the impact on the Keystone pipeline and the various

pipelines that ship Canadian crude oil into the Rockies is minor. It is likely that, as the

Western Canadian crude oil supply continues to grow, the L3R Program will have a de

minimis effect on the other pipelines.54 The more substantive drop in throughput on the

Keystone pipeline beginning in 2021 is related to the Trans Mountain Expansion

Project, not the L3R Program. However, the L3R Program (and the Trans Mountain

Expansion Project) does act to substantially reduce rail shipments. As shown in Figure

59, rail shipments drop when the L3R Program is commissioned in 2019, and fall again

in 2021 with the start up of the Trans Mountain Expansion Project. However, by about

2028 the volume of Canadian crude oil being shipped by rail is rapidly rising, and

additional Western Canadian export pipelines easily could be accommodated in this

period without affecting throughput on the existing pipelines.

54 This assertion cannot be rigorously tested unless the optimization model is rerun without the Trans

Mountain Expansion Project.

0

100

200

300

400

500

600

700

800

900

kb/d

Trans Mountain


0

100

200

300

400

500

600

700

kb/d

TransCanada Keystone


Figure 56 Figure 57


-80-

A moderate degree of excess pipeline capacity is beneficial to the refining industry.

Figure 60 below illustrates the monthly imports of Canadian crude oil by Midwestern

refiners. The month-to-month swing in crude oil demand frequently exceeds 200 kb/d,

with a peak month-to-month swing of 490 kb/d, representing demand swings of 10 to

about 27 percent, respectively. Accordingly, if pipeline capacity just equaled average

annual demand, refineries frequently would not be able to obtain all of the crude oil that

they desire as the pipelines would be full, and in apportionment, about half of the time.

Moreover, while sometimes high demand at an individual refinery will coincide with low

demand at a second refinery, thus offsetting each other, this is not always the case, as

demonstrated by Figure 60. Even in the hypothetical circumstance where the

incremental capacity provided by the L3R Program is not needed on an annual average

basis, the L3R Program provides useful sprint capacity to meet the peak needs of

Midwestern refineries for Canadian crude oil, as it represents only about 10 percent of

the outbound Canadian crude oil pipeline capacity. The L3R Program also provides

additional redundancy to the entire pipeline system that delivers Western Canadian, and

some U.S. Bakken crude oil, to Midwestern and other U.S. refineries, thus improving the

overall reliability of crude oil supply to refineries in Minnesota and its neighboring states.

Figure 58 Figure 59

0

200

400

600

800

1,000

1,200

1,400

1,600

kb/d

Rail

Heavy Crude Oil Light Crude OilSource: Muse

050

100150200250300350400450500

kb/d

Express/Milk/Rangeland



-81-

ANALYSIS OF L3R PROGRAM ON NORTH AMERICAN CRUDE OIL FLOWS

The L3R Program adds, directly and indirectly, roughly 500 kb/d of additional crude oil

transportation capacity via pipeline between Western Canada and the Midwest. A

project of this size can be expected to have a significant impact on the distribution

pattern of crude oil in North America. The effect of the L3R Program on the flow of

North American crude oil from the various production locations to North American

refineries can be assessed by comparing the model output for the Line 3 Replacement

Scenario to the Current Status Scenario.

Rail Shipments

The impact that the L3R Program has on rail shipments of crude oil from Western

Canada is material. Figure 61 provides the delta between rail shipments without the

L3R Program (the Current Status Scenario) and with the L3R Program (the Line 3

Replacement Scenario). The L3R Program reduces expected rail shipments by a

minimum of about 110 kb/d (in 2021, the first year of operation of the Trans Mountain

Figure 60

1,000

1,200

1,400

1,600

1,800

2,000

2,200

kb/d

Canadian Crude Oil Imports by Midwestern Refiners

Source: EIA, Muse


-82-

Expansion Project) and up to about 510 kb/d. The change in rail volumes is greater

than the effective incremental capacity of the L3R Program (370 kb/d * 92% = 340 kb/d)

because the L3R Program also enables utilization of about 180 kb/d of light crude oil

capacity in the Enbridge Mainline System that is currently unused, for a total effective

increase in capacity of about 520 kb/d. This 180 kb/d of unused capacity is specifically

that in the Clearbrook to Superior segment. Absent the L3R Program, much of the

additional rail shipments can be expected to transit Minnesota to such destinations as

the Midwest, East Coast, and the Gulf Coast. Appendix 5 provides the volume of

avoided crude oil shipments by rail on a year-by-year basis.

The analytical conclusion that rail will be used to ship Western Canadian crude oil

absent the L3R Program, and that, consequently, the L3R Program will reduce rail

shipments is fully consistent with current evidence that sizable volumes of Canadian

crude oil are being shipped by rail. Figure 62 provides the historical shipments of

Canadian crude oil by rail to various U.S. regions. As Figure 62 demonstrates, as much

as 175 kb/d of Canadian crude oil has been shipped by rail into the U.S. Additional

volumes of Western Canadian crude oil are also being shipped to Canadian refineries

during this period. Finally, as Figure 55 above demonstrates, the supply of crude oil

Figure 61

-

100

200

300

400

500

600

kb/d

Avoided Rail Shipments from Canada

Gulf Coast Puget Sound Minnesota Chicago Lower Midwest East CoastSource: Muse


-83-

from Western Canada is projected to exceed total outbound pipeline capacity by about

2028, even if it is assumed that the Trans Mountain Expansion Project is commissioned

in 2021. The difference between Western Canadian crude oil supply and effective

pipeline capacity must necessarily be transported by rail.

DESTINATION OF INCREMENTAL ENBRIDGE MAINLINE SYSTEM THROUGHPUT

The commissioning of the L3R Program will not change the supply volume of Western

Canadian crude oil. However, the L3R Program will influence the transportation modes

and the distribution patterns of Western Canadian crude oil. The effect on

transportation modes is primarily reflected by a decrease in rail shipments, as discussed

immediately above.

Figure 63 provides an overview of the disposition of the incremental throughput of

518 kb/d on the Enbridge Mainline System in 2020. Approximately 60 percent of the

incremental throughput leaves the Upper Midwest via one of five pipelines: Enbridge

Figure 62

0

50

100

150

200

250

300

kb/d




-84-

Line 9, which supplies refineries in Eastern Canada; the Flanagan South, and

Spearhead pipelines, both of which terminate at Cushing; and, the Southern Access

Extension and Mustang pipelines, both of which terminate in southern Illinois at Patoka.

About 15 percent of the incremental throughput is attributable to reductions of rail

deliveries to refineries in Minnesota and the Chicago area, and the balance (25 percent)

is due to a decrease in shipments on northbound crude oil pipelines. These northbound

pipelines are: Chicap, which originates at Patoka and terminates in Chicago; Maumee,

which originates in Lima, Ohio, and terminates in Toledo; and, the BP No. 1 pipeline,

which originates at Cushing and terminates at the BP Whiting refinery in the Chicago

area. Appendix 6 provides the year-by-year disposition of the incremental throughput

on the Enbridge Mainline System that is attributable to the L3R Program, and a further

discussion of the market factors that influence this distribution follows.

Enbridge Line 9

Line 9 originates in Sarnia, Ontario, and terminates in Montreal, where crude oil can be

delivered to the Suncor Montreal refinery or routed to a dock where tankers can be

loaded. The tankers typically deliver crude oil to the Valero Lévis refinery in Quebec or

Figure 63

85

150

47 15

60

33

15

114

Disposition of Incremental Mainline Throughput - 2020kb/d

Enbridge Line 9

Flanagan South/Spearhead

Southern Access Extension/Mustang

Rail to Minnesota

Rail to Chicago

ChiCap

Maumee

BP No. 1Source: Muse


-85-

one of the refineries in Atlantic Canada. The higher throughput on Enbridge Line 9 is

mostly light crude oil for delivery to refineries in Eastern Canada that acts to reduce the

volume of waterborne imports that these refineries would otherwise process. For

example, refineries in Quebec and Atlantic Canada imported 375 kb/d of crude oil from

countries other than the U.S. in the first half of 2016.55 It is possible that relatively small

volumes of Canadian or U.S. Bakken crude oil could find their way to the U.S. East

Coast via Montreal.

Flanagan South and Spearhead

These two pipelines essentially parallel each other, as they both originate at the

Enbridge Flanagan terminal south of Chicago and terminate in Cushing. At Cushing,

two high-capacity southbound pipelines provided connectivity to the Gulf Coast. The

incremental throughput on Flanagan South and Spearhead is almost entirely heavy

crude oil destined for the Gulf Coast. This is not a surprising analytical result, as the

Gulf Coast is the largest market for heavy crude oil in the world. Figure 64 shows the

historical patterns of Gulf Coast heavy sour crude oil receipts, and it demonstrates both

that there is a large volume of heavy sour crude oil that is currently being processed on

the Gulf Coast and that the volume of Canadian heavy crude oil being processed also

has been increasing in recent years. Moreover, there is no substantive need for the

Canadian heavy crude oil producers to increase their market share on the Gulf Coast,

because the higher shipments on Flanagan South and Spearhead are projected to

essentially replace rail deliveries to the Gulf Coast of Canadian heavy crude oil.

55 Statistic Canada; Table 134-0001; Refinery supply of crude oil and equivalent, monthly;

http://www5.statcan.gc.ca/cansim/a26.


http://www5.statcan.gc.ca/cansim/a26

-86-

Southern Access Extension and Mustang

These two pipelines both originate in the Chicago area and terminate in Patoka, which

is a major crude oil transportation hub in southern Illinois. An incremental 47 kb/d of

light crude oil is expected to ship on these pipelines in 2020 for delivery to refineries in

the Lower Midwest. These flows are projected to primarily displace northbound

shipments on Capline, which connects Louisiana with Patoka.

Rail to Minnesota and Chicago

The greater Enbridge Mainline System capacity created by the L3R Program is

projected to essentially end regular rail shipments from Canada to Minnesota refineries

and the Chicago area refineries throughout the forecast period. The rail deliveries to

Minnesota and Chicago are exclusively Canadian heavy crude oil. It is possible that

there may be an occasional rail shipment to a Minnesota or the Chicago area refinery

post-L3R Program, but such volumes are expected to be negligible.

Figure 64

-

500

1,000

1,500

2,000

2,500

2011 2012 2013 2014 2015 Jan-Oct 2016

kb/d

Gulf Coast Heavy Sour Crude Oil Imports by Country

Canada OtherSource: EIA


-87-

Chicap, Maumee, and BP No. 1 Pipelines

These three are all northbound pipelines that deliver crude oil into the Upper Midwest.

The Chicap pipeline originates in Patoka and the BP No. 1 pipeline originates in

Cushing; both terminate in Chicago. Chicap is capable of transporting both light and

heavy crude oil, whereas the BP No. 1 pipeline is limited to transporting light crude oil.

In 2020, the displaced Chicap volume of 33 kb/d is comprised of Canadian heavy crude

oil that was delivered to Patoka via the Keystone pipeline. The 114 kb/d of crude oil

displaced on the BP No. 1 pipeline is light crude oil from West Texas. The Maumee

pipeline originates in Lima, Ohio, and terminates in Toledo, Ohio, where it is connected

to the Toledo and Detroit refineries. At Lima, the Maumee pipeline can receive crude oil

from a Marathon pipeline that originates in Patoka, or the MidValley pipeline that

originates in east Texas. The total flow rate on the Maumee pipeline is projected to

drop by 15 kb/d in 2020 and shift to a predominately light crude oil slate.

An approximate monthly forecast of the Enbridge Mainline System throughput is

provided in Appendix 7, so as to comply with Minnesota Rule 7853.0520(B) and the

Commission’s Order modifying this data requirement.56

ANALYTICAL CONCLUSIONS

The following key conclusions can be extracted from the analysis:

1. The incremental nominal Enbridge Mainline System capacity of 370 kb/d created

by the L3R Program will be fully utilized throughout the forecast period;

56 Order Approving Notice Plan, Granting Variance Request, Approving Exemption Requests, and

Approving and Adopting Orders for Protection and Separate Docket. In the Matter of the Application of Enbridge Energy, Limited Partnership for a Certificate of Need for the Line 3 Replacement Project, Docket No. PL-9/CN-14-916 (January 27, 2015).


-88-

2. The light-heavy crude oil swing capability provided by the L3R Program will

enable the full utilization of currently unused light crude oil capacity of about 180

kb/d;

3. The L3R Program has a minor initial impact on the other pipelines that exit

Western Canada, and likely will have no impact once a few years have passed;

4. The L3R Program will reduce the forecast volume of Canadian crude oil shipped

by rail by between 110 and 510 kb/d, much of which will otherwise transit

Minnesota; and

5. The L3R Program will not change the supply volume of Western Canadian or

Bakken crude oil. It acts only to influence the transportation modes used by and

the distribution patterns of North American crude oil.


-89-

APPENDIX 1


-90-

APPENDIX 2


-91-

APPENDIX 3

ENBRIDGE MAINLINE THROUGHPUT ― GRETNA TO CLEARBROOK

CURRENT STATUS SCENARIO


Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Light Crude Oil PipelinesCanadian Light Crude Oil 538.3 674.4 585.0 554.5 541.8 541.8 541.8 541.8 541.8 543.3 544.4 546.7 542.7 543.6 547.1 548.5 553.8 580.2 581.0 586.8 U.S. Bakken Crude Oil 188.8 52.7 143.8 172.6 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 Heavy Synthetic 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0

Subtotal 767.1 767.1 768.8 767.1 770.6 770.6 770.6 770.6 770.6 772.1 773.2 775.5 771.5 772.4 775.9 777.3 782.6 809.0 809.8 815.6

Heavy Crude Oil PipelinesCanadian Heavy Crude Oil 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 Light Crude Oil to Line 3 - - - - - - - - - - - - - - - - - - - -

Subtotal 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3 1,468.3


-92-

APPENDIX 4

ENBRIDGE MAINLINE THROUGHPUT ― GRETNA TO CLEARBROOK



Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Light Crude Oil PipelinesCanadian Light Crude Oil 538.3 674.4 585.0 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 400.9 U.S. Bakken Crude Oil 188.8 52.7 143.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 188.8 Heavy Synthetic 40.0 40.0 40.0 - - - - - - - - - - - - - - - - -

Subtotal 767.1 767.1 768.8 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7 589.7

Heavy Crude Oil PipelinesCanadian Heavy Crude Oil 1,468.3 1,468.3 1,468.3 1,969.8 1,953.7 1,971.0 1,971.0 1,963.9 1,956.8 1,968.7 1,972.7 1,991.9 2,000.2 2,007.2 2,006.9 1,939.3 1,926.6 1,968.7 1,974.5 1,976.3 Light Crude Oil to Line 3 - - - 197.7 213.8 195.0 196.5 203.6 210.7 198.8 194.9 175.6 167.3 160.3 160.6 228.2 240.9 198.9 193.0 191.2

Subtotal 1,468.3 1,468.3 1,468.3 2,167.5 2,167.5 2,165.9 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5 2,167.5


-93-

APPENDIX 5

AVOIDED RAIL SHIPMENTS OF WESTERN CANADIAN CRUDE OIL

CURRENT STATUS SCENARIO LESS LINE 3 REPLACEMENT SCENARIO


Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

HoustonLight - - - - - - - - - - - - - - - - - - - - Heavy - - - 245 245 - - 29 106 162 244 296 317 427 373 249 175 106 83 16

Subtotal - - - 245 245 - - 29 106 162 244 296 317 427 373 249 175 106 83 16

LouisianaLight - - - - - - - - - - - - - - - - - - 8 18 Heavy - - - - - - - - - - - - - - - 6 41 145 152 226

Subtotal - - - - - - - - - - - - - - - 6 41 145 160 244

Puget SoundLight - - - 63 54 - - - - - - - - - - - - - - - Heavy - - - 22 9 - 38 12 12 12 12 12 26 29 5 8 7 13 10 12

Subtotal - - - 85 63 - 38 12 12 12 12 12 26 29 5 8 7 13 10 12

MinnesotaLight - - - - - - - - - - - - - - - - - - - - Heavy - - - 15 15 - 15 15 15 15 15 15 15 15 15 15 15 15 15 15

Subtotal - - - 15 15 - 15 15 15 15 15 15 15 15 15 15 15 15 15 15

ChicagoLight - - - - - - - - - - - - - - - - - - - - Heavy - - - 19 60 - - - - - - - - - 34 77 94 110 110 110

Subtotal - - - 19 60 - - - - - - - - - 34 77 94 110 110 110

Lower MidwestLight - - - - - - - - - - - - - - - 55 55 55 55 55 Heavy - - - - - - - - - - - - - - - - - 4 4 4

Subtotal - - - - - - - - - - - - - - - 55 55 59 59 59

East CoastLight - - - 31 71 67 72 80 98 105 95 112 95 18 26 85 62 (1) 1 (8) Heavy - - - 38 22 47 23 21 0 0 0 7 20 4 23 17 12 23 23 28

Subtotal - - - 70 93 114 94 101 98 105 95 119 115 22 49 102 74 22 24 20

Grand Total - - - 433 476 114 147 156 231 294 365 441 474 492 475 512 461 470 460 476


-94-

APPENDIX 6

DISPOSITION OF INCREMENTAL ENBRIDGE MAINLINE THROUGHPUT

LINE 3 REPLACEMENT SCENARIO LESS CURRENT STATUS SCENARIO


Year 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Enbridge Mainline SystemGretna to Clearbrook - - - 522 518 517 518 518 518 517 516 513 517 517 513 512 506 480 479 473

Outbound PipelinesEnbridge Line 9 - - - 75 85 74 73 71 60 71 73 75 63 27 19 87 75 21 8 12 Flanagan South/Spearhead - - - 203 150 284 258 242 252 287 283 266 300 349 308 114 112 108 110 125 Southern Access Extension/Mustang - - - 39 47 62 77 94 76 38 (55) (60) (10) (21) (28) - 15 53 62 28

Subtotal - - - 317 282 420 408 408 388 396 301 281 353 356 299 201 203 181 180 165

Reduction in Rail ShipmentsFrom Canada

Minnesota - - - 15 15 - 15 15 15 15 15 15 15 15 15 15 15 15 15 15 Chicago - - - 19 60 - - - - - - - - - 34 77 94 110 110 110

From North DakotaChicago/Detroit/Toledo - - - - - - - - 46 51 70 75 28 25 44 33 16 - - -

Subtotal - - - 34 75 - 15 15 61 66 85 90 43 40 92 125 125 125 125 125

Reduction in Northbound Pipeline ShipmentsChiCap - - - 31 33 46 39 41 17 - - - 30 - - - - - - - Maumee - - - 24 15 51 54 55 53 51 30 (2) 8 61 43 46 35 28 27 36 BP No. 1 - - - 116 114 - 2 - - 4 99 143 84 60 79 140 143 146 147 148

Subtotal - - - 172 162 97 96 95 70 55 130 142 122 121 122 186 179 174 175 184

Grand Total - - - 522 518 517 518 518 518 517 516 513 517 517 513 512 506 480 479 473


-95-

APPENDIX 7

ENBRIDGE MAINLINE SYSTEM CAPACITY UTILIZATION ANALYSIS(Thousands of Barrels per Day)

Total Surplus Total Surplus Total SurplusHeavy Light/Med Capacity Capacity Heavy Light/Med Capacity Capacity Heavy Light/Med Capacity Capacity

Jan-19 2,168 590 2,758 0 May-24 2,168 590 2,758 0 Sep-29 2,168 590 2,758 0Feb-19 2,168 590 2,758 0 Jun-24 2,168 590 2,758 0 Oct-29 2,168 590 2,758 0Mar-19 2,168 590 2,758 0 Jul-24 2,168 590 2,758 0 Nov-29 2,168 590 2,758 0Apr-19 2,168 590 2,758 0 Aug-24 2,168 590 2,758 0 Dec-29 2,168 590 2,758 0

May-19 2,168 590 2,758 0 Sep-24 2,168 590 2,758 0 Jan-30 2,168 590 2,758 0Jun-19 2,168 590 2,758 0 Oct-24 2,168 590 2,758 0 Feb-30 2,168 590 2,758 0Jul-19 2,168 590 2,758 0 Nov-24 2,168 590 2,758 0 Mar-30 2,168 590 2,758 0

Aug-19 2,168 590 2,758 0 Dec-24 2,168 590 2,758 0 Apr-30 2,168 590 2,758 0Sep-19 2,168 590 2,758 0 Jan-25 2,168 590 2,758 0 May-30 2,168 590 2,758 0Oct-19 2,168 590 2,758 0 Feb-25 2,168 590 2,758 0 Jun-30 2,168 590 2,758 0Nov-19 2,168 590 2,758 0 Mar-25 2,168 590 2,758 0 Jul-30 2,168 590 2,758 0Dec-19 2,168 590 2,758 0 Apr-25 2,168 590 2,758 0 Aug-30 2,168 590 2,758 0Jan-20 2,168 590 2,758 0 May-25 2,168 590 2,758 0 Sep-30 2,168 590 2,758 0Feb-20 2,168 590 2,758 0 Jun-25 2,168 590 2,758 0 Oct-30 2,168 590 2,758 0Mar-20 2,168 590 2,758 0 Jul-25 2,168 590 2,758 0 Nov-30 2,168 590 2,758 0Apr-20 2,168 590 2,758 0 Aug-25 2,168 590 2,758 0 Dec-30 2,168 590 2,758 0









Throughput Throughput Throughput


-96-

SUPPORTING DATA FOR FIGURES

Five-State Demand Five-State Productionkb/d kb/d

1994 717 309 1995 737 322 1996 760 340 1997 765 361 1998 788 359 1999 818 335 2000 815 362 2001 825 361 2002 825 360 2003 822 354 2004 850 366 2005 856 358 2006 855 353 2007 862 342 2008 835 362 2009 801 359 2010 830 367 2011 838 381 2012 843 389 2013 847 386 2014 874 403

FIGURE 2

COMPARISON OF FIVE-STATE TRANSPORTATION FUEL SUPPLY-DEMAND


-97-

Canadian Light Heavy SynLight Crude Oil to

Crude Oil Capacity U.S. Bakken Line 3kb/d kb/d kb/d kb/d

2016 538 949 189 40 2017 674 949 53 40 2018 585 949 144 40 2019 555 949 173 40 2020 542 949 189 40 2021 542 949 189 40 2022 542 949 189 40 2023 542 949 189 40 2024 542 949 189 40 2025 543 949 189 40 2026 544 949 189 40 2027 547 949 189 40 2028 543 949 189 40 2029 544 949 189 40 2030 547 949 189 40 2031 548 949 189 40 2032 554 949 189 40 2033 580 949 189 40 2034 581 949 189 40 2035 587 949 189 40

FIGURES 3 AND 42

ENBRIDGE GRETNA TO CLEARBROOK LIGHT CRUDE OIL


-98-

HeavyHeavy Crude Oil

Crude Oil Capacitykb/d kb/d

2016 1,468 1,468 2017 1,468 1,468 2018 1,468 1,468 2019 1,468 1,468 2020 1,468 1,468 2021 1,468 1,468 2022 1,468 1,468 2023 1,468 1,468 2024 1,468 1,468 2025 1,468 1,468 2026 1,468 1,468 2027 1,468 1,468 2028 1,468 1,468 2029 1,468 1,468 2030 1,468 1,468 2031 1,468 1,468 2032 1,468 1,468 2033 1,468 1,468 2034 1,468 1,468 2035 1,468 1,468

FIGURES 4 AND 43

ENBRIDGE GRETNA TO CLEARBROOK HEAVY CRUDE OIL


-99-



2016 538 949 189 40 2017 674 949 53 40 2018 585 949 144 40 2019 401 590 189 - 2020 401 590 189 - 2021 401 590 189 - 2022 401 590 189 - 2023 401 590 189 - 2024 401 590 189 - 2025 401 590 189 - 2026 401 590 189 - 2027 401 590 189 - 2028 401 590 189 - 2029 401 590 189 - 2030 401 590 189 - 2031 401 590 189 - 2032 401 590 189 - 2033 401 590 189 - 2034 401 590 189 - 2035 401 590 189 -

FIGURES 5 AND 51

ENBRIDGE GRETNA TO CLEARBROOK LIGHT CRUDE OIL


-100-

Heavy LightHeavy Crude Oil Crude Oil

Crude Oil Capacity to Line 3kb/d kb/d kb/d

2016 1,468 1,468 - 2017 1,468 1,468 - 2018 1,468 1,468 - 2019 1,970 2,168 198 2020 1,954 2,168 214 2021 1,971 2,168 195 2022 1,971 2,168 197 2023 1,964 2,168 204 2024 1,957 2,168 211 2025 1,969 2,168 199 2026 1,973 2,168 195 2027 1,992 2,168 176 2028 2,000 2,168 167 2029 2,007 2,168 160 2030 2,007 2,168 161 2031 1,939 2,168 228 2032 1,927 2,168 241 2033 1,969 2,168 199 2034 1,975 2,168 193 2035 1,976 2,168 191

FIGURES 6 AND 52

ENBRIDGE GRETNA TO CLEARBROOK HEAVY CRUDE OIL


-101-



2016 430 777 347 - 2017 573 777 205 - 2018 480 777 297 - 2019 454 777 324 - 2020 451 777 326 - 2021 453 777 325 - 2022 466 777 312 - 2023 483 777 295 - 2024 478 777 300 - 2025 477 777 300 - 2026 476 777 301 - 2027 479 777 299 - 2028 461 777 317 - 2029 464 777 313 - 2030 472 777 305 - 2031 499 777 279 - 2032 506 777 271 - 2033 506 777 271 - 2034 506 777 271 - 2035 506 777 271 -

FIGURES 7 AND 44

ENBRIDGE CLEARBROOK TO SUPERIOR LIGHT CRUDE OIL


-102-

HeavyHeavy Crude Oil

Crude Oil Capacitykb/d kb/d

2016 1,269 1,468 2017 1,269 1,468 2018 1,286 1,468 2019 1,284 1,468 2020 1,287 1,468 2021 1,272 1,468 2022 1,287 1,468 2023 1,287 1,468 2024 1,287 1,468 2025 1,289 1,468 2026 1,290 1,468 2027 1,292 1,468 2028 1,288 1,468 2029 1,289 1,468 2030 1,293 1,468 2031 1,294 1,468 2032 1,299 1,468 2033 1,326 1,468 2034 1,327 1,468 2035 1,332 1,468

FIGURES 8 AND 45

ENBRIDGE CLEARBROOK TO SUPERIOR HEAVY CRUDE OIL


-103-



2016 430 777 347 - 2017 573 777 205 - 2018 480 777 297 - 2019 76 419 343 - 2020 76 419 343 - 2021 104 419 315 - 2022 100 419 318 - 2023 100 419 318 - 2024 81 419 338 - 2025 76 419 343 - 2026 98 419 320 - 2027 92 419 327 - 2028 85 419 333 - 2029 76 419 343 - 2030 76 419 343 - 2031 91 419 327 - 2032 100 419 319 - 2033 100 419 319 - 2034 97 419 322 - 2035 96 419 323 -

FIGURES 9 AND 53

ENBRIDGE CLEARBROOK TO SUPERIOR LIGHT CRUDE OIL


-104-

Heavy LightHeavy Crude Oil Crude Oil

Crude Oil Capacity to Line 3kb/d kb/d kb/d

2016 1,269 1,468 - 2017 1,269 1,468 - 2018 1,286 1,468 - 2019 1,689 2,168 460 2020 1,680 2,168 469 2021 1,694 2,168 454 2022 1,690 2,168 459 2023 1,683 2,168 466 2024 1,678 2,168 471 2025 1,683 2,168 467 2026 1,685 2,168 464 2027 1,704 2,168 446 2028 1,712 2,168 438 2029 1,708 2,168 441 2030 1,708 2,168 442 2031 1,640 2,168 509 2032 1,636 2,168 514 2033 1,675 2,168 474 2034 1,678 2,168 472 2035 1,679 2,168 470

FIGURES 10 AND 54

ENBRIDGE CLEARBROOK TO SUPERIOR HEAVY CRUDE OIL


-105-

Heavy Light PipelineCrude Oil Crude Oil Capacity U.S. Bakken

kb/d kb/d kb/d kb/d

2016 2,299 1,075 3,718 189 2017 2,473 1,062 3,718 53 2018 2,754 1,053 3,718 144 2019 2,846 1,027 4,058 189 2020 2,890 1,059 4,058 189 2021 2,966 1,067 4,648 189 2022 3,021 1,074 4,648 189 2023 3,017 1,079 4,648 189 2024 3,057 1,086 4,648 189 2025 3,092 1,090 4,648 189 2026 3,163 1,093 4,648 189 2027 3,222 1,107 4,648 189 2028 3,314 1,124 4,648 189 2029 3,459 1,141 4,648 189 2030 3,600 1,165 4,648 189 2031 3,698 1,188 4,648 189 2032 3,799 1,211 4,648 189 2033 3,903 1,235 4,648 189 2034 4,009 1,259 4,648 189 2035 4,119 1,284 4,648 189

FIGURES 11 AND 55

WESTERN CANADIAN CRUDE OIL DISPOSITION


-106-

Gulf Puget Lower EastCoast Sound Minnesota Chicago Midwest Coastkb/d kb/d kb/d kb/d kb/d kb/d

2016 - - - - - - 2017 - - - - - - 2018 - - - - - - 2019 245 85 15 19 - 70 2020 245 63 15 60 - 93 2021 - - - - - 114 2022 - 38 15 - - 94 2023 29 12 15 - - 101 2024 106 12 15 - - 98 2025 162 12 15 - - 105 2026 244 12 15 - - 95 2027 296 12 15 - - 119 2028 317 26 15 - - 115 2029 427 29 15 - - 22 2030 373 5 15 34 - 49 2031 256 8 15 77 55 102 2032 217 7 15 94 55 74 2033 251 13 15 110 59 22 2034 243 10 15 110 59 24 2035 260 12 15 110 59 20

FIGURES 12 AND 61

AVOIDED RAIL SHIPMENTS FROM CANADA


-107-

NetElectricity Natural

Petroleum Coal Imports Gas Nuclear Renewables

1994 38% 22% 4% 22% 9% 5%1995 37% 21% 5% 23% 9% 5%1996 38% 21% 5% 23% 8% 5%1997 38% 21% 6% 22% 7% 6%1998 38% 22% 5% 21% 8% 5%1999 38% 20% 6% 21% 8% 6%2000 38% 22% 5% 21% 8% 6%2001 39% 21% 7% 20% 7% 6%2002 37% 20% 8% 21% 8% 6%2003 36% 21% 10% 20% 7% 6%2004 37% 20% 9% 20% 7% 6%2005 38% 21% 7% 20% 7% 7%2006 38% 21% 7% 20% 8% 7%2007 36% 20% 8% 21% 7% 8%2008 34% 19% 7% 23% 7% 9%2009 34% 19% 6% 23% 7% 11%2010 32% 17% 7% 23% 8% 12%2011 32% 17% 8% 23% 7% 13%2012 33% 14% 9% 24% 7% 13%2013 32% 15% 9% 26% 6% 13%2014 31% 17% 6% 26% 7% 14%

FIGURE 13

COMPOSITION OF MINNESOTA ENERGY SUPPLY


-108-

NetElectricity Natural

Petroleum Coal Imports Gas Nuclear Renewables

1994 579 333 63 327 128 72 1995 601 338 73 357 139 76 1996 633 355 86 374 127 81 1997 631 342 95 360 114 84 1998 632 357 81 337 122 81 1999 661 341 107 351 139 95 2000 678 374 84 367 135 103 2001 673 353 112 345 123 109 2002 674 361 139 374 143 107 2003 695 391 189 374 140 114 2004 711 379 173 362 139 126 2005 719 379 122 372 134 140 2006 698 371 129 358 138 157 2007 701 366 142 396 137 179 2008 667 359 134 435 136 215 2009 617 329 100 406 130 259 2010 622 315 135 427 141 288 2011 613 316 141 425 125 300 2012 619 258 158 430 125 293 2013 612 268 157 475 112 294 2014 608 313 109 490 133 334

FIGURE 14

SOURCES OF MINNESOTA ENERGY SUPPLYTrillion Btu per Year


-109-

ElectricPower

Transportation Commercial Industrial Generation Residential

1994 400 9 129 7 35 1995 415 9 137 5 36 1996 424 11 148 7 44 1997 421 15 147 9 40 1998 443 13 137 7 31 1999 474 9 138 9 32 2000 492 10 133 8 35 2001 483 11 138 7 33 2002 489 9 138 7 31 2003 494 14 141 9 37 2004 508 11 150 8 34 2005 510 11 159 8 31 2006 501 15 149 5 28 2007 505 12 150 5 29 2008 483 15 136 3 30 2009 452 14 125 1 27 2010 455 12 128 0 26 2011 448 13 127 0 25 2012 457 12 128 0 22 2013 438 14 134 0 26 2014 436 14 130 1 27

FIGURE 15

SOURCES OF MINNESOTA PETROLEUM DEMANDTrillion Btu per Year


-110-

Asphalt Diesel Jet/Kero Gasoline Otherkb/d kb/d kb/d kb/d kb/d

1994 13 60 27 144 24 1995 18 63 28 149 22 1996 18 66 29 150 26 1997 18 65 30 153 26 1998 19 67 30 159 23 1999 21 66 35 164 24 2000 20 68 37 167 24 2001 18 68 32 171 27 2002 15 67 30 174 26 2003 17 69 33 177 28 2004 18 72 34 177 28 2005 20 72 35 177 30 2006 19 71 32 177 28 2007 19 75 31 177 28 2008 15 73 28 172 27 2009 13 63 25 168 22 2010 13 69 25 169 23 2011 12 73 26 161 23 2012 12 73 25 166 22 2013 12 75 16 166 22 2014 12 76 15 164 21

FIGURE 16

MINNESOTA REFINED PRODUCT DEMAND


-111-

Diesel/Gasoline No. 2 FO Jet

kb/d kb/d kb/d

Jan-10 130.8 41.5 19.2 Feb-10 138.1 49.3 22.1 Mar-10 134.2 54.7 25.5 Apr-10 141.6 62.4 24.3

May-10 145.9 55.2 21.6 Jun-10 152.1 58.4 24.2 Jul-10 157.1 59.1 25.7

Aug-10 151.9 63.8 25.3 Sep-10 149.4 67.3 22.1 Oct-10 143.8 81.0 23.0 Nov-10 141.1 60.3 21.1 Dec-10 148.8 52.8 18.8 Jan-11 137.2 51.2 20.7 Feb-11 142.6 54.7 21.7 Mar-11 134.8 53.6 22.7 Apr-11 133.5 50.8 22.0

May-11 142.4 60.8 23.3 Jun-11 153.3 60.3 26.4 Jul-11 149.3 53.8 26.1


May-12 146.4 58.9 23.2 Jun-12 160.3 60.4 24.6 Jul-12 159.3 62.4 25.4

Aug-12 160.6 70.0 26.6 Sep-12 146.6 75.1 23.1 Oct-12 153.9 75.5 22.6 Nov-12 148.7 64.7 21.6 Dec-12 153.6 56.8 20.9 Jan-13 150.1 57.4 21.4 Feb-13 149.0 56.0 22.2 Mar-13 138.0 54.6 NAApr-13 138.8 54.9 NA

May-13 150.2 62.8 9.8 Jun-13 157.1 56.2 11.1 Jul-13 162.8 65.6 12.0


May-14 153.9 64.4 11.4 Jun-14 155.3 62.8 12.3 Jul-14 160.6 68.3 12.9


May-15 155.7 59.6 12.1 Jun-15 166.9 62.5 12.7 Jul-15 172.6 63.3 14.4


May-16 162.8 61.4 12.0 Jun-16 170.7 63.6 13.4 Jul-16 164.0 55.3 13.0

Aug-16 166.2 63.7 14.4 Sep-16 158.9 68.2 9.0 Oct-16 156.4 84.7 8.6

FIGURE 17

MONTHLY MINNESOTA PETROLEUM PRODUCT DEMAND


-112-

Diesel/Gasoline No. 2 FO Jet

Spring 95.4 92.3 100.4 Summer 106.6 102.5 105.2 Fall 100.6 117.8 98.7 Winter 97.4 87.4 95.7

FIGURE 18

SEASONALITY OF MINNESOTA PRODUCT DEMAND(Percent of Annual Average)


-113-

Gasoline Diesel/No. 2 FO Jetkb/d kb/d kb/d

Jan-10 220 112 23Feb-10 227 115 25Mar-10 218 110 28Apr-10 193 93 25

May-10 190 112 24Jun-10 234 130 29Jul-10 242 125 31

Aug-10 232 119 30Sep-10 202 93 26Oct-10 238 143 26Nov-10 249 144 24Dec-10 222 128 22Jan-11 236 128 23Feb-11 239 134 25Mar-11 210 109 26Apr-11 198 102 26

May-11 221 107 28Jun-11 226 130 30Jul-11 227 126 28


May-12 228 131 26Jun-12 228 106 26Jul-12 230 142 26


May-13 202 87 21Jun-13 230 125 28Jul-13 223 136 31


May-14 164 112 23Jun-14 228 133 28Jul-14 250 141 31


May-15 249 147 30Jun-15 245 135 32Jul-15 253 138 34


May-16 249 116 25Jun-16 261 123 32Jul-16 256 137 33

Aug-16 260 141 36Sep-16 222 125 27Oct-16 249 167 28

FIGURE 19

MINNESOTA REFINING DISTRICT TRANSPORTATION FUEL PRODUCTION


-114-

Asphalt Diesel Jet/Kero Gasoline Otherkb/d kb/d kb/d kb/d kb/d

1994 33 213 41 432 47 1995 38 215 41 445 42 1996 41 228 40 453 49 1997 47 226 40 454 50 1998 49 227 41 474 47 1999 57 235 50 479 50 2000 51 238 52 478 47 2001 46 252 47 484 48 2002 42 245 43 496 48 2003 47 234 43 501 49 2004 50 249 50 504 51 2005 55 249 50 505 54 2006 52 254 48 504 51 2007 43 269 44 510 51 2008 38 263 41 495 50 2009 34 235 38 496 40 2010 35 256 37 504 41 2011 35 275 38 492 41 2012 34 283 37 491 37 2013 35 292 28 493 41 2014 34 309 28 502 40

FIGURE 20

FIVE-STATE REFINED PRODUCT DEMAND


-115-

Fuel GasolineEthanol ex EtOH Jet Diesel Asphalt/HFO Other

kb/d kb/d kb/d kb/d kb/d kb/d

1994 1.5 193.5 30.0 96.0 34.0 13.0 1995 4.0 206.0 31.0 93.0 40.0 13.0 1996 5.7 214.3 33.0 100.0 39.0 14.0 1997 5.9 223.1 33.0 106.0 45.0 13.0 1998 5.9 221.1 32.0 107.0 50.0 10.0 1999 6.3 206.7 33.0 95.0 45.0 9.0 2000 6.5 220.5 32.0 109.0 49.0 13.0 2001 6.1 215.9 30.0 115.0 42.0 11.0 2002 10.3 212.7 28.0 114.0 39.0 10.0 2003 18.3 202.7 29.0 109.0 42.0 11.0 2004 19.0 214.0 30.0 109.0 42.0 11.0 2005 25.0 217.0 31.0 114.0 51.0 10.0 2006 23.0 216.0 29.0 114.0 47.0 11.0 2007 27.0 216.0 28.0 104.0 46.0 12.0 2008 31.0 215.0 27.0 124.0 41.0 11.0 2009 36.0 225.0 28.0 112.0 36.0 11.0 2010 37.0 227.0 26.0 120.0 41.0 11.0 2011 37.0 231.0 26.0 127.0 48.0 11.0 2012 37.0 232.0 26.0 133.0 51.0 10.0 2013 39.0 228.0 27.0 133.0 47.0 9.0 2014 40.0 238.0 29.0 140.0 46.0 10.0 2015 41.0 251.0 30.0 140.0 50.0 11.0

FIGURE 21

FIVE-STATE AREA REFINERY PRODUCTION


-116-

Minnesotaless 3-Month

Gulf Coast Averagects/gal cts/gal

Jan-10 67.3 67.3 Feb-10 63.7 65.5 Mar-10 62.6 64.5 Apr-10 57.6 61.3

May-10 72.2 64.1 Jun-10 66.8 65.5 Jul-10 68.6 69.2

Aug-10 72.5 69.3 Sep-10 79.3 73.5 Oct-10 77.8 76.5 Nov-10 70.1 75.8 Dec-10 65.5 71.1 Jan-11 73.0 69.5 Feb-11 71.7 70.0 Mar-11 64.3 69.6 Apr-11 56.6 64.2

May-11 79.7 66.8 Jun-11 77.5 71.3 Jul-11 66.1 74.4


May-12 77.6 61.7 Jun-12 99.9 78.0 Jul-12 84.1 87.2


May-13 122.6 93.4 Jun-13 97.5 99.8 Jul-13 66.2 95.4


May-14 67.8 71.7 Jun-14 62.7 64.5 Jul-14 68.3 66.2

Aug-14 66.2 65.7 Sep-14 68.9 67.8 Oct-14 89.9 75.0 Nov-14 94.5 84.4 Dec-14 101.7 95.4

FIGURE 24

MINNESOTA RETAIL GASOLINE LESS GULF COAST SPOT


-117-

Minnesota Chicago$/gal $/gal

07/22/15 2.77 3.00 07/23/15 2.76 2.99 07/24/15 2.74 2.97 07/25/15 2.73 2.95 07/26/15 2.71 2.91 07/27/15 2.71 2.91 07/28/15 2.69 2.90 07/29/15 2.67 2.87 07/30/15 2.65 2.85 07/31/15 2.63 2.83 08/01/15 2.61 2.81 08/02/15 2.60 2.80 08/03/15 2.60 2.79 08/04/15 2.58 2.78 08/05/15 2.56 2.76 08/06/15 2.54 2.74 08/07/15 2.52 2.77 08/08/15 2.50 2.79 08/09/15 2.49 2.78 08/10/15 2.49 2.77 08/11/15 2.47 2.77 08/12/15 2.47 2.84 08/13/15 2.57 3.00 08/14/15 2.67 3.25 08/15/15 2.70 3.40 08/16/15 2.71 3.45 08/17/15 2.70 3.46 08/18/15 2.74 3.47 08/19/15 2.74 3.46 08/20/15 2.72 3.44 08/21/15 2.70 3.42 08/22/15 2.67 3.38 08/23/15 2.65 3.34 08/24/15 2.64 3.32 08/25/15 2.62 3.30 08/26/15 2.59 3.25 08/27/15 2.55 3.20 08/28/15 2.51 3.15 08/29/15 2.48 3.10 08/30/15 2.46 3.06 08/31/15 2.45 3.03 09/01/15 2.43 3.00 09/02/15 2.42 2.98 09/03/15 2.40 2.95

FIGURE 25

RETAIL GASOLINE PRICES


-118-

Five-State Upper Lower PADD IIArea Midwest Midwest Midcontinent Crude Runskb/d kb/d kb/d kb/d kb/d

2010 447 1,202 1,220 842 3,281 2011 428 1,208 1,225 848 3,372 2012 449 1,144 1,212 848 3,442 2013 455 1,227 1,227 848 3,406 2014 468 1,242 1,238 850 3,523 2015 491 1,270 1,248 850 3,561 2016 510 1,273 1,289 850 3,609

FIGURE 26

PADD II REFINING CAPACITY AND CRUDE OIL RUNS


-119-

Domestic Crude Oil Foreign Crude OilReceipts by Pipeline Receipts by Pipeline

% %

1998 99.08% 100.00%1999 98.43% 100.00%2000 98.63% 99.99%2001 99.11% 100.00%2002 99.15% 100.00%2003 99.04% 100.00%2004 99.46% 100.00%2005 99.36% 100.00%2006 99.24% 100.00%2007 99.00% 100.00%2008 98.94% 100.00%2009 99.13% 100.00%2010 99.15% 99.99%2011 98.93% 100.00%2012 97.25% 99.90%2013 97.17% 99.96%2014 96.61% 99.95%2015 95.75% 99.99%

FIGURE 27

PROPORTION OF PIPELINE RECEIPTS FOR PADD II REFINERIES


-120-

PADD I PADD II PADD III PADD IV/Vkb/d kb/d kb/d kb/d

Jun-11 - - - 1.3 Jul-11 - - - -

Aug-11 - - 0.4 - Sep-11 - - 0.8 1.4 Oct-11 - - 2.5 1.4 Nov-11 - - 0.7 4.2 Dec-11 0.1 - 1.8 - Jan-12 2.2 2.3 1.6 0.7 Feb-12 1.4 1.7 - - Mar-12 3.8 0.3 2.4 0.7 Apr-12 4.7 - 7.3 2.2

May-12 9.6 0.7 12.5 2.1 Jun-12 7.1 - 5.7 2.2 Jul-12 11.2 - 11.4 0.7

Aug-12 25.5 3.8 7.6 0.7 Sep-12 23.9 1.6 8.0 3.8 Oct-12 17.2 0.7 6.0 3.2 Nov-12 17.1 - 5.5 3.8 Dec-12 11.9 - 10.5 3.2 Jan-13 16.5 0.7 9.9 14.7 Feb-13 19.8 - 15.0 4.5 Mar-13 18.1 2.3 21.5 2.4 Apr-13 26.3 2.3 24.4 4.7

May-13 37.3 4.1 24.3 10.9 Jun-13 44.4 3.9 20.3 10.4 Jul-13 34.5 8.4 32.1 13.5

Aug-13 39.2 2.3 55.0 10.0 Sep-13 30.4 4.0 53.8 4.6 Oct-13 28.2 3.8 62.2 4.9 Nov-13 31.0 4.4 71.3 2.3 Dec-13 43.7 3.8 71.5 11.3 Jan-14 58.5 6.4 65.4 10.4 Feb-14 57.5 - 73.9 16.9 Mar-14 47.6 - 49.6 18.4 Apr-14 63.7 - 68.7 26.4

May-14 100.9 2.3 53.4 16.9 Jun-14 90.6 0.8 51.6 10.8 Jul-14 59.2 0.7 37.6 12.2

Aug-14 79.2 2.2 52.2 4.5 Sep-14 74.2 5.2 67.3 6.9 Oct-14 93.2 0.8 61.5 7.5 Nov-14 62.2 0.8 74.5 0.8 Dec-14 78.4 1.5 66.8 8.2 Jan-15 62.6 3.1 74.7 19.7 Feb-15 28.3 - 32.8 9.8 Mar-15 37.7 - 34.0 6.8 Apr-15 19.6 2.3 44.4 8.6

May-15 19.7 2.3 60.9 8.5 Jun-15 24.3 - 56.7 8.4 Jul-15 17.7 2.3 77.7 14.6

Aug-15 19.5 6.2 50.9 12.4 Sep-15 25.8 4.0 104.9 39.4 Oct-15 11.7 13.1 73.2 22.1 Nov-15 17.4 9.9 82.9 4.2 Dec-15 32.1 10.5 73.8 15.9 Jan-16 38.9 - 50.5 - Feb-16 17.0 4.3 75.3 6.1 Mar-16 2.2 15.3 61.5 11.9 Apr-16 27.3 11.3 27.2 28.1

May-16 4.9 18.8 52.8 17.1 Jun-16 - 7.3 25.6 20.6 Jul-16 4.5 9.3 21.5 14.9

Aug-16 - 21.8 40.9 - Sep-16 4.5 20.1 43.3 5.1 Oct-16 10.2 23.4 47.3 18.5

FIGURES 28 AND 62

CANADIAN CRUDE OIL DELIVERIES BY RAIL TO U.S.


-121-

NEBOct 2016

CAPP Reference2016 Casekb/d kb/d

2005 2,264 2,269 2006 2,454 2,451 2007 2,492 2,497 2008 2,459 2,463 2009 2,579 2,583 2010 2,703 2,701 2011 2,874 2,874 2012 3,175 3,173 2013 3,385 3,392 2014 3,672 3,666 2015 3,838 3,844 2016 3,802 3,860 2017 4,004 4,069 2018 4,232 4,242 2019 4,291 4,405 2020 4,346 4,483 2021 4,412 4,554 2022 4,464 4,632 2023 4,518 4,736 2024 4,562 4,781 2025 4,607 4,881 2026 4,671 5,049 2027 4,731 5,131 2028 4,818 5,153 2029 4,954 5,214 2030 5,084 5,326

FIGURE 29

WESTERN CANADIAN CRUDE OIL PRODUCTION


-122-

CAPP NEB NEB NEB2016 Reference Low Highkb/d kb/d kb/d kb/d

2005 2,264 2,269 2,269 2,269 2006 2,454 2,451 2,451 2,451 2007 2,492 2,497 2,497 2,497 2008 2,459 2,463 2,463 2,463 2009 2,579 2,583 2,583 2,583 2010 2,703 2,701 2,701 2,701 2011 2,874 2,874 2,874 2,874 2012 3,175 3,173 3,173 3,173 2013 3,385 3,392 3,392 3,392 2014 3,672 3,666 3,666 3,666 2015 3,838 3,844 3,844 3,844 2016 3,802 3,860 3,860 3,861 2017 4,004 4,069 4,071 4,187 2018 4,232 4,242 4,215 4,380 2019 4,291 4,405 4,355 4,560 2020 4,346 4,483 4,417 4,662 2021 4,412 4,554 4,472 4,750 2022 4,464 4,632 4,510 4,879 2023 4,518 4,736 4,545 5,029 2024 4,562 4,781 4,570 5,094 2025 4,607 4,881 4,621 5,230 2026 4,671 5,049 4,672 5,447 2027 4,731 5,131 4,696 5,586 2028 4,818 5,153 4,713 5,703 2029 4,954 5,214 4,743 5,851 2030 5,084 5,326 4,770 6,039

FIGURE 30

WESTERN CANADIAN CRUDE OIL PRODUCTION


-123-

NEBOct 2016

CAPP Reference AER2016 Case 2016kb/d kb/d kb/d

2005 1,065 1,065 1,065 2006 1,263 1,254 1,255 2007 1,320 1,320 1,321 2008 1,306 1,305 1,305 2009 1,491 1,489 1,490 2010 1,616 1,612 1,613 2011 1,745 1,744 1,744 2012 1,926 1,922 1,922 2013 2,085 2,084 2,085 2014 2,305 2,303 2,305 2015 2,527 2,526 2,527 2016 2,556 2,655 2,696 2017 2,834 2,852 2,867 2018 3,106 3,016 3,015 2019 3,185 3,167 3,152 2020 3,261 3,219 3,296 2021 3,331 3,259 3,476 2022 3,379 3,310 3,654 2023 3,426 3,391 3,800 2024 3,463 3,418 3,904 2025 3,499 3,505 4,015 2026 3,554 3,668 - 2027 3,604 3,750 - 2028 3,680 3,776 - 2029 3,801 3,844 - 2030 3,917 3,966 -

FIGURE 31

WESTERN CANADIAN BITUMEN PRODUCTION


-124-

kb/d

2007 985 2008 1,012 2009 1,068 2010 1,016 2011 1,113 2012 1,141 2013 1,152 2014 1,316 2015 1,295

Jan-Oct 2016 1,258

FIGURE 33

CANADIAN CRUDE OIL RUNS IN UPPER MIDWEST


-125-

kb/d

2007 110 2008 96 2009 82 2010 87 2011 231 2012 334 2013 351 2015 317

Jan-Oct 2016 357

FIGURE 34

CANADIAN CRUDE OIL RUNS IN LOWER MIDWEST


-126-

kb/d

2007 63 2008 70 2009 82 2010 83 2011 88 2012 123 2013 160 2014 144 2015 135

Jan-Oct 2016 110

FIGURE 35

CANADIAN CRUDE OIL RUNS IN MIDCONTINENT


-127-

kb/d

2007 78 2008 53 2009 43 2010 87 2011 83 2012 64 2013 60 2014 104 2015 245

Jan-Oct 2016 250

FIGURE 36

ON GULF COASTCANADIAN CRUDE OIL RUNS


-128-

Crude OilGasoline Jet Diesel Runs

kb/d kb/d kb/d kb/d

Jan-09 8,623 1,312 4,079 14,146 Feb-09 8,836 1,356 3,864 14,134 Mar-09 8,903 1,406 3,744 14,118 Apr-09 9,029 1,432 3,455 14,382

May-09 9,084 1,329 3,436 14,483 Jun-09 9,180 1,425 3,513 14,850 Jul-09 9,260 1,506 3,395 14,636

Aug-09 9,295 1,449 3,426 14,593 Sep-09 8,911 1,414 3,560 14,710 Oct-09 8,986 1,362 3,654 14,095 Nov-09 8,906 1,352 3,596 13,898 Dec-09 8,931 1,372 3,861 13,983 Jan-10 8,520 1,344 3,701 13,666 Feb-10 8,579 1,343 3,854 13,950 Mar-10 8,793 1,443 3,835 14,314 Apr-10 9,108 1,410 3,759 15,131

May-10 9,162 1,446 3,639 15,215 Jun-10 9,311 1,543 3,743 15,382 Jul-10 9,301 1,494 3,544 15,519


May-11 8,817 1,424 3,699 14,718 Jun-11 9,067 1,540 3,947 15,294 Jul-11 9,031 1,473 3,564 15,589


May-12 8,979 1,409 3,756 15,097 Jun-12 8,996 1,546 3,732 15,637 Jul-12 8,810 1,468 3,557 15,665


May-13 9,033 1,459 3,749 15,305 Jun-13 9,078 1,454 3,663 15,833 Jul-13 9,146 1,546 3,621 16,042


May-14 9,023 1,400 3,952 15,946 Jun-14 9,039 1,544 3,902 15,817 Jul-14 9,249 1,559 3,866 16,534


May-15 9,262 1,519 3,778 16,402 Jun-15 9,417 1,654 3,897 16,701 Jul-15 9,470 1,650 3,901 16,879


May-16 9,436 1,562 3,745 16,276 Jun-16 9,663 1,714 3,830 16,432 Jul-16 9,597 1,715 3,578 16,640

Aug-16 9,595 1,710 3,890 16,592 Sep-16 9,492 1,624 3,905 16,356

U.S. LIGHT REFINED PRODUCT DEMAND VERSUS CRUDE RUNS

FIGURE 37


-129-

Gasoline Jet Dieselkb/d kb/d kb/d

Jan-09 179 77 647 Feb-09 189 42 539 Mar-09 154 61 555 Apr-09 141 66 684

May-09 223 86 648 Jun-09 214 42 578 Jul-09 256 49 622

Aug-09 172 54 617 Sep-09 207 63 607 Oct-09 246 95 557 Nov-09 206 74 588 Dec-09 330 116 406 Jan-10 244 113 391 Feb-10 279 66 389 Mar-10 384 70 454 Apr-10 374 76 685

May-10 233 79 756 Jun-10 344 57 638 Jul-10 318 82 771


May-11 497 56 728 Jun-11 433 74 726 Jul-11 366 109 950

Aug-11 576 91 835 Sep-11 565 103 931 Oct-11 562 78 1,067 Nov-11 665 106 943 Dec-11 647 130 1,128 Jan-12 430 115 873 Feb-12 462 126 927 Mar-12 536 100 911 Apr-12 460 90 1,078

May-12 385 125 1,052 Jun-12 422 152 1,086 Jul-12 480 142 1,046

Aug-12 507 110 979 Sep-12 493 131 1,003 Oct-12 568 150 1,047 Nov-12 589 160 1,061 Dec-12 745 189 1,023 Jan-13 559 164 774 Feb-13 674 98 833 Mar-13 469 132 807 Apr-13 417 137 843

May-13 350 120 1,123 Jun-13 408 179 1,292 Jul-13 446 151 1,351

Aug-13 412 195 1,308 Sep-13 458 141 1,351 Oct-13 530 138 1,353 Nov-13 575 202 1,268 Dec-13 784 213 1,280 Jan-14 664 136 1,068 Feb-14 548 146 852 Mar-14 523 141 1,014 Apr-14 448 114 1,162

May-14 560 158 1,162 Jun-14 425 152 1,170 Jul-14 496 206 1,207

Aug-14 440 213 1,291 Sep-14 428 138 1,097 Oct-14 474 203 929 Nov-14 686 189 1,101 Dec-14 901 155 1,139 Jan-15 742 241 1,121 Feb-15 667 193 943 Mar-15 510 155 1,018 Apr-15 509 194 1,219

May-15 601 129 1,280 Jun-15 490 147 1,210 Jul-15 628 181 1,328

Aug-15 540 154 1,066 Sep-15 522 162 1,277 Oct-15 609 118 1,150 Nov-15 787 191 1,178 Dec-15 803 155 1,300 Jan-16 756 205 951 Feb-16 852 176 937 Mar-16 729 129 1,208 Apr-16 625 160 1,296

May-16 699 187 1,241 Jun-16 697 208 1,472 Jul-16 661 141 1,385

Aug-16 744 200 1,218 Sep-16 635 177 1,218

FIGURE 38

U.S. LIGHT REFINED PRODUCT EXPORTS


-130-

Crude OilGasoline Jet Diesel Runs

kb/d kb/d kb/d kb/d

Jan-09 2,420 224 1,081 3,126 Feb-09 2,474 246 1,070 3,165 Mar-09 2,501 243 1,097 2,955 Apr-09 2,513 248 1,053 3,108

May-09 2,563 245 1,064 3,213 Jun-09 2,618 263 1,057 3,298 Jul-09 2,690 272 1,042 3,287

Aug-09 2,546 251 1,037 3,168 Sep-09 2,541 247 1,096 3,175 Oct-09 2,514 241 1,111 2,968 Nov-09 2,527 239 1,118 3,014 Dec-09 2,513 247 1,097 3,152 Jan-10 2,324 218 975 3,199 Feb-10 2,433 238 1,098 3,276 Mar-10 2,467 244 1,142 3,084 Apr-10 2,648 243 1,206 3,133

May-10 2,686 245 1,192 3,410 Jun-10 2,658 282 1,182 3,442 Jul-10 2,695 269 1,153 3,457

Aug-10 2,685 260 1,210 3,434 Sep-10 2,617 256 1,217 3,312 Oct-10 2,526 269 1,284 3,063 Nov-10 2,574 264 1,188 3,244 Dec-10 2,586 259 1,096 3,320 Jan-11 2,373 244 1,079 3,306 Feb-11 2,431 241 1,147 3,306 Mar-11 2,393 265 1,154 3,241 Apr-11 2,448 248 1,121 3,241

May-11 2,550 270 1,138 3,309 Jun-11 2,642 273 1,211 3,469 Jul-11 2,623 260 1,100 3,478


May-12 2,645 248 1,235 3,481 Jun-12 2,672 262 1,265 3,466 Jul-12 2,558 263 1,173 3,499


May-13 2,583 240 1,233 3,137 Jun-13 2,596 249 1,209 3,357 Jul-13 2,636 256 1,218 3,574


May-14 2,580 218 1,284 3,594 Jun-14 2,718 258 1,302 3,662 Jul-14 2,725 242 1,273 3,717


May-15 2,703 250 1,200 3,674 Jun-15 2,645 276 1,264 3,705 Jul-15 2,797 255 1,260 3,815


May-16 2,642 263 1,174 3,607 Jun-16 2,899 241 1,260 3,683 Jul-16 2,799 281 1,134 3,723

Aug-16 2,782 279 1,282 3,746 Sep-16 2,749 278 1,284 3,624

FIGURE 39

PADD II LIGHT REFINED PRODUCT DEMAND VERSUS CRUDE OIL RUNS


-131-

Gasoline Jet Dieselkb/d kb/d kb/d

Jan-09 455 68 183 Feb-09 369 48 124 Mar-09 340 36 175 Apr-09 356 35 166

May-09 342 51 153 Jun-09 424 54 168 Jul-09 481 47 219


May-10 310 41 220 Jun-10 327 57 181 Jul-10 346 27 218


May-11 258 23 179 Jun-11 266 28 150 Jul-11 199 33 162


May-12 59 7 160 Jun-12 137 19 186 Jul-12 118 18 165


May-13 126 7 257 Jun-13 125 43 240 Jul-13 123 25 162


May-14 54 30 212 Jun-14 43 30 131 Jul-14 26 45 131


May-15 26 29 107 Jun-15 32 28 104 Jul-15 30 26 124


May-16 40 21 173 Jun-16 60 47 120 Jul-16 37 40 140

Aug-16 42 35 203 Sep-16 62 52 212

FIGURE 40

PADD II NET LIGHT REFINED PRODUCT RECEIPTS


-132-

Heavy Lightkb/d kb/d

Jan-11 239 41 Feb-11 278 19 Mar-11 273 17 Apr-11 194 7

May-11 214 20 Jun-11 279 18 Jul-11 242 17

Aug-11 270 11 Sep-11 266 17 Oct-11 235 17 Nov-11 252 20 Dec-11 284 12 Jan-12 260 17 Feb-12 314 13 Mar-12 219 20 Apr-12 244 20

May-12 306 18 Jun-12 240 14 Jul-12 235 20


May-13 262 40 Jun-13 262 22 Jul-13 259 39


May-14 149 26 Jun-14 262 30 Jul-14 240 18


May-15 233 6 Jun-15 294 6 Jul-15 224 3


May-16 229 24 Jun-16 223 9 Jul-16 307 14

Aug-16 244 22 Sep-16 247 28 Oct-16 268 31

FIGURE 41

CANADIAN CRUDE OIL IMPORTS BY MINNESOTA REFINERS


-133-

Heavy Light PipelineCrude Oil Crude Oil Capacity U.S. Bakken

kb/d kb/d kb/d kb/d

2016 2,299 1,075 3,718 189 2017 2,473 1,062 3,718 53 2018 2,754 1,053 3,718 144 2019 2,846 1,027 3,718 173 2020 2,890 1,059 3,718 189 2021 2,966 1,067 4,308 189 2022 3,021 1,074 4,308 189 2023 3,017 1,079 4,308 189 2024 3,057 1,086 4,308 189 2025 3,092 1,090 4,308 189 2026 3,163 1,093 4,308 189 2027 3,222 1,107 4,308 189 2028 3,314 1,124 4,308 189 2029 3,459 1,141 4,308 189 2030 3,600 1,165 4,308 189 2031 3,698 1,188 4,308 189 2032 3,799 1,211 4,308 189 2033 3,903 1,235 4,308 189 2034 4,009 1,259 4,308 189 2035 4,119 1,284 4,308 189

FIGURE 46

WESTERN CANADIAN CRUDE OIL DISPOSITION


-134-

Heavy LightCrude Oil Crude Oil Capacity

kb/d kb/d kb/d

2016 396 195 591 2017 530 0 591 2018 591 0 591 2019 591 0 591 2020 591 0 591 2021 590 1 591 2022 591 0 591 2023 591 0 591 2024 555 36 591 2025 535 56 591 2026 521 70 591 2027 519 72 591 2028 560 31 591 2029 526 65 591 2030 536 55 591 2031 569 22 591 2032 571 20 591 2033 560 31 591 2034 568 23 591 2035 591 - 591

FIGURE 47

TRANSCANADA KEYSTONE


-135-


kb/d kb/d kb/d

2016 60 190 250 2017 60 190 250 2018 60 190 250 2019 60 190 250 2020 60 190 250 2021 540 300 840 2022 540 300 840 2023 540 300 840 2024 540 300 840 2025 540 300 840 2026 540 300 840 2027 540 300 840 2028 540 300 840 2029 540 300 840 2030 540 300 840 2031 540 300 840 2032 540 300 840 2033 540 300 840 2034 540 300 840 2035 540 300 840

FIGURE 48

TRANS MOUNTAIN


-136-


kb/d kb/d kb/d

2016 257 92 460 2017 277 183 460 2018 280 170 460 2019 270 154 460 2020 270 161 460 2021 250 157 460 2022 251 161 460 2023 245 157 460 2024 243 111 460 2025 242 85 460 2026 245 74 460 2027 248 77 460 2028 250 117 460 2029 242 88 460 2030 235 110 460 2031 195 76 460 2032 193 76 460 2033 221 79 460 2034 220 88 460 2035 221 110 460

FIGURE 49

EXPRESS/MILK/RANGELAND


-137-

Heavy LightCrude Oil Crude Oil

kb/d kb/d

2016 77 59 2017 98 15 2018 314 108 2019 417 128 2020 460 166 2021 77 67 2022 130 72 2023 133 80 2024 211 98 2025 267 105 2026 348 105 2027 406 112 2028 456 133 2029 643 144 2030 780 153 2031 885 241 2032 987 261 2033 1,074 245 2034 1,172 268 2035 1,258 287

FIGURE 50

RAIL


-138-


kb/d kb/d kb/d

2016 396 195 591 2017 530 0 591 2018 591 0 591 2019 493 37 591 2020 528 42 591 2021 262 108 591 2022 268 102 591 2023 267 103 591 2024 265 105 591 2025 268 113 591 2026 370 124 591 2027 428 160 591 2028 463 120 591 2029 506 85 591 2030 491 100 591 2031 510 81 591 2032 531 60 591 2033 523 68 591 2034 508 83 591 2035 544 47 591

FIGURE 56

TRANSCANADA KEYSTONE


-139-


kb/d kb/d kb/d

2016 60 190 250 2017 60 190 250 2018 60 190 250 2019 50 200 250 2020 45 205 250 2021 526 314 840 2022 540 300 840 2023 540 300 840 2024 540 300 840 2025 540 300 840 2026 540 300 840 2027 540 300 840 2028 540 300 840 2029 540 300 840 2030 540 300 840 2031 540 300 840 2032 540 300 840 2033 540 300 840 2034 540 300 840 2035 540 300 840

FIGURE 57

TRANS MOUNTAIN


-140-


kb/d kb/d kb/d

2016 257 92 460 2017 277 183 460 2018 280 170 460 2019 255 157 460 2020 254 156 460 2021 176 49 460 2022 186 75 460 2023 190 71 460 2024 218 69 460 2025 238 77 460 2026 203 64 460 2027 185 71 460 2028 234 98 460 2029 236 70 460 2030 231 76 460 2031 195 76 460 2032 158 66 460 2033 213 76 460 2034 210 79 460 2035 211 122 460

FIGURE 58

EXPRESS/MILK/RANGELAND


-141-

Heavy LightCrude Oil Crude Oil

kb/d kb/d

2016 77 59 2017 98 15 2018 314 108 2019 78 34 2020 110 40 2021 31 0 2022 55 0 2023 57 0 2024 77 0 2025 77 0 2026 77 10 2027 77 0 2028 77 38 2029 169 126 2030 331 127 2031 513 102 2032 643 144 2033 658 191 2034 776 204 2035 847 223

FIGURE 59

RAIL


-142-

kb/d

Jan-11 1,326 Feb-11 1,300 Mar-11 1,340 Apr-11 1,229

May-11 1,335 Jun-11 1,427 Jul-11 1,371

Aug-11 1,507 Sep-11 1,546 Oct-11 1,454 Nov-11 1,467 Dec-11 1,516 Jan-12 1,527 Feb-12 1,558 Mar-12 1,536 Apr-12 1,522

May-12 1,479 Jun-12 1,549 Jul-12 1,541


May-13 1,359 Jun-13 1,400 Jul-13 1,520


May-14 1,558 Jun-14 1,738 Jul-14 1,720


May-15 1,588 Jun-15 1,674 Jul-15 1,653


May-16 1,543 Jun-16 1,507 Jul-16 1,642

Aug-16 1,749 Sep-16 1,700 Oct-16 1,631

FIGURE 60

CANADIAN CRUDE OIL IMPORTS BY MIDWESTERN REFINERS


-143-

kb/d

Enbridge Line 9 85 Flanagan South/Spearhead 150 Southern Access Extension/Mustang 47 Rail to Minnesota 15 Rail to Chicago 60 ChiCap 33 Maumee 15 BP No. 1 114

FIGURE 63

DISPOSITION OF INCREMENTAL MAINLINE THROUGHPUT - 2020


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