Implications of Increasing Light 

Tight Oil Production for U.S. 

Refining

May 2015

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System i 

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and 

analytical agency within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are 

independent of approval by any other officer or employee of the United States Government. The views 

in this report therefore should not be construed as representing those of the Department of Energy or 

other Federal agencies.
U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System ii

Table of Contents

1. Background and Analytical Framework .................................................................................................... 1

Background.............................................................................................................................................. 1

Analytical Framework .............................................................................................................................. 2

2. Results....................................................................................................................................................... 5

2.1. Overview........................................................................................................................................... 5

2.2. Low Production Case ........................................................................................................................ 7

2.3. High Production, Current Crude Export Restrictions Case ............................................................... 7

2.4. High Production, No Crude Export Restrictions Case ....................................................................... 7

3. Appendix ................................................................................................................................................... 9

Tables 

Table 1. EIA studies/activities related to implications of increased crude production and relaxation of 

crude export restrictions ..............................................................................................................................2

Table 2. Crude quality types .........................................................................................................................3

Table 3. Scenario results...............................................................................................................................6

Figures 

Figure 1. Crude production regions..............................................................................................................3

Figure 2. Crude production by region...........................................................................................................5

Figure 3. Crude production by quality type ..................................................................................................5

Figure 4. Change 2025 versus 2013 ..............................................................................................................8
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U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 1 

1. Background and Analytical Framework 

Background

Recent and projected increases in U.S. crude production have sparked discussion about the implications 

of current limitations on crude oil exports for prices, including both world and domestic crude oil and 

petroleum product prices, and for the level of domestic crude production and refining activity. 

In response to multiple requests, the U.S. Energy Information Administration is developing analyses that 

shed light on these issues. Studies completed since May 2014 have considered the characteristics of 

domestic crude production streams, price formation for gasoline and other petroleum products, tools to 

better track displacement of crude imports by domestic production, and technical options for processing 

additional light tight crude oil. 

Given that some responses to the growth in production that has already occurred since 2011, including 

the like-for-like replacement of crude oil imports comparable in quality to new domestic streams, are 

inherently limited going forward, the question of how domestic and international markets for both 

crude and products might evolve in scenarios with and without a relaxation in current limitations on 

crude oil exports continues to hold great interest for policymakers, industry, and the public. 

Recognizing that refiner responses beyond like-for-like substitution are an important pathway to 

increasing the use of domestic crude by refiners much beyond its current level, EIA retained Turner, 

Mason & Company (TM) to provide an analysis of the implications of increasing domestic light tight oil 

production for the U.S. refining, focusing on 

• regional crude supply/demand balances

• refinery crude slates

• operations

• capital investment

• product yields

• crude oil exports/imports

• petroleum product exports

• infrastructure constraints and expansions 

• crude oil price relationship

The TM report is intended to be considered in the context of prior and forthcoming EIA analyses. TM 

was asked to consider likely refining responses to specific crude production scenarios, both with and 

without current limitations on crude oil exports. In this regard, the TM study goes beyond the recently 

published EIA report on Technical Options for Processing Additional Light Tight Oil Volumes within the 

United States, which focused on technical options for the U.S. refining industry to process additional 

volumes of light tight oil. 

Given their focus on refining, the TM report and this paper summarizing its context and findings do not 

address all key questions related to the implications of crude export policy choices. For example, the TM 
May 2015

U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 2 

report uses assumed scenarios of domestic crude production provided by EIA and does not consider 

how possible feedback from crude export policies on domestic crude oil prices could, in turn, potentially 

affect domestic crude production levels. Similarly, the report does not consider international market 

arbitrage on crude or products; or international refinery competitive analysis to support increased U.S. 

product exports. Some of these issues will be considered in forthcoming EIA efforts. 

Table 1. EIA studies/activities related to implications of increased crude production and relaxation of 

crude export restrictions

Study/Activity Status

U.S. Crude Oil Production Forecast-Analysis of Crude 

Types May 2014

Condensate Workshop September 2014

What Drives U.S. Gasoline Prices? October 2014

U.S. Crude Oil Import Tracking Tool November 2014

Technical Options for Processing Additional Light Tight 

Oil Volumes within the United States April 2015

Turner Mason Study: Implications of Increasing Light 

Tight Oil Production for U.S. Refining May 2015

U.S. Crude Oil Production to 2025: Updated Projection 

of Crude Types May 2015

Analysis of Removing Current Limitations on U.S. Crude 

Oil Exports May/June 2015

Analytical Framework

The TM analysis considers operational changes and investments in capacity expansion that domestic 

refiners would likely make to process increasing volumes of light oil, under two crude production 

scenarios and two crude export policy scenarios, one representing continuation of current crude export 

policies, the other a relaxation of those policies. The analysis covers the period 2014 through 2025, using 

2013 as the base year. 

TM used its own proprietary domestic refinery modeling platform for the analysis. EIA provided detailed 

year-by-year forecasts of U.S. crude production by region, basin, and crude quality category for two 

cases, a low production (LP) case and a high production (HP) case. For both production cases, U.S. crude 

oil was classified into nine crude types produced from eight regions. EIA did not provide a forecast for 

Canadian crude oil production. TM used its own forecast of Canadian crude oil production for the study. 
May 2015

U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 3 

Figure 1. Crude production regions

 

For the purposes of this study, the Rocky Mountains and Northern Great Plains crude production 

profiles were combined. Although Alaska and Lower 48 Offshore regions are not shown on the map 

above, they are included in the study.

Table 2. Crude quality types

Crude Oil Type API Gravity (degrees) Sulfur Content 

(wt.%)

API 50+ API>=50 <0.5

API 40-50 sweet 40<=API<50 <0.5

API 35-40 sweet 35<=API<40 <0.5

API 35+ sour 35<=API >=0.5

API 27-35 med-sour 27<=API<35 <1.1

API 27-35 sour 27<=API<35 >=1.1

California API<27 1.1-2.6 

API<27 sweet API<27 <1.1

API<27 sour API<27 >=1.1

EIA provided TM with the following additional inputs: 

• Brent and WTI prices for low production case 

• Brent prices for high production cases

• Refined product demand projections for the United States 

The crude production and price forecasts EIA provided for this study were generated while crude prices 

were dropping rapidly and price uncertainty was increasing; however, as refineries make decisions 

based on the relative prices of different types of crude oil, and the relative prices of crude oil and 

refined petroleum products, the study results are still meaningful. 
May 2015

U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 4 

EIA also provided TM with a specification of current policies that limit crude oil exports for use in this 

study. Crude oil exports to Canada are allowed. Alaska Cook Inlet crude may also be exported provided 

that conditions related to transportation are met. Also, consistent with determinations by the U.S. 

Department of Commerce, Bureau of Industry and Security, condensate processed through a distillation 

tower is classified as a petroleum product and may be exported without a license. The specification of 

current policy outlined above is less restrictive than the base case assumptions used in some other 

studies that have considered the implications of relaxing current limits on crude oil exports. 

Three cases were analyzed:

• Low crude production under current export restrictions

• High crude production without export restrictions

• High crude production with current export restrictions 

A fourth case, low crude production without export restrictions, was also considered for analysis.

However, results obtained for the low crude oil production case under current export restrictions found 

that domestic production volumes, which reach 10.9 million barrels per day (bbl/d) in 2025 in that case, 

could be processed domestically without the need for significant capacity expansion after consideration 

of crude export opportunities available under current policies. Absent a requirement for major 

investments in incremental capacity that might only be incentivized by a widening of the gap between 

domestic and international crude prices, TM found that current export policies did not cause the spread 

between domestic and global crudes to widen in the low production case. Based on this finding, TM 

determined that refining results for the low production case would not materially differ between low 

production case with current export limitations and the low production case without those limitations.

For this reason, the latter combination of production and policy was not pursued as a separate case in 

the TM report. 
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U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 5 

Figure 2. Crude production by region

million barrels per day

Note: Northern Great Plains states (Montana, North Dakota, and South Dakota) are included with the Rocky Mountains region.

Figure 3. Crude production by quality type

million barrels per day

2. Results 

2.1. Overview

In all three scenarios developed by TM, increasing domestic crude oil production leads to a decline in 

crude imports, an increase in refinery runs, new investments to expand refinery capacity, and higher 

crude and refined petroleum product exports. However, the magnitudes of the changes, which are 

tabulated in Table 3, vary across the scenarios. 
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U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 6 

Table 3. Scenario results

Low production/ 

exports restricted

High production/

exports unrestricted

High production/

exports restricted

Crude production

2025 vs. 2013 +3.5 million bbl/d +7.2 million bbl/d +7.2 million bbl/d

2025 vs. 2013 % change 46% higher 97% higher 97% higher

2025 production 10.9 million bbl/d 14.7 million bbl/d 14.7 million bbl/d

Crude imports

2025 vs. 2013 -1.5 million bbl/d -2.8 million bbl/d -2.9 million bbl/d

2025 vs. 2013 % change 19% lower 36% lower 37% lower

2025 imports 6.3 million bbl/d 4.9 million bbl/d 4.9 million bbl/d

Existing refinery crude runs (a)

2025 vs. 2013 +1.3 million bbl/d +1.4 million bbl/d +1.5 million bbl/d

2025 vs. 2013 % change 8% higher 9% higher 10% higher

2025 refinery runs 16.3 million bbl/d 16.4 million bbl/d 16.5 million bbl/d

New refinery unit runs (b)

2025 vs. 2013 inputs +0.3 million bbl/d +0.7 million bbl/d +2.1 million bbl/d

Crude exports

2025 vs. 2013 +0.4 million bbl/d +2.3 million bbl/d +0.7 million bbl/d

2025 crude exports 0.6 million bbl/d 2.4 million bbl/d 0.8 million bbl/d

Existing refinery investment (c) 

Total capacity added 0.4 million bbl/d 0.4 million bbl/d 0.4 million bbl/d

New refinery unit investment (d)

Dollars spent $1.8 billion $2.3 billion $11.0 billion

Total capacity added 0.5 million bbl/d 0.8 million bbl/d 2.4 million bbl/d

Net refined product exports (e) 

2025 vs. 2013 +2.0 million bbl/d +1.8 million bbl/d +3.4 million bbl/d

2025 net fin. prod. exports 3.1 million bbl/d 2.9 million bbl/d 4.5 million bbl/d

Brent-WTI spread

2015-2025 average $6.78/bbl $6.64/bbl $13.78/bbl

Notes: 

(a) Existing refinery crude runs increase as a result of both increased capacity and utilization.

(b) New refinery units include stabilizers, splitters, and hydroskimming refining capacity, which combine 

distillation and basic upgrading units.

(c) Existing refinery investment for currently planned refinery projects (which include projects to expand light 

crude capacity as well as other substantial refinery unit expansions) total between $6–7 billion, according to 

Turner Mason estimate.

(d) New refinery unit investment costs for splitters and hydroskimmers are estimated by EIA based on 

correspondence with Turner Mason on March 11, 2015. New refinery unit investment costs for stabilizers are 

estimated by EIA based on brownfield stabilizer cost from Table ES-1 in EIA's Technical Options for Processing 

Additional Light Tight Oil Volumes within the United States.

(e) Net refined product exports include gasoline, jet/kerosene, distillate, residual fuel, aviation gas, 

petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke, refinery gas, and other miscellaneous 

products. Net refined product exports do not include NGL.

Source: U.S. Energy Information Administration, based on Turner Mason & Company.

 
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U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 7 

2.2. Low Production Case

In the low production case, by 2025, the U.S. refinery system accommodates 3.5 million bbl/d of 

incremental (relative to a 2013 baseline) light crude production by investing $1.8 billion in new, less 

sophisticated processing units, i.e., splitters. This is in addition to the already announced investment to 

expand and debottleneck existing capacity, some of which has already been completed. A list of these 

announced projects is provided in the report’s Input Table 5. The incremental production is absorbed by 

reducing crude imports by 1.5 million bbl/d; increasing refinery runs by 1.3 million bbl/d day; increasing 

crude exports by 0.4 bbl/d; and processing 0.3 bbl/d of crude in the new splitter units. The increase in 

crude runs at domestic refineries results in higher U.S. net exports of refined products, based on the 

assumption across all cases that U.S. refineries remain competitive in the global market. The price of 

U.S. crude WTI does not change relative to the price of global benchmark Brent as the U.S. refining 

system does not require significant new capacity investments beyond that which has already been 

planned. 

2.3. High Production, Current Crude Export Restrictions Case 

In the high resource case and with no changes to current export restrictions, by 2025, additional 

processing capacity investment is required to absorb 7.2 million bbl/d of incremental (relative to a 2013 

baseline) domestic light crude production. An estimated $11.0 billion dollars is invested to expand U.S. 

processing capacity by 2.4 million bbl/d in the form of new stabilizers, splitters, and hydroskimming 

refining capacity, which combine distillation and basic upgrading units. This is in addition to the already 

announced plans to expand and debottleneck existing capacity. The 0.4 bbl/d crude processing capacity

expansions at existing refineries, combined with an increase in utilization, increases crude runs at 

existing refineries by 10% to 16.5 million bbl/d. By 2025, the increase in crude runs results in net refined 

product exports of 4.5 million bbl/d, an increase of 3.4 million bbl/d compared with 2013. Crude exports 

increase modestly, limited by the volume of U.S. crude that Canadian refineries can absorb, but crude 

imports decline by 37%. Imports of most all grades of crude except heavy sour crude decline to zero. The 

price of WTI crude oil declines relative to Brent reflecting the price discount required to incentivize 

incremental U.S. refiner investment needed to process higher volumes of light crude oil. The Brent-WTI 

spread increases to $18/bbl in 2018 and then falls to $12.60/bbl in 2022 and remains between $12/bbl 

and $13/bbl through 2025, reflecting the costs of hydroskimming refinery investments. 

2.4. High Production, No Crude Export Restrictions Case

When the high resource case is considered in a scenario without crude export restrictions, crude exports 

increase to 2.4 million bb/d in 2025. Domestic processing capacity also increases, but to a significantly 

lesser extent than in the high production case with current crude export restrictions, as $2.3 billion is 

invested to build 0.8 million bbl/d of new stabilizer and splitter capacity. More costly hydroskimming 

refineries are not built, because the ability to export crude oil prevents the price of WTI from declining 

to a level that would support such investment. Crude imports decline, falling by 36% from 7.8 million 

bbl/d in 2013 to 4.9 million bbl/d in 2025, as refiners make the same adjustments to back out light and 

medium crude imports as in the high production case with current export restrictions, run their 

refineries at high utilization rates, and process light oil through splitters. 
May 2015

U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 8 

Figure 4 illustrates how the growth in crude oil production by 2025 is absorbed for each of the three 

scenarios. 

Figure 4. Change 2025 versus 2013

thousand barrels per day
May 2015

U.S. Energy Information Administration | Implications of Increasing Light Oil Production on the U.S. Refining System 9 

3. Appendix 

Full text and data tables from TM. 
Implications of Increasing U.S. 

Light Tight Oil Production 

A study for the 

Energy Information Administration 

 Presented by 

Suite 2920

2100 Ross Avenue 

Dallas, Texas 75201 

214/754-0898 

turnermason.com 

April 28, 2015 

John R. Auers 

John M. Mayes
TABLE OF CONTENTS 

Introduction ................................................................................................................ 2

Background ................................................................................................................ 2 

Key Study Assumptions and Data Table Descriptions ............................................... 3 

Data Tables 

Series I – Input Tables ..................................................................................... 16 

Series II – Low Production Base Case ............................................................ 35 

Series III – High Production Base Case .......................................................... 67 

Series IV – High Production Export Case ....................................................... 99 

Series V – Appendix Tables – Key Crude Logistical Assets ......................... 131 

 
Page 2 

Introduction 

The Energy Information Administration (“EIA”) retained Turner, Mason & Company 

(“TM&C”) to provide an analysis of the implications of increasing domestic light tight oil 

production on the U.S. refining sector under two crude production scenarios and two 

crude export scenarios over the period 2014 through 2025. For each case, this analysis 

considered the impacts on regional crude supply/demand balances, refinery crude 

slates, operations, capital investment, product yields, crude oil exports/imports, 

petroleum product exports, infrastructure constraints and expansions and crude oil price 

relationships.  

Background 

This work will be used by the EIA as input to its assessment for government policy 

makers of potential impacts under various crude export scenarios and production 

forecasts. TM&C’s domestic refinery modeling platform was used to provide the 

specialized supplemental input that the EIA desired to assist them in preparing this 

assessment. 

It should be noted that this project was initiated prior to the sharp drop in crude prices, 

which has taken place since the middle part of 2014. As a result, the crude production 

and price levels in the cases provided to us by the EIA are higher than what would be 

projected today; however, the dynamics driving the impacts on all of the key parameters 

identified above (crude supply/demand, product yields, price relationships, etc.), from 

production levels and export policy, are still valid. Therefore, the forecasts still provide 

valid information to help the EIA make the necessary policy assessments despite input 

parameters being “out of sync” with the current environment.

At the commencement of the study, the EIA provided TM&C a detailed year-by-year 

forecast of U.S. crude production by region, basin and crude quality category for a Low 

Production Case and a High Production Case. U.S. Production has been classified into 

nine crude types covering seven regions shown below and on page 3. 

Crude Oil Type

API Gravity

(degrees)

Sulfur Content (wt.

%)

API 50+ API>=50   <0.5

API 40‐50 sweet 40<=API<50    <0.5

API 35‐40 sweet 35<=API<40   <0.5

API 35‐40 sour 35<=API<40    <1.1

API 27‐35 med‐sour 27<=API<35   <1.1
Page 3

Crude Oil Type

API Gravity

(degrees)

Sulfur Content (wt.

%)

API 27‐35 sour 27<=API<35 >=1.1

California API<27 1.1‐2.6

API<27 sweet API<27   <1.1

API<27 sour API<27 >=1.1

The EIA did not provide a forecast for either U.S. natural gas liquids (NGL) production 

or Canadian crude oil production. Rather, TM&C generated forecasts for these 

volumes, consistent with the crude price and production levels in the EIA-provided Low 

Production and High Production Cases. 

The seven U.S. production regions are defined by the map below, with the Northern 

Great Plains being combined with the Rocky Mountains and Alaska (not shown) being 

the seventh region. Lower 48 Offshore production is included in its nearest defined 

region (e.g., Gulf of Mexico production is in the Gulf Coast region). For this study, the 

EIA’s regional forecasts included production estimates for each of the EIA crude 

categories. 

Key Study Assumptions and Data Table Descriptions

The foundation of Implications of Increasing U.S. Light Tight Oil Production is two crude 

oil production forecasts supplied by the EIA. The Low Production Case details 
Page 4

moderate oil production growth, peaking in 2020 at 11.05 million BPD. The High 

Production Case has a more aggressive trajectory, with output at 14.7 million BPD in 

2025. TM&C was tasked with assessing crude oil refining demand (by region and 

grade) and calculating refining product output. The refining output was compared with a 

product demand forecast (also supplied by the EIA) to determine product balances and 

export requirements. These results were evaluated for two crude export cases: the 

Base Case, which would not allow crude exports except to Canada, and the Export 

Case, which would allow unlimited crude exports. As a result, this study is based on 

substantive input from both the EIA and TM&C to determine the implications of rising 

U.S. production levels. The three study cases are summarized below: 

 The Low Production Case utilizes the EIA-supplied Low Production crude 

forecast and assumes current export regulations are unchanged, both from a 

policy and an administrative perspective. 

 The High Production Base Case utilizes the EIA-supplied High Production 

crude forecast and assumes current export regulations are unchanged, both from 

a policy and an administrative perspective. 

 The High Production Export Case utilizes the EIA-supplied High Production 

crude forecast and assumes unlimited crude exports are permitted.

The output of the study is provided in a series of tables at the end of this document: 

 Input Tables – Series I Tables 

 Low Production Case – Series II Tables 

 High Production Base Case – Series III Tables 

 High Production Export Case – Series IV Tables 

 Appendix Tables – Series V Tables 

One of the early conclusions of the study was that no crude exports would be required 

using the Low Production Case. With production peaking at slightly over 11 million BPD 

and significant movements to Canada (550 MBPD), the U.S. refining system could 

process the remaining domestic supply. This eliminated the need for a Low Production 

Export Case. 

Input Table Descriptions 

Table I-3, Canadian Crude Production Forecast 

The Canadian crude production forecast was supplied by TM&C. We have researched 

Canadian production trends for several years as part of our NORTH AMERICAN CRUDE 

AND CONDENSATE OUTLOOK and WORLD CRUDE OIL OUTLOOK studies. The principal 
Page 5

input source is from the yearly, “Crude Oil Forecast, Markets and Transportation,”

published by the Canadian Association of Petroleum Producers. We also incorporate 

third-party assessments of production capabilities from producers, governmental 

agencies and media outlets. 

Canadian production is divided into two regions: Western Canada includes British 

Columbia, Alberta, Saskatchewan, and Manitoba and Eastern Canada comprises the 

remaining provinces. This division is necessary to track oil flow (both inside Canada 

and to the various U.S. PADDs), but it is also utilized for the refining classifications. 

A distinction, which is unique to Canada, is the tracking of both oil production and 

shipments. Oil shipments include diluents which have been imported into Canada 

(primarily from the U.S.) for blending with the heavy, bitumen-based streams. Canadian 

diluents are considered to have already been blended into the heavy crude streams. 

Table I-4, U.S. Refining Capacities – 2013 

This data was generally derived from EIA reports, but has been modified based on 

information received by TM&C. Refining capacities were utilized to estimate crude run 

levels in the forecast years by applying estimated utilization rates for each case. These 

utilization rates are shown in Tables II-6, III-6 and IV-6. 

Table I-5, Projected U.S. Refinery Projects Through 2019 

TM&C routinely monitors new refining projects in the U.S. and throughout the world as a 

primary component of its biannual CRUDE AND REFINED PRODUCTS OUTLOOK. The list in 

Table I-5 is a portion of our recent survey and details the projects, which will have an 

impact on crude demand; either by increasing crude runs or shifting to a different mix of 

crude grades. There are 22 projects on the list, which add an additional 416 MBPD of 

crude capacity to U.S. refineries. While there is a modest increase in heavy crude runs, 

the bulk of the increase is in light sweet crude, reflective of the current shift to process 

additional quantities of shale grades. The projects are grouped by PADDs and are used 

to estimate crude run levels (by grade) in the forecast years. 

Table I-6, 2013 Charge and Yield Data by PADDs 

Before the analysis phase of the study could be conducted, it was necessary to 

establish the refining feedstocks and output by PADD for the base year of 2013. The 

principal source of data for this table was from the EIA web site. This data became the 

foundation for estimating future product outputs for each PADD. TM&C utilized its 

proprietary refining modeling system to calculate changes in refining charges and 

yields, which were then added to the 2013 base values. 
Page 6

Table I-9, Census Regions to PADD Conversion; Table I-10, EIA Product Demand – 

Low Production Case; and Table I-11, EIA Product Demand – High Production Case 

The EIA provided two product demand forecasts. Table I-7 (U.S. Domestic Petroleum 

Product Demand – Low Production Case) details a moderate product demand forecast, 

which was used in conjunction with the Low Production Case crude forecast. Table I-8 

(U.S. Domestic Petroleum Product Demand – High Production Case) has a more robust 

forecast reflective of the High Production crude forecast. These two forecasts detail 

product demand by grade, but are listed in nine Census Bureau geographic divisions. It 

was necessary to convert this data to a PADD format. Table I-9 (Census Regions to 

PADD Conversion) details the percentage of each Census Bureau region in each 

PADD. The percentages are from the Census Bureau web site for populations in 2013. 

This methodology assumes that petroleum product demand is proportional to 

population. Tables I-10 and I-11 are the adjusted demand tables for the two cases in a 

PADD format. 

Table I-12, TM&C Natural Gas Liquids Forecast 

The demand forecasts in Tables I-7 and I-8 (and the revised I-10 and I-11) are for all 

petroleum products, including those derived from the production of Natural Gas Liquids 

(NGLs). NGLs are light hydrocarbon products; including ethane, propane, butane, and 

small volumes of pentane and hexane. Because these products are also derived from 

crude oil, it was necessary to produce an NGL forecast in order to estimate total product 

yields and export requirements. Table I-12 (TM&C Natural Gas Liquids Forecast) 

details a Low Production and High Production NGL forecast to be used with the 

respective crude oil forecasts. 

Table I-13, Other Refining and Logistic Assumptions 

Table I-13 lists a series of logistic, refining and other assumptions which were 

previously agreed to by the EIA in a series of discussions. Some of the items are 

duplicates to other tables in the workbook. 

Output Table Descriptions

The structures of the three output workbooks are similar. The first four tables detail the 

individual crude grades processed in each PADD for the base year of 2013 and the 

forecast years of 2015, 2020, and 2025. Tables 7-12 list the product yields for each of 

these crude slates, while Tables 13-18 compare the refining yields to the product 

demand forecast to determine product imbalances. Tables 21-28 outline crude and 

product export requirements. 
Page 7

Tables 1-4, Crude Oil Supply and Demand Balances 

Because of its advantaged pricing, refiners are continually incentivized to process 

steadily increasing volumes of light tight oil crudes. There are limits as to how much 

each refinery can accommodate of the lighter grades. In general, refiners are induced 

to back out other foreign light grades and even foreign medium grades to process 

domestic light. This transition does not come without a cost, however. Substantial 

incremental capital costs may be required to revamp atmospheric units, expand light 

ends processing and handling capabilities, and even expand isomerization or reforming 

capacities. TM&C has assumed the necessary capital expenditures will be made and 

refineries will eliminate all foreign light and medium imports where necessary. 

While TM&C believes refiners are willing to back out medium grades to process more 

domestic light, we do not believe this transition will extend to foreign heavy grades. In 

recent decades, refiners have made considerable capital investments to expand coking 

units in order to process greater volumes of heavy crudes. This shift was first made to 

accommodate the growing volumes of heavy Mexican and Venezuelan grades, but 

more recently has focused on rising Canadian volumes. TM&C does not feel these 

investments will be under-utilized in the future for prolonged periods. 

As a result, the primary balancing mechanism for Tables 1-4 was based on the 

computed vacuum tower bottoms. This is the primary feedstock for coking units for 

most refiners. This volume was calculated for 2013 and then held constant for each 

forecast year, except where coking unit additions have been announced. This process 

insured the coking units would be fully utilized during the forecast years, and residual 

fuel and asphalt yields would be held relatively constant in noncoking refineries. This 

methodology was used to calculate the maximum amount of domestic light penetration 

for each PADD. 

Table 6, U.S. and Canadian Utilization Rates 

Refining utilization rates are generally related to refining margins. As margins increase, 

refiners are induced to process greater quantities of crude oil until maximum limits are 

hit. On the assumption that refining margins would be highest in the High Production 

Base Case (no crude exports except to Canada), we have U.S. utilization rates at 

86.6% in 2025. In this scenario, crude is constrained in the U.S. and prices must 

stimulate additional construction of new hydoskimming facilities. In the High Production 

Export Case (where margins would expected to be lower than the High Production Base 

Case), average utilization rates in 2025 are at 85.9%. In the Low Production Case, 

utilization rates are 85.2%. All of these levels are significantly higher than the 80.3% 

rate seen in 2013. 
Page 8

Tables 7-12, Charge and Yield Data 

TM&C has calculated product yields for each PADD in each of the forecast years using 

its proprietary refining models. Product yields were determined as changes from the 

base year of 2013, and then added back to the calibrated 2013 data shown in Table I-6. 

All splitter and hydroskimmer projects were assumed to be built in PADD III. 

Tables 13-18, Refinery Product Supply and Demand Balances 

These tables compare the changes in refinery production with the changes in product 

demand for the main product groups. In Tables 7-12, the heavy fuel included both 

residual fuel and asphalt, but in Tables 13-18, only residual fuel is shown to conform to 

the EIA product categories. Asphalt production and demand is in the Other category. 

Table 18 also includes an NGL balance along with a correction factor to tie back to the 

2013 summary balance currently on the EIA web site. The correction factor is the sum 

of inventory changes, EIA adjustments, supply inputs into refineries, and other factors. 

It is included in the Other product category. 

Table 19, Crude Oil Flows 

These tables highlight the change in crude flows during the forecast years. The 

balances on the left side of the worksheet summarize the total crude inputs for each 

region. The balances on the right side of the worksheet detail the changes from 2013 

going forward. Increases of greater than 100 MPBD are highlighted to indicate regions 

that may require additional infrastructure. Decreases are not relevant in that it is 

assumed the infrastructure is already in place. 

Table 20, Required Crude Oil Logistic Improvements 

These worksheets detail the logistic improvements which we estimate will be necessary 

to handle the additional crude flows in the forecast years. Increases within production 

areas (such as the Gulf Coast for example) were not assessed as it was assumed that 

necessary logistic improvements were to be constructed as needed. Supporting 

documentation for these tables is shown in the Appendix Tables. 

Tables 21-26, Supply and Demand Balances by Products 

These tables summarize the product imbalances by product. The product surpluses 

shown for 2013 are the actual net export volumes. Table 25 (Other Products) includes 

the NGL balance and the adjustment factor. 
Page 9

Tables 27-28, Crude and Product Exports 

These tables summarize the volumes and likely export destinations of U.S. and 

Canadian crudes and U.S. products. 

Table 29, Crude Price Forecasts 

These tables summarize the annual yearly price forecasts through 2025 for key market 

crudes, including Brent, LLS, WTI, Bakken, Mexican Maya and Western Canadian 

Select (WCS). They also show the key differentials between these crudes. 

EIA provided TM&C a Brent price forecast for both the Low Production Case and the 

High Production Case. From this absolute view on crude prices, we then generated 

forecasts for the other crudes using TM&C’s proprietary modeling platform, which 

considers the various factors that we believe drive petroleum pricing. These factors 

include crude supply and demand, logistical limitations, export policy, crude quality, 

product supply and demand, refinery capabilities, as well as all other relevant drivers. 

For each case, the forecast prices and relationships are consistent with the supply 

estimates, crude and product flows, export policy assumptions and other key 

assumptions spelled out in this report (both descriptively and in the data Tables). 

Low Production Case – Background Assumptions 

The absolute (Brent) prices provided by EIA are higher in this scenario than for the High 

Production Cases. This is consistent with the lower supply environment which this case 

is based on. Since domestic crude production does not grow fast enough in this case 

to exceed the total of domestic and allowable export market demand, price relationships 

in this case are not impacted by export restrictions and therefore, there was no need for 

a separate Low Production Export Case. 

Brent – LLS Differential 

The domestic crude discount, as measured by the Brent – LLS differential, is 

expected to stay generally in a range from $1.50 to $2 per barrel (on an annual 

average basis), and is consistent with an environment where domestic crude has 

displaced all waterborne light imports on the USGC. However, production levels have 

not gotten to the point where export restrictions are binding and domestic crude 

(including LLS) is priced to compete with the remaining waterborne medium imports on 

the USGC and light imports to the USWC. 
Page 10

LLS – WTI Differential 

Over the last year, sufficient pipeline capacity has been put into place to allow Permian 

Basin crude to reach USGC refining markets. This includes pipelines from both the 

Permian directly to the USGC and pipelines from Cushing to the coast (see Appendix 

Tables 2 and 3). Additional pipelines are being built and we believe “connectivity” will 

be maintained going forward. As a result, we expect the WTI (Cushing) price to trade 

at a level equal to pipeline transportation and quality-adjusted parity with LLS (St. 

James) on the USGC (about $5.00 to $5.50 per barrel discount) on a sustainable 

basis. 

 

WTI – Bakken Differential 

After filling available space in the local, Midcontinent and Pacific Northwest markets, 

incremental production of Bakken will move to both the East Coast and USWC by unit 

train. There, it will compete with Brent-linked, waterborne imports. Considering rail 

transportation costs, quality differentials between Bakken and Brent, and the Brent/LLS 

and LLS/WTI differentials discussed above, we expect the Bakken (Clearbrook) price 

will average a discount of about $4.25 to $4.75 per barrel compared to WTI 

(Cushing) throughout the forecast period. 

LLS – Maya Differential 

The light-heavy differential (as represented by LLS – Maya price) will be based on 

supply/demand fundamentals between light and heavy crudes in North America and 

more specifically on the USGC. As a result, factors such as relative light vs. heavy 

supply growth, investment in refining capabilities targeted to run either light or heavy 

crudes and build out of logistics facilities to move heavy Western Canadian crude to the 

USGC will be key drivers. 

In the short term, relatively strong growth in light crude production combines with 

continued stagnation of heavy crude production from Mexico and Venezuela, and the 

inability of growing Canadian heavy production to reach the USGC to keep the spread 

relatively compressed (although the recent Seaway expansion has increased Canadian 

connectivity). On the demand side, the strong growth in light crude production actually 

increases the demand for heavy crude as it is necessary as a blend stock to create a 

“pseudo” medium crude. Together these factors result in our forecast of a Maya (FOB) 

discount vs. LLS (St. James) of about $11 to $12 per barrel over the next three 

years. 

 

In the longer term, TM&C expects the differential to grow as Canadian heavy production 

picks up and accessibility to the USGC is facilitated by the increase in both pipeline and 
Page 11

rail capacity. We also expect Latin American heavy crude production to grow as the 

traditional U.S. suppliers, Mexico and Venezuela, improve their upstream results. 

Continued growth of production, from similar heavy crude reserves in Colombia and 

offshore Brazilian subsalt deposits, will add to the Latin American totals. On the 

demand side, the low coking margins of recent years, and in the first half of our forecast 

period, will result in no new coking capacity being developed or built. Factoring all of 

this into the supply/demand balance, TM&C expects the LLS/Maya spread to grow to 

levels exceeding $15 per barrel by 2022 and reach $17 per barrel by 2025. 

Maya – WCS Differential 

Until recently, the ability of heavy Western Canadian crude to reach USGC markets was 

extremely limited. As a result, WCS and Maya were not “connected” and the differential 

between the crudes was very volatile and unpredictable. In most cases, because of the 

“stranded” condition for WCS and its inability to readily reach markets, the WCS 

(Hardisty) price was discounted significantly compared to Maya (FOB), sometimes by 

as much as $40 and more. With the recent completion of the Seaway “twin,” which 

more than doubled the capacity of that pipeline system to 850 MBPD, a sustainable 

“connection” to the USGC has been established and the Maya (FOB) – WCS (Hardisty) 

differential has declined to levels equal to pipeline transportation and quality-adjusted 

parity at the USGC (about $7 per barrel). We have assumed that this connectivity will 

remain as pipeline capacity stays sufficient to move crude from Hardisty to markets and 

thus, we expect the Maya – WCS differential to stay in the $7 to $8 per barrel range

throughout the forecast period. 

High Production Base Case – Background Assumptions 

As noted earlier, the absolute (Brent) prices provided by EIA are lower in this scenario 

than for the Low Production Cases due to the higher level of production. By 2020, this 

difference approaches $7 per barrel and grows further to about $14 by 2025. Domestic 

crude production is significantly higher than in the Low Production Case and quickly 

exceeds the total of domestic and allowable export market demand. As a result, 

domestic discounts and even light/heavy discounts are significantly different between 

the Base Cases (Exports Restricted) and Export Case, as described in the paragraphs 

to follow. 

One thing to note is that the EIA provided TM&C a single Brent price set for the High 

Production Case and we held to that, leaving Brent prices identical between the Base 

Cases and the Export Case. 

 
Page 12

Brent – LLS Differential 

Due to the “stranded” condition that develops in the High Production Base Case as 

domestic production exceeds allowable market options, the domestic crude discount 

(measured by the Brent – LLS differential) is significantly higher than in either the Low 

Production Base Case or the High Production Export Case. We expect that the 

domestic crude discount grows rapidly from an average of $3.20 per barrel in 

2015 to exceed $13 per barrel (annual average) in 2018. Thereafter, investment in 

“crude-to-product” processing facilities (incentivized by the large discounts) will 

begin to come on line and the discount declines to a level of $7 to $8 per barrel by 

2022 and stays at this sustainable range for the remainder of the forecast period. 

TM&C believes this level of discount will be necessary to incentivize continued 

investment in processing to keep up with domestic production growth. 

LLS – WTI Differential 

Our assumption is that sufficient pipeline capacity will be added to maintain 

“connectivity” to USGC refining markets for Permian crude. As a result, we expect the 

LLS – WTI differential to be identical in this case to that for the Low Production 

Case, again based on pipeline transportation and quality-adjusted parity. This 

was a WTI (Cushing) discount of about $5.00 to $5.50 per barrel vs. LLS (St. 

James). 

 

WTI – Bakken Differential 

With relative production levels between WTI and Bakken similar between the Low 

Production Base Case and High Production Cases and impacts of export restrictions 

similar as well, we expect WTI and Bakken to move in tandem relative to each other in 

all of the cases. As a result, the Brent (Clearbrook) price will average a discount of 

about $4.25 to $4.75 per barrel compared to WTI (Cushing) throughout the 

forecast period, the same relationship as in the Low Production Case and the 

High Production Export Case.

LLS – Maya Differential 

Although Mexican produced Maya is not directly impacted by U.S. crude export 

restrictions, it (along with other Latin America and Canadian heavies) will be indirectly 

impacted; however, this impact will be less than that for U.S. produced crudes as they 

will have some ability to access foreign markets. As a result, the light/heavy (LLS – 

Maya) differential will be lower in the High Production Base Case than in either the Low 

Production Base Case or the High Production Export Case. 
Page 13

On a sustainable basis, we believe heavy crude producers will have to reduce prices 

somewhat to continue to incentivize USGC coking refineries to run heavy crudes. This 

is because of the inability to fully place these barrels in alternate markets due to limited 

available deep conversion capacity in the rest of the world. We believe a LLS – Maya 

differential of $7 per barrel provides marginally sufficient economics for most USGC 

deep conversion refineries to run heavy crudes, and that this will be the sustainable 

“floor” for the differential. Our forecast, therefore, is for LLS - Maya to decline from 

$11 per barrel in 2015 to the $7 per barrel floor by 2018 as U.S. export restrictions 

drive the domestic crude discount to double digit levels. It stays at these levels 

through 2019 and starts to increase in 2020, reaching and exceeding $13 per 

barrel by 2025 as investment in “crude-to-product” processing facilities decrease 

the domestic discount. The 2025 level is about $4 per barrel less than in the Low 

Production Case.

Maya – WCS Differential 

As with the LLS/WTI and Bakken/WTI relationships, the price dynamics between all 

three of the cases (Low Production, High Production Base, and High Production Export) 

for Maya vs. WCS remain the same. In all cases we assume sufficient pipeline capacity 

is in place to maintain connectivity between Western Canada and the USGC and the 

two heavy crudes compete with each for the attention of USGC refineries based on their 

quality differences. As a result, we expect the Maya (FOB) – WCS (Hardisty) 

differential stays in the $7 to $8 per barrel range throughout the forecast period, 

based on quality and transportation (to the USGC) differences. 

High Production Export Case – Background Assumptions 

For the absolute (Brent) prices, see the discussion on page 11 for the High Production 

Base Case. Absolute prices are assumed to be the same in the High Production Base 

Case and the High Production Export Case. 

Brent – LLS Differential 

With crude exports allowed, a “stranded” situation does not develop and the Brent – 

LLS differential does not “blow out” as in the Base Case. Instead, domestic crude 

essentially moves to an “export parity” relationship with Brent. Because it takes some 

time to develop export facilities and markets, we show this happening over a three-tofour year period. From a level of $2.15 per barrel in 2015, we forecast the LLS 

discount (vs. Brent) to decline to about $0.90 per barrel by 2018. As U.S. 

production continues to grow, we forecast that this discount will increase 

gradually to about $1.40 per barrel by 2025 due to supply/demand factors. 
Page 14

LLS – WTI Differential 

Export policy should not affect this differential. Therefore, for the same reasons as in 

the High Production Base Case, we have the LLS – WTI differential identical in this 

case to that for the Low Production Case, again based on pipeline transportation 

and quality-adjusted parity. This has WTI (Cushing) discounted by about $5.00 to 

$5.50 per barrel vs. LLS (St. James). 

 

WTI – Bakken Differential 

Again, we expect export policy to impact WTI and Bakken in the same way. As a result, 

this differential is the same in the High Production Export Case as in both the Low 

Production Case and the High Production Base Case.

LLS – Maya Differential 

The trajectory of the light/heavy differential in this case is forecast to be similar to that in 

the Low Production Case, as in neither case are crude export restrictions impacting. 

The level of the discount is a bit lower in this High Production Case, due to the higher 

relative level of light crude production compared to the Low Production Case. As a 

result, we forecast a Maya (FOB) discount vs. LLS (St. James) of about $11 to $12 

per barrel over the next three years, growing to reach $16 per barrel by 2025. At 

that point, the differential is about $1 per barrel below that in the Low Production Case. 

 

Maya – WCS Differential 

As with the LLS/WTI and Bakken/WTI relationships, the price dynamics between all 

three of the cases (Low Production, High Production Base, and High Production Export) 

for Maya vs. WCS remain the same. As a result, we expect the Maya (FOB) – WCS 

(Hardisty) differential stays in the $7 to $8 per barrel range throughout the 

forecast period, based on quality and transportation (to the USGC) differences. 

Appendix Tables – Key Logistical Assumptions 

These tables summarize the most important crude logistics facilities currently serving or 

proposed for U.S. and Canadian crude markets. Data shown includes ownership, 

capacities and start-up timing (for new facilities). Included are both pipelines and rail 

offloading terminals. The tables are arranged by region and cover the most critical 

supply corridors in North America. 

 
Page 15

Table 1, PADD I Rail Offloading Facilities 

This table shows the rail offloading facilities which are either in place or proposed to be 

built to allow domestic crude, primarily Bakken, to reach PADD I refineries. These 

include terminals located both within and outside of refinery gates. 

Table 2, Permian Basin Exit Pipelines 

This table shows the pipelines, both existing and proposed dedicated to moving 

Permian Basin crude oil to either refineries on the USGC or to the Cushing terminal 

complex. 

Table 3, Cushing, OK and Patoka, IL Exit Pipelines 

This table shows the pipelines, existing and proposed, which provide capacity for 

movements from the key Midcontinent crude junctions/terminals in Patoka, Illinois, and 

Cushing, Oklahoma. 

Table 4, PADD V Rail Offloading Facilities 

This table shows the rail offloading facilities, which are either in place or proposed to be 

built to serve PADD V refineries. These include terminals located both within and 

outside of refinery gates. In contrast to the PADD I facilities listed in Table 1, most of 

the PADD V rail terminals are not yet completed and located away from the actual 

refineries. Included are facilities which target a wide variety of domestic crudes, 

including Bakken, Rocky Mountain crudes and Permian Basin crudes 

Table 5, Western Canadian Exit Pipelines 

This table shows the pipelines, existing and proposed, which provide capacity for 

movements from the Western Canadian crude fields to either the U.S. or to ports on 

both the Pacific and Atlantic Oceans. 
16

Number Tab Table Name

I-1 Low Production Case U.S. Crude Production Forecast - EIA Low Production Case

I-2 High Production Case U.S. Crude Production Forecast - EIA High Production Case

I-3 Canada Canadian Crude Production Forecast

I-4 RefCapacities U.S. Refining Capacities - 2013

I-5 New Projects Projected U.S. Refinery Projects Through 2019

I-6 2013 2013 Charge and Yield Data by PADDs

I-7 LP Demand U.S. Domestic Petroleum Product Demand - Low Production Case

I-8 HP Demand U.S. Domestic Petroleum Product Demand - High Production Case

I-9 Regions Census Regions to PADD Conversion

I-10 Adj. LP Demand EIA Product Demand by PADDs- Low Production Case

I-11 Adj. HP Demand EIA Product Demand by PADDs- High Production Case

I-12 NGLs TM&C Natural Gas Liquids Forecast

I-13 Other Assumptions Other Refining and Logistic Assumptions

Implications of Increasing U.S. Light Tight Oil Production

Input Tables
17

 Production 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Domestic Crude Oil Production 7.46 8.54 9.59 10.30 10.65 10.97 11.02 11.05 11.02 11.03 11.02 11.06 10.92

 Northeast 0.10 0.12 0.07 0.07 0.07 0.07 0.07 0.06 0.06 0.06 0.06 0.06 0.06

 Light Sweet 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Light Sour 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

 Medium Medium Sour 0.03 0.03 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.00 0.00 0.00

 Medium Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Heavy Sweet 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Heavy Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ultra Light Sweet 0.03 0.04 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.01

 API 50+ 0.03 0.04 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Gulf Coast 1.31 1.73 2.22 2.43 2.42 2.39 2.36 2.38 2.38 2.39 2.36 2.34 2.28

 Light Sweet 0.22 0.33 0.40 0.42 0.42 0.38 0.36 0.35 0.34 0.34 0.34 0.33 0.34

 Light Sour 0.06 0.08 0.09 0.11 0.12 0.13 0.14 0.15 0.16 0.17 0.17 0.18 0.15

 Medium Medium Sour 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.12 0.12 0.12 0.12 0.12 0.13

 Medium Sour 0.02 0.03 0.04 0.05 0.06 0.06 0.06 0.07 0.07 0.07 0.07 0.07 0.04

 Heavy Sweet 0.01 0.01 0.02 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.02

 Heavy Sour 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02

 Ultra Light Sweet 0.24 0.50 0.80 0.96 0.94 1.02 1.04 1.07 1.09 1.11 1.11 1.12 1.13

 API 50+ 0.64 0.65 0.74 0.74 0.73 0.64 0.61 0.59 0.57 0.56 0.51 0.48 0.46

 Midcontinent 0.60 0.60 0.40 0.39 0.37 0.37 0.38 0.40 0.42 0.45 0.48 0.53 0.57

 Light Sweet 0.15 0.15 0.10 0.10 0.09 0.09 0.10 0.12 0.14 0.16 0.17 0.21 0.23

 Light Sour 0.03 0.03 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02

 Medium Medium Sour 0.07 0.08 0.05 0.05 0.06 0.06 0.06 0.07 0.08 0.09 0.10 0.11 0.11

 Medium Sour 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

 Heavy Sweet 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.01 0.01

 Heavy Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ultra Light Sweet 0.21 0.20 0.13 0.12 0.12 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.12

 API 50+ 0.12 0.13 0.09 0.08 0.08 0.07 0.07 0.06 0.06 0.06 0.06 0.07 0.07

 Southwest 1.65 1.88 2.07 2.18 2.24 2.31 2.35 2.38 2.41 2.45 2.49 2.52 2.53

 Light Sweet 0.33 0.36 0.38 0.39 0.39 0.40 0.40 0.40 0.40 0.41 0.42 0.42 0.41

 Light Sour 0.12 0.12 0.13 0.13 0.13 0.14 0.14 0.15 0.15 0.16 0.16 0.17 0.18

 Medium Medium Sour 0.09 0.09 0.09 0.09 0.09 0.09 0.10 0.09 0.09 0.10 0.10 0.10 0.10

 Medium Sour 0.34 0.32 0.31 0.31 0.31 0.31 0.32 0.33 0.33 0.34 0.35 0.36 0.36

 Heavy Sweet 0.00 0.00 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.02

 Heavy Sour 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.02 0.02

 Ultra Light Sweet 0.65 0.77 0.89 0.96 0.99 1.02 1.02 1.05 1.05 1.05 1.05 1.05 1.04

 API 50+ 0.09 0.20 0.25 0.29 0.31 0.33 0.34 0.35 0.36 0.37 0.38 0.39 0.39

 Rocky Mountain 1.40 1.67 2.06 2.18 2.36 2.44 2.50 2.53 2.55 2.57 2.60 2.61 2.52

 Light Sweet 0.12 0.10 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.09 0.09 0.09 0.09

 Light Sour 0.13 0.15 0.16 0.16 0.17 0.17 0.18 0.19 0.19 0.19 0.19 0.19 0.18

 Medium Medium Sour 0.04 0.03 0.03 0.03 0.03 0.03 0.04 0.04 0.05 0.05 0.06 0.05 0.06

 Medium Sour 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.03 0.04 0.06

 Heavy Sweet 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.03 0.06 0.06 0.06

 Heavy Sour 0.06 0.05 0.05 0.05 0.05 0.04 0.04 0.04 0.05 0.04 0.05 0.05 0.05

 Ultra Light Sweet 0.98 1.28 1.64 1.76 1.93 2.00 2.05 2.06 2.07 2.07 2.06 2.06 1.93

 API 50+ 0.05 0.05 0.05 0.06 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.09

 West Coast, California 0.51 0.52 0.53 0.54 0.55 0.57 0.58 0.59 0.60 0.61 0.61 0.62 0.63

 Lower 48 Offshore 1.37 1.54 1.79 2.07 2.18 2.38 2.35 2.29 2.19 2.11 2.05 2.04 2.01

 Atlantic Medium Medium Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Gulf of Mexico Medium Medium Sour 1.28 1.45 1.70 2.01 2.12 2.33 2.30 2.23 2.14 2.06 2.00 1.99 1.96

 Pacific California 0.09 0.09 0.09 0.06 0.06 0.06 0.06 0.05 0.05 0.05 0.05 0.05 0.05

 Alaska 0.52 0.49 0.45 0.43 0.44 0.45 0.43 0.42 0.40 0.38 0.35 0.34 0.32

 North Slope Offshore Medium Medium Sour 0.00 0.00 0.04 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.06 0.06

 North Slope Onshore Medium Medium Sour 0.50 0.48 0.40 0.35 0.36 0.37 0.35 0.34 0.32 0.30 0.28 0.27 0.25

 South Alaska Medium Medium Sour 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

 Other Crudes Not Listed 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Table I-1

U.S. Crude Production Forecast - EIA Low Production Case

(million barrels per day)
18

Table I-2

U.S. Crude Production Forecast - EIA High Production Case

 Production 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Domestic Crude Oil Production 7.46 8.57 9.80 10.84 11.33 12.26 12.79 13.29 13.64 13.85 14.19 14.55 14.70

 Lower 48 Onshore

 Northeast 0.10 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.09 0.09 0.10

 Light Sweet 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Light Sour 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

 Medium Medium Sour 0.03 0.02 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00

 Medium Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Heavy Sweet 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Heavy Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ultra Light Sweet 0.03 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02

 API 50+ 0.03 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.05 0.05 0.06 0.06 0.07

 Gulf Coast 1.31 1.91 2.26 2.53 2.55 2.84 2.99 3.12 3.22 3.22 3.23 3.20 3.23

 Light Sweet 0.22 0.31 0.35 0.39 0.42 0.48 0.50 0.51 0.52 0.53 0.54 0.49 0.48

 Light Sour 0.06 0.10 0.11 0.11 0.11 0.14 0.18 0.22 0.24 0.25 0.26 0.28 0.30

 Medium Medium Sour 0.10 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.12 0.12 0.12 0.13 0.14

 Medium Sour 0.02 0.04 0.06 0.06 0.06 0.06 0.07 0.07 0.08 0.08 0.08 0.09 0.09

 Heavy Sweet 0.01 0.02 0.02 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

 Heavy Sour 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02

 Ultra Light Sweet 0.24 0.56 0.80 0.95 0.93 1.10 1.16 1.20 1.24 1.27 1.28 1.30 1.32

 API 50+ 0.64 0.76 0.80 0.87 0.89 0.92 0.94 0.97 0.98 0.93 0.90 0.88 0.87

 Midcontinent 0.60 0.38 0.39 0.38 0.37 0.38 0.43 0.48 0.53 0.57 0.62 0.66 0.70

 Light Sweet 0.16 0.09 0.10 0.10 0.09 0.09 0.10 0.11 0.13 0.14 0.16 0.18 0.20

 Light Sour 0.03 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02

 Medium Medium Sour 0.07 0.05 0.05 0.05 0.05 0.06 0.06 0.07 0.08 0.09 0.10 0.10 0.10

 Medium Sour 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

 Heavy Sweet 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.01 0.01 0.01

 Heavy Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ultra Light Sweet 0.21 0.13 0.13 0.12 0.12 0.12 0.13 0.14 0.14 0.14 0.15 0.16 0.17

 API 50+ 0.12 0.08 0.08 0.08 0.08 0.09 0.11 0.13 0.15 0.16 0.17 0.17 0.18

 Southwest 1.65 1.80 2.08 2.17 2.22 2.50 2.73 2.93 3.09 3.23 3.34 3.44 3.57

 Light Sweet 0.33 0.33 0.40 0.40 0.39 0.54 0.67 0.79 0.86 0.92 0.96 1.00 1.05

 Light Sour 0.13 0.12 0.13 0.12 0.11 0.12 0.13 0.13 0.14 0.14 0.15 0.16 0.16

 Medium Medium Sour 0.09 0.07 0.08 0.08 0.08 0.08 0.08 0.08 0.09 0.09 0.09 0.10 0.10

 Medium Sour 0.34 0.27 0.29 0.28 0.28 0.29 0.30 0.31 0.31 0.32 0.33 0.34 0.34

 Heavy Sweet 0.00 0.00 0.00 0.00 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.02 0.02

 Heavy Sour 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.02

 Ultra Light Sweet 0.65 0.78 0.89 0.97 1.01 1.09 1.13 1.18 1.23 1.27 1.30 1.33 1.37

 API 50+ 0.09 0.22 0.27 0.30 0.34 0.37 0.40 0.42 0.45 0.47 0.48 0.50 0.51

 Rocky Mountain 1.40 1.84 2.21 2.39 2.60 2.82 2.97 3.13 3.25 3.33 3.58 3.81 3.84

 Light Sweet 0.12 0.10 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.09 0.09 0.09 0.09

 Light Sour 0.13 0.15 0.16 0.16 0.17 0.17 0.18 0.18 0.19 0.19 0.19 0.18 0.18

 Medium Medium Sour 0.04 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.04 0.05 0.06 0.08 0.10

 Medium Sour 0.02 0.01 0.02 0.02 0.01 0.02 0.01 0.01 0.01 0.01 0.02 0.04 0.06

 Heavy Sweet 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.17 0.30 0.21

 Heavy Sour 0.06 0.05 0.05 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04

 Ultra Light Sweet 0.98 1.45 1.78 1.96 2.17 2.37 2.52 2.66 2.77 2.85 2.91 2.97 3.04

 API 50+ 0.05 0.05 0.06 0.07 0.07 0.08 0.08 0.08 0.08 0.09 0.09 0.10 0.11

 West Coast, California 0.51 0.55 0.55 0.58 0.59 0.60 0.62 0.63 0.65 0.65 0.66 0.67 0.68

 Lower 48 Offshore 1.37 1.54 1.79 2.28 2.48 2.58 2.54 2.49 2.44 2.39 2.33 2.34 2.28

 Atlantic Medium Medium Sour 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Gulf of Mexico Medium Medium Sour 1.28 1.45 1.70 2.22 2.42 2.53 2.48 2.44 2.39 2.34 2.28 2.29 2.23

 Pacific California 0.09 0.09 0.09 0.06 0.06 0.06 0.06 0.05 0.05 0.05 0.05 0.05 0.05

 Alaska 0.52 0.49 0.45 0.43 0.44 0.45 0.43 0.42 0.40 0.38 0.35 0.34 0.32

 North Slope Offshore Medium Medium Sour 0.00 0.00 0.04 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.06 0.06

 North Slope Onshore Medium Medium Sour 0.50 0.48 0.40 0.35 0.36 0.37 0.35 0.34 0.32 0.30 0.28 0.27 0.25

 South Alaska Medium Medium Sour 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

 Other Crudes Not Listed 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

(million barrels per day)
19

2013 2015 2020 2025

Western Canada

 Production 3,190 3,537 4,090 4,755

 Shipments 3,418 3,781 4,509 5,368

Eastern Canada

 Production 232 227 263 175

 Shipments 232 227 263 175

Total Canada

 Production 3,422 3,764 4,353 4,930

 Shipments 3,650 4,008 4,772 5,543

Canadian Crude Production Forecast, MBPD

Table I-3
20

Company Location Crude

PADD I

Monroe Energy Trainer, PA 190

Philadelphia Energy Philadelphia, PA 355

Phillips 66 Linden, NJ 251

Axeon Specialty Products Paulsboro, NJ 75

PBF Energy Delaware City, DE 190

PBF Energy Paulsboro, NJ 166

American Refining Group Bradford, PA 11

United Warren, PA 70

Ergon Newell, WV 22

1,330

PADD II

Marathon Robinson, IL 225

Countrymark Mt. Vernon, IN 28

Continental Somerset, KY 6

Marathon Catlettsburg, KY 261

Tesoro Mandan, ND 70

Husky Lima, OH 170

Marathon Canton, OH 87

PBF Energy Toledo, OH 175

Exxon Joliet, IL 248

Citgo Lemont, IL 180

WRB Wood River, IL 350

BP Whiting, IN 428

Marathon Detroit, MI 126

Flint Hills Rosemount, MN 320

Northern Tier St. Paul, MN 85

BP-Husky Toledo, OH 160

Calumet Superior, WI 45

Valero Memphis, TN 190

NCRA (CHS) McPherson, KS 88

CVR Energy Coffeyville, KS 125

Holly Frontier El Dorado, KS 140

Holly Frontier Tulsa, OK 166

Valero Ardmore, OK 87

CVR Energy Wynnewood, OK 75

Phillips 66 Ponca City, OK 215

4,049

U.S. Refinery Capacities - 2013

(Unit Capacities in Thousands of Barrels per Stream Day)

Table I-4
21

Company Location Crude

U.S. Refinery Capacities - 2013

(Unit Capacities in Thousands of Barrels per Stream Day)

Table I-4

PADD III

Martin Midstream Smackover, AR 8

Calumet Cotton Valley, LA 14

Calumet Shreveport, LA 60

Calumet Princeton, LA 9

Holly Frontier Artesia, NM 115

Western Gallup, NM 25

Alon Big Spring, TX 70

Delek Tyler, TX 65

Valero Sunray, TX 160

Western El Paso, TX 130

Delek El Dorado, AR 85

Ergon Vicksburg, MS 25

WRB Borger, TX 154

Goodway Atmore 5

Shell Saraland, AL 85

Alon Krotz Springs, LA 83

Exxon/PDVSA Chalmette, LA 195

Motiva Convent, LA 255

Motiva Norco, LA 250

Phillips 66 Belle Chase, LA 260

Placid Port Allen, LA 59

Valero Meraux, LA 140

Hunt Tuscaloosa, AL 40

Exxon Baton Rouge, LA 523

Marathon Garyville, LA 548

Citgo Lake Charles 440

Phillips 66 Westlake, LA 252

Shell St. Rose, LA 46

Valero Norco, LA 210

Chevron Pascagoula, MS 360

Hunt Sandersville, MS 13

Marathon Texas City, TX 475

Exxon Beaumont, TX 359

Marathon Texas City, TX 87

Petrobras Pasadena, TX 107

Valero Houston, TX 90

Lyondell Houston, TX 302

Shell Deer Park, TX 340

Exxon Baytown, TX 584

Motiva Port Arthur, TX 620

Phillips 66 Sweeny, TX 260

Total Port Arthur, TX 245

Valero Port Arthur, TX 415

Valero Texas City, TX 233

Blue Dolphin Energy Nixon, TX 12

Calumet San Antonio, TX 15

Flint Hills Corpus Christi, TX 293

Citgo Corpus Christi, TX 165

Valero Corpus Christi, TX 205

Valero Three Rivers, TX 95

9,584
22

Company Location Crude

U.S. Refinery Capacities - 2013

(Unit Capacities in Thousands of Barrels per Stream Day)

Table I-4

PADD IV

Suncor Commerce City, CO 110

Chevron Salt Lake City, UT 49

Big West Salt Lake City, UT 30

Holly Frontier Salt Lake City, UT 26

Silver Eagle Salt Lake City, UT 6

Tesoro Salt Lake City, UT 60

Black Elk Newcastle 15

Silver Eagle Salt Lake City, UT 3

Sinclair Casper, WY 26

Montana Ref. Great Falls, MT 11

CHS Laurel, MT 61

Exxon Billings, MT 62

Phillips 66 Billings, MT 63

Holly Frontier Cheyenne, WY 52

Sinclair Rawlins, WY 85

658

PADD V

Phillips 66 Ferndale, WA 108

Tesoro Anacortes, WA 125

BP Blaine, WA 234

Trailstone Tacoma, WA 42

Shell Anacortes, WA 149

Chevron El Segundo, CA 291

Chevron Richmond, CA 257

Exxon Los Angeles, CA 156

Greka Energy Santa Maria, CA 10

Kern Bakersfield, CA 27

Phillips 66 Santa Maria/Rodeo, CA 128

Phillips 66 Carson/Wilmington, CA 147

Shell Martinez, CA 158

San Joaquin Refining Bakersfield, CA 25

Tesoro Martinez, CA 170

Tesoro Los Angeles, CA 107

Tesoro Los Angeles, CA 276

Valero Benicia, CA 135

Valero Los Angeles, CA 87

Lunday-Thagard Los Angeles, CA 10

Arctic Slope North Pole, AK 23

Arctic Slope Valdez, AK 60

BP Prudhoe Bay, AK 13

ConocoPhillips Prudhoe Bay, AK 16

Flint Hills North Pole, AK 87

Tesoro Kenai, AK 72

Chevron Kapolei, HI 57

Par Petroleum Kapolei, HI 95

3,063
23

Expected

State Company Location Compl'n Heavy Medium Lt. Sour Lt. Swt. Total

PADD I

NJ Axeon Specialty Paulsboro 2014 (35) 35 0

(35) 0 0 35 0

PADD II

OH Marathon Canton 2014 25 25

ND Calumet / MDU Resources Dickinson 2014 20 20

KY Marathon Catlettsburg 2015 35 35

IL Marathon Robinson 2016 30 30

OH Husky Lima 2017 40 (40) 0

KS NCRA McPherson 2018 30 (15) 15

70 0 0 55 125

PADD III

TX Calumet San Antonio 2014 3 3

TX Flint Hills Corpus Christi 2014 (30) 30 0

LA Marathon Garyville 2014 10 5 5 20

TX Delek Tyler 2015 12 12

TX Valero Energy Corpus Christi 2015 70 70

TX Valero Energy Houston 2015 90 90

TX Valero Energy McKee 2015 25 25

TX Marathon Galveston Bay 2015 (25) 25 0

10 (20) (25) 255 220

PADD IV

UT Tesoro Salt Lake City 2015 4 4

UT HollyFrontier Woods Cross 2015 14 14

MT Calumet Great Falls 2015 10 10

UT HollyFrontier Woods Cross 2017 15 15

MT CHS Laurel 2019 25 25

10 0 0 58 68

PADD V

CA Chevron Richmond 2017 20 (20) 0

AK AIDEA Mustang 2018 3 3

20 (17) 0 0 3

 TOTAL 75 (37) (25) 403 416

Projected U.S. Refinery Projects Through 2019

Crude Capacity Changes

(Unit Capacities in Thousands of Barrels per Stream Day)

Change to Crude Capacity

Table I-5
24

PADD I PADD II PADD III PADD IV PADD V U.S.

Feedstocks

Crude 1,022 3,353 7,829 569 2,303 15,076

Other Feedstocks1 188 669 1,442 53 591 2,943

1,210 4,022 9,271 622 2,894 18,019

Products

Propane/Propylene 34 107 369 9 45 564

Normal Butane 2 4 48 2 8 64

Isobutane -1 -1 -1 -1 -1 -5

Gasoline 584 2,319 4,216 320 1,600 9,038

Jet/Kerosene 73 223 760 26 414 1,496

Distillate 361 1,013 2,721 194 568 4,857

Resid/Asphalt 116 195 351 44 130 836

Other2 92 365 1,434 52 313 2,256

1,261 4,225 9,898 646 3,077 19,106

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table I-6

2013 Charge and Yield Data by PADDs

Thousands of Barrel per Day
25

TOTAL DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.70 0.72 0.70 0.69 0.68 0.68 0.67 0.66 0.65 0.65 0.64 0.63 0.62

02_Middle_Atlantic 1.80 1.81 1.80 1.79 1.76 1.73 1.72 1.70 1.68 1.66 1.64 1.62 1.60

03_East_North_Central 2.30 2.31 2.31 2.32 2.29 2.27 2.25 2.23 2.21 2.19 2.16 2.14 2.11

04_West_North_Central 1.39 1.40 1.40 1.41 1.41 1.40 1.40 1.39 1.38 1.37 1.36 1.35 1.34

05_South_Atlantic 2.81 2.83 2.83 2.84 2.83 2.83 2.81 2.80 2.79 2.79 2.78 2.76 2.75

06_East_South_Central 1.18 1.18 1.18 1.19 1.18 1.17 1.17 1.16 1.15 1.15 1.14 1.13 1.12

07_West_South_Central 4.98 4.91 5.01 5.09 5.20 5.35 5.42 5.49 5.53 5.60 5.68 5.72 5.75

08_Mountain 1.16 1.17 1.18 1.18 1.22 1.25 1.27 1.28 1.28 1.28 1.29 1.29 1.29

09_Pacific 2.52 2.51 2.51 2.52 2.50 2.51 2.53 2.52 2.52 2.51 2.50 2.49 2.48

US 18.83 18.85 18.91 19.04 19.08 19.18 19.24 19.24 19.20 19.19 19.19 19.14 19.06

MOGAS DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.41 0.40 0.40 0.40 0.39 0.38 0.37 0.36 0.36 0.35 0.34 0.33 0.33

02_Middle_Atlantic 0.94 0.94 0.93 0.93 0.90 0.86 0.85 0.83 0.81 0.80 0.78 0.76 0.74

03_East_North_Central 1.26 1.26 1.26 1.25 1.21 1.17 1.16 1.13 1.11 1.09 1.07 1.04 1.02

04_West_North_Central 0.66 0.66 0.66 0.66 0.64 0.62 0.61 0.60 0.59 0.58 0.57 0.56 0.55

05_South_Atlantic 1.80 1.79 1.79 1.78 1.77 1.75 1.73 1.71 1.69 1.67 1.64 1.62 1.59

06_East_South_Central 0.62 0.61 0.61 0.61 0.60 0.58 0.57 0.56 0.55 0.54 0.53 0.52 0.51

07_West_South_Central 1.17 1.17 1.16 1.16 1.15 1.14 1.13 1.12 1.11 1.10 1.08 1.07 1.05

08_Mountain 0.61 0.61 0.61 0.60 0.60 0.60 0.60 0.59 0.59 0.58 0.58 0.57 0.57

09_Pacific 1.26 1.25 1.25 1.25 1.23 1.22 1.20 1.19 1.17 1.15 1.13 1.12 1.10

US 8.71 8.69 8.68 8.65 8.49 8.32 8.22 8.12 8.00 7.86 7.73 7.59 7.45

DISTILLATE DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.20 0.21 0.20 0.19 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20

02_Middle_Atlantic 0.43 0.46 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.43 0.43

03_East_North_Central 0.51 0.54 0.54 0.55 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56

04_West_North_Central 0.42 0.44 0.44 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45

05_South_Atlantic 0.55 0.58 0.58 0.60 0.60 0.61 0.61 0.61 0.61 0.61 0.62 0.62 0.62

06_East_South_Central 0.29 0.31 0.31 0.32 0.32 0.33 0.33 0.33 0.33 0.33 0.33 0.34 0.34

07_West_South_Central 0.70 0.74 0.75 0.76 0.78 0.80 0.81 0.81 0.81 0.81 0.82 0.82 0.82

08_Mountain 0.33 0.35 0.35 0.36 0.37 0.37 0.37 0.37 0.37 0.37 0.38 0.38 0.38

09_Pacific 0.43 0.44 0.44 0.45 0.46 0.47 0.47 0.47 0.47 0.47 0.48 0.48 0.48

US 3.88 4.06 4.07 4.13 4.19 4.23 4.25 4.25 4.25 4.26 4.27 4.27 4.27

U.S. Domestic Petroleum Product Demand - Low Production Case

Table I-7

(million barrels per day)
26

U.S. Domestic Petroleum Product Demand - Low Production Case

Table I-7

(million barrels per day)

K-JET DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

02_Middle_Atlantic 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

03_East_North_Central 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14

04_West_North_Central 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

05_South_Atlantic 0.19 0.19 0.19 0.19 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20

06_East_South_Central 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.09 0.09 0.09

07_West_South_Central 0.25 0.25 0.25 0.25 0.25 0.26 0.26 0.26 0.26 0.26 0.26 0.27 0.27

08_Mountain 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

09_Pacific 0.41 0.42 0.42 0.42 0.42 0.43 0.43 0.43 0.43 0.43 0.43 0.43 0.44

US 1.42 1.44 1.43 1.44 1.44 1.45 1.45 1.45 1.46 1.46 1.46 1.47 1.47

RESID DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.01 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

02_Middle_Atlantic 0.05 0.04 0.04 0.04 0.04 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04

03_East_North_Central 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

04_West_North_Central 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

05_South_Atlantic 0.07 0.06 0.05 0.05 0.05 0.06 0.05 0.05 0.05 0.05 0.05 0.05 0.05

06_East_South_Central 0.01 0.01 0.00 0.00 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

07_West_South_Central 0.11 0.09 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08

08_Mountain 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

09_Pacific 0.12 0.10 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09

US 0.38 0.32 0.29 0.28 0.28 0.29 0.27 0.28 0.28 0.28 0.29 0.29 0.29

ALL OTHER DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06

02_Middle_Atlantic 0.20 0.19 0.19 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20

03_East_North_Central 0.37 0.37 0.37 0.37 0.38 0.39 0.39 0.39 0.39 0.39 0.39 0.39 0.39

04_West_North_Central 0.25 0.25 0.24 0.25 0.27 0.28 0.28 0.28 0.28 0.28 0.29 0.29 0.29

05_South_Atlantic 0.20 0.20 0.21 0.21 0.21 0.22 0.23 0.23 0.24 0.26 0.27 0.27 0.28

06_East_South_Central 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.18 0.18 0.18 0.18

07_West_South_Central 2.75 2.67 2.77 2.84 2.94 3.07 3.15 3.23 3.27 3.36 3.44 3.50 3.53

08_Mountain 0.14 0.13 0.13 0.14 0.17 0.20 0.22 0.23 0.24 0.24 0.25 0.25 0.26

09_Pacific 0.30 0.29 0.30 0.31 0.29 0.31 0.34 0.34 0.35 0.36 0.36 0.37 0.38

US 4.45 4.34 4.44 4.54 4.67 4.89 5.04 5.14 5.21 5.33 5.44 5.52 5.58
27

TOTAL DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.70 0.72 0.70 0.70 0.69 0.68 0.67 0.67 0.66 0.66 0.65 0.65 0.64

02_Middle_Atlantic 1.80 1.81 1.78 1.78 1.77 1.74 1.73 1.71 1.69 1.67 1.66 1.64 1.63

03_East_North_Central 2.30 2.31 2.32 2.33 2.30 2.28 2.27 2.24 2.23 2.21 2.20 2.18 2.16

04_West_North_Central 1.39 1.40 1.41 1.43 1.42 1.41 1.41 1.41 1.40 1.40 1.39 1.39 1.38

05_South_Atlantic 2.81 2.83 2.83 2.83 2.84 2.84 2.83 2.82 2.82 2.81 2.81 2.80 2.79

06_East_South_Central 1.18 1.18 1.19 1.20 1.18 1.18 1.18 1.17 1.17 1.17 1.16 1.16 1.15

07_West_South_Central 4.98 4.91 5.09 5.19 5.27 5.43 5.52 5.60 5.65 5.74 5.82 5.88 5.92

08_Mountain 1.16 1.17 1.18 1.19 1.22 1.25 1.28 1.29 1.30 1.30 1.31 1.32 1.32

09_Pacific 2.52 2.51 2.48 2.49 2.51 2.53 2.54 2.55 2.54 2.54 2.54 2.54 2.54

US 18.83 18.85 18.99 19.14 19.19 19.33 19.43 19.46 19.46 19.50 19.54 19.56 19.52

MOGAS DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.41 0.40 0.40 0.40 0.39 0.38 0.37 0.37 0.36 0.36 0.35 0.34 0.34

02_Middle_Atlantic 0.94 0.94 0.93 0.93 0.90 0.87 0.85 0.84 0.82 0.81 0.79 0.78 0.76

03_East_North_Central 1.26 1.26 1.26 1.25 1.22 1.18 1.16 1.14 1.13 1.11 1.09 1.07 1.05

04_West_North_Central 0.66 0.66 0.66 0.66 0.64 0.62 0.62 0.61 0.60 0.59 0.58 0.57 0.56

05_South_Atlantic 1.80 1.79 1.79 1.78 1.77 1.76 1.75 1.73 1.72 1.70 1.68 1.66 1.65

06_East_South_Central 0.62 0.61 0.61 0.61 0.60 0.58 0.58 0.57 0.56 0.55 0.55 0.54 0.53

07_West_South_Central 1.17 1.17 1.16 1.16 1.16 1.15 1.14 1.14 1.13 1.12 1.11 1.10 1.08

08_Mountain 0.61 0.61 0.61 0.60 0.60 0.60 0.60 0.60 0.60 0.60 0.59 0.59 0.58

09_Pacific 1.26 1.25 1.25 1.25 1.24 1.22 1.21 1.20 1.19 1.17 1.16 1.14 1.13

US 8.71 8.69 8.68 8.65 8.51 8.37 8.28 8.20 8.10 8.00 7.89 7.79 7.68

DISTILLATE DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.20 0.21 0.20 0.20 0.20 0.20 0.20 0.20 0.21 0.21 0.21 0.21 0.21

02_Middle_Atlantic 0.43 0.46 0.44 0.44 0.44 0.44 0.45 0.45 0.44 0.44 0.44 0.44 0.44

03_East_North_Central 0.51 0.54 0.54 0.55 0.56 0.56 0.57 0.57 0.57 0.57 0.57 0.58 0.58

04_West_North_Central 0.42 0.43 0.44 0.45 0.45 0.45 0.46 0.46 0.46 0.46 0.47 0.47 0.47

05_South_Atlantic 0.55 0.58 0.58 0.60 0.60 0.61 0.61 0.61 0.61 0.62 0.62 0.62 0.63

06_East_South_Central 0.29 0.31 0.31 0.32 0.32 0.33 0.33 0.34 0.34 0.34 0.34 0.35 0.35

07_West_South_Central 0.70 0.74 0.75 0.77 0.78 0.81 0.82 0.83 0.84 0.85 0.85 0.86 0.87

08_Mountain 0.33 0.35 0.36 0.36 0.36 0.37 0.37 0.37 0.37 0.38 0.38 0.38 0.39

09_Pacific 0.43 0.44 0.44 0.45 0.46 0.47 0.48 0.48 0.48 0.48 0.49 0.49 0.50

US 3.88 4.06 4.07 4.14 4.18 4.25 4.29 4.31 4.33 4.35 4.38 4.41 4.42

U.S. Domestic Petroleum Product Demand - High Production Case

Table I-8

(million barrels per day)
28

U.S. Domestic Petroleum Product Demand - High Production Case

Table I-8

(million barrels per day)

K-JET DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

02_Middle_Atlantic 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

03_East_North_Central 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14 0.14

04_West_North_Central 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

05_South_Atlantic 0.19 0.19 0.19 0.19 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20 0.20

06_East_South_Central 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.09 0.09 0.09 0.09

07_West_South_Central 0.25 0.25 0.25 0.25 0.25 0.26 0.26 0.26 0.26 0.26 0.26 0.27 0.27

08_Mountain 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

09_Pacific 0.41 0.42 0.42 0.42 0.42 0.43 0.43 0.43 0.43 0.43 0.43 0.44 0.44

US 1.42 1.44 1.43 1.44 1.44 1.45 1.45 1.45 1.46 1.46 1.47 1.47 1.47

RESID DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.01 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

02_Middle_Atlantic 0.05 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

03_East_North_Central 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

04_West_North_Central 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

05_South_Atlantic 0.07 0.06 0.05 0.05 0.06 0.06 0.05 0.05 0.05 0.05 0.05 0.05 0.05

06_East_South_Central 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

07_West_South_Central 0.11 0.09 0.08 0.08 0.07 0.08 0.07 0.07 0.07 0.07 0.07 0.07 0.07

08_Mountain 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

09_Pacific 0.12 0.10 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09

US 0.38 0.32 0.29 0.29 0.29 0.30 0.27 0.28 0.28 0.28 0.28 0.29 0.29

ALL OTHER DEMAND

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

01_New_England 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06

02_Middle_Atlantic 0.20 0.19 0.17 0.17 0.20 0.20 0.21 0.20 0.20 0.19 0.20 0.19 0.20

03_East_North_Central 0.37 0.37 0.38 0.38 0.39 0.39 0.39 0.39 0.39 0.39 0.39 0.39 0.39

04_West_North_Central 0.25 0.25 0.26 0.27 0.27 0.28 0.29 0.29 0.29 0.29 0.29 0.29 0.29

05_South_Atlantic 0.20 0.20 0.20 0.21 0.21 0.22 0.23 0.23 0.24 0.25 0.26 0.26 0.27

06_East_South_Central 0.17 0.17 0.18 0.18 0.17 0.17 0.18 0.18 0.18 0.18 0.18 0.18 0.18

07_West_South_Central 2.75 2.67 2.84 2.93 3.00 3.13 3.22 3.30 3.35 3.44 3.52 3.59 3.62

08_Mountain 0.14 0.13 0.14 0.15 0.17 0.19 0.22 0.24 0.24 0.25 0.25 0.26 0.26

09_Pacific 0.30 0.29 0.27 0.28 0.29 0.32 0.33 0.34 0.35 0.36 0.37 0.37 0.38

US 4.45 4.34 4.51 4.62 4.76 4.97 5.13 5.23 5.29 5.41 5.52 5.60 5.66
29

Percent

of Region

PADD I

01_New_England 100.0%

02_Middle_Atlantic 100.0%

05_South_Atlantic 100.0%

PADD II

03_East_North_Central 100.0%

04_West_North_Central 100.0%

06_East_South_Central 58.2%

07_West_South_Central 10.2%

PADD III

06_East_South_Central 41.8%

07_West_South_Central 89.8%

08_Mountain 9.1%

PADD IV

08_Mountain 49.7%

PADD V

08_Mountain 41.2%

09_Pacific 100.0%

Census Regions to PADD Conversion

Table I-9
30

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Gasoline

PADD I 3,139 3,132 3,128 3,116 3,054 2,985 2,949 2,909 2,865 2,812 2,763 2,713 2,661

PADD II 2,402 2,396 2,393 2,383 2,318 2,250 2,216 2,179 2,140 2,101 2,059 2,016 1,971

PADD III 1,361 1,359 1,357 1,352 1,342 1,324 1,312 1,299 1,284 1,266 1,248 1,229 1,207

PADD IV 302 302 301 300 299 298 297 295 293 290 287 284 281

PADD V 1,505 1,502 1,500 1,494 1,481 1,463 1,450 1,434 1,417 1,393 1,372 1,351 1,329

 U.S. 8,710 8,690 8,680 8,646 8,494 8,320 8,223 8,116 7,999 7,863 7,730 7,594 7,449

Jet/Kero

PADD I 404 410 408 410 409 407 407 407 407 408 408 409 409

PADD II 267 271 270 271 270 270 270 270 269 269 269 269 269

PADD III 264 268 267 268 271 273 275 276 278 279 281 282 283

PADD IV 38 39 39 39 39 39 39 39 40 40 40 40 40

PADD V 447 453 451 453 456 458 460 461 463 465 466 468 470

 U.S. 1,419 1,440 1,434 1,441 1,444 1,448 1,451 1,454 1,457 1,460 1,464 1,468 1,472

Distillate

PADD I 1,187 1,251 1,226 1,230 1,242 1,252 1,256 1,253 1,251 1,250 1,250 1,249 1,246

PADD II 1,174 1,228 1,239 1,264 1,276 1,286 1,290 1,290 1,289 1,289 1,291 1,292 1,290

PADD III 786 824 835 853 874 893 900 902 902 905 908 911 911

PADD IV 167 174 176 180 182 183 184 185 185 186 187 188 188

PADD V 565 584 590 602 612 620 623 624 625 627 631 634 636

 U.S. 3,878 4,061 4,066 4,129 4,185 4,234 4,253 4,254 4,252 4,257 4,268 4,275 4,272

Resid

PADD I 120 118 106 104 108 113 100 102 103 105 105 106 107

PADD II 36 15 13 13 13 14 14 14 15 15 16 16 16

PADD III 102 82 72 70 66 69 62 64 66 68 69 70 71

PADD IV 2 2 2 2 2 2 2 2 2 2 2 2 2

PADD V 120 105 95 93 92 92 93 93 93 94 94 94 95

 U.S. 380 321 288 281 280 290 270 275 280 284 286 288 291

Other

PADD I 460 453 455 465 463 477 488 495 502 518 528 537 544

PADD II 1,003 990 994 1,010 1,043 1,073 1,090 1,103 1,110 1,121 1,131 1,138 1,143

PADD III 2,559 2,482 2,568 2,638 2,727 2,848 2,926 2,993 3,034 3,111 3,192 3,241 3,276

PADD IV 68 66 67 69 84 98 110 114 117 121 123 127 129

PADD V 356 348 356 363 356 393 427 437 446 458 465 474 484

 U.S. 4,445 4,339 4,441 4,545 4,674 4,888 5,040 5,143 5,209 5,330 5,440 5,518 5,576

Total

PADD I 5,309 5,363 5,324 5,325 5,276 5,234 5,200 5,166 5,128 5,092 5,054 5,014 4,967

PADD II 4,881 4,900 4,909 4,941 4,920 4,892 4,879 4,856 4,823 4,796 4,766 4,732 4,690

PADD III 5,072 5,014 5,099 5,181 5,278 5,408 5,474 5,534 5,564 5,630 5,698 5,733 5,749

PADD IV 577 582 585 589 606 619 632 635 637 638 640 641 640

PADD V 2,993 2,992 2,992 3,006 2,997 3,026 3,052 3,050 3,045 3,038 3,028 3,022 3,013

 U.S. 18,833 18,851 18,909 19,042 19,077 19,180 19,237 19,241 19,196 19,193 19,187 19,142 19,060

By PADDs - MBPD

EIA Product Demand - Low Production Case

Table I-10
31

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Gasoline

PADD I 3,139 3,132 3,128 3,117 3,060 3,003 2,972 2,938 2,902 2,860 2,822 2,783 2,742

PADD II 2,402 2,396 2,393 2,384 2,322 2,262 2,231 2,199 2,167 2,132 2,098 2,064 2,027

PADD III 1,361 1,359 1,358 1,353 1,344 1,332 1,323 1,313 1,303 1,290 1,278 1,264 1,249

PADD IV 302 302 301 300 300 300 299 299 297 296 295 293 291

PADD V 1,505 1,502 1,500 1,494 1,484 1,472 1,460 1,448 1,434 1,417 1,402 1,387 1,371

 U.S. 8,710 8,690 8,680 8,649 8,509 8,369 8,285 8,196 8,103 7,996 7,894 7,791 7,679

Jet/Kero

PADD I 404 410 408 410 409 408 408 407 408 408 408 409 410

PADD II 267 271 270 271 271 270 270 270 269 269 269 269 269

PADD III 264 268 267 268 271 273 275 276 278 279 281 282 283

PADD IV 38 39 39 39 39 39 39 39 40 40 40 40 40

PADD V 447 453 451 453 456 459 460 462 463 465 467 468 470

 U.S. 1,419 1,440 1,434 1,441 1,445 1,449 1,452 1,455 1,458 1,461 1,465 1,469 1,473

Distillate

PADD I 1,187 1,251 1,227 1,232 1,242 1,254 1,260 1,262 1,263 1,266 1,271 1,277 1,278

PADD II 1,174 1,228 1,239 1,265 1,275 1,293 1,302 1,308 1,312 1,317 1,325 1,333 1,335

PADD III 786 824 835 854 874 902 915 923 929 936 946 955 959

PADD IV 167 174 177 180 181 182 184 185 186 188 189 191 192

PADD V 565 584 590 604 611 623 629 633 636 640 645 651 655

 U.S. 3,878 4,061 4,068 4,135 4,182 4,254 4,290 4,311 4,327 4,347 4,377 4,407 4,420

Resid

PADD I 120 118 111 110 112 115 102 104 105 105 106 107 106

PADD II 36 15 14 14 14 15 14 14 15 15 15 15 15

PADD III 102 82 74 72 70 71 63 64 65 66 67 68 68

PADD IV 2 2 2 2 2 2 2 2 2 2 2 2 2

PADD V 120 105 95 93 92 93 93 93 94 94 95 95 95

 U.S. 380 321 294 291 290 295 274 277 280 281 285 287 287

Other

PADD I 460 453 433 435 472 483 491 489 492 502 511 517 527

PADD II 1,003 990 1,032 1,051 1,061 1,087 1,109 1,114 1,119 1,135 1,147 1,155 1,159

PADD III 2,559 2,482 2,643 2,725 2,779 2,902 2,989 3,063 3,107 3,188 3,264 3,320 3,357

PADD IV 68 66 71 73 84 97 111 117 120 122 125 129 132

PADD V 356 348 331 336 363 396 426 442 449 464 474 480 489

 U.S. 4,445 4,339 4,510 4,620 4,759 4,966 5,126 5,225 5,289 5,413 5,521 5,601 5,663

Total

PADD I 5,309 5,363 5,308 5,304 5,294 5,262 5,233 5,200 5,170 5,141 5,119 5,093 5,063

PADD II 4,881 4,899 4,948 4,985 4,943 4,926 4,926 4,905 4,883 4,869 4,855 4,837 4,806

PADD III 5,072 5,014 5,176 5,272 5,336 5,481 5,564 5,640 5,682 5,760 5,835 5,889 5,917

PADD IV 577 582 589 594 605 620 636 642 645 647 651 655 656

PADD V 2,993 2,992 2,967 2,981 3,007 3,043 3,068 3,077 3,076 3,080 3,082 3,082 3,080

 U.S. 18,833 18,850 18,988 19,136 19,185 19,332 19,427 19,464 19,457 19,497 19,543 19,556 19,522

EIA Product Demand - High Production Case

By PADDs - MBPD

Table I-11
32

High

Year Actual Reference Resource

2000 1,911

2001 1,868

2002 1,880

2003 1,719

2004 1,809

2005 1,717

2006 1,739

2007 1,783

2008 1,784

2009 1,910

2010 2,074

2011 2,216

2012 2,408

2013 2,606

2014 2,962 2,962 2,962

2015 3,350 3,467

2016 3,680 3,900

2017 3,900 4,320

2018 4,080 4,780

2019 4,163 5,123

2020 4,177 5,357

2021 4,167 5,480

2022 4,146 5,550

2023 4,104 5,600

2024 4,043 5,630

2025 3,962 5,645

Forecasts

Table I-12

TM&C Natural Gas Liquids Forecast

MBPD

0

1,000

2,000

3,000

4,000

5,000

6,000

2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

MBPD 

U.S. NGL Forecasts

Historical Reference Case High Resource Case
33

Pipelines

Company Pipeline From To Date MBPD

Enbridge Line 9 Reversal North Montreal, QC 4Q14 300

Enbridge Alb. Clipper Hardisty, AB Superior, WI 4Q14 120

Enbridge Alb. Clipper Hardisty, AB Superior, WI 3Q15 230

• Other logistic investments necessary to ensure crude flows will be identified in study.

• Sufficient exit pipeline capacities out of Bakken, Niobrara, and Permian fields.

• No new pipelines to PADD I or PADD V will be constructed.

• No pipeline constraints into or out of Cushing, OK.

Canadian Production Forecast

2013 2015 2020 2025

Production 3,190 3,537 4,090 4,755

Shipments 3,418 3,781 4,509 5,368

Production 232 227 263 175

Shipments 232 227 263 175

Production 3,422 3,764 4,353 4,930

Shipments 3,650 4,008 4,772 5,543

• Canadian rail load capacity and shipments as per CAPP forecast.

Refining

• All refineries currently operating in the U.S. and Canada will continue to operate. See Appendix Table 1 for a

 listing of all refineries.

• 17 refining expansions in the U.S. will be completed by 2019 which will add 416 MBPD of additional capacity.

• One refining expansion in Canada will be completed by 2019 which will add 50 MBPD of additional capacity.

• Condensate/crude splitter capacity at:

o 2013 75 MBPD

o 2015 175 MBPD

o 2020 325 MBPD

o 2025 575 MBPD

• PADD crude utilization rates as follows:

Table I-13

Other Refining and Logistic Assumptions

Western Canada

Eastern Canada

Total Canada

Major North American Pipeline Assumptions

Lines Assumed to be in Service by 2025

Canadian Crude Production Forecast, MBPD
34

Table I-13

Other Refining and Logistic Assumptions

Actual

2013 2015 2020 2025 2015 2020 2025

PADD I 76.9 81 82 82 79 79 79

PADD II 82.8 89 91 91 87 88 88

PADD III 81 85 86.3 86.5 83 84.5 84.7

PADD IV 86.5 90 91.5 91.5 88 89 89

PADD V 73.9 77.5 81 82 75.5 78 78

• New splitter capacity to be operated at 90% utilization.

• Investment in additional crude processing capacity or conversion of heavy crude refineries to light crude

 will be made as required and economic in High Production Base Case (Export Limited) to balance crude

 supply and demand.

U.S. Crude Export Policy

• U.S. crude exports to Canada in all cases fixed at:

o 2013 134 MPBD

o 2014 324

o 2015 357

o 2016 407

o 2017 443

o 2018 479

o 2019 514

o 2020 550

• Stabilized condensate (≥50° API) exports to be allowed.

• No exports of stabilized crude (<50° API) to be allowed in Base Case.

• ANS exports to be allowed using U.S. flagged vessels.

Other

• Inter-PADD movements into PADDs I and V will be set by rail offloading limitations.

• No substantive change in Jones Act shipping regulations.

• California Low Carbon Fuel Standard (LCFS) will not restrict crude imports or other movements in the state.

• No minimum structural crude imports.

Low Production Case High Product Export Case

PADD Utilization Rates

(Percent of Crude Capacity)
35

Number Tab Table Name

II-1 2013 Crude Oil Supply and Demand Balance - 2013

II-2 2015 Crude Oil Supply and Demand Balance - 2015

II-3 2020 Crude Oil Supply and Demand Balance - 2020

II-4 2025 Crude Oil Supply and Demand Balance - 2025

II-5 Capacities U.S. and Canadian Distillation Capacities

II-6 Utilizations U.S. and Canadian Utilization Rates

II-7 PI Products Total PADD I Charge and Yield Data

II-8 PII Products Total PADD II Charge and Yield Data

II-9 PIII Products Total PADD III Charge and Yield Data

II-10 PIV Products Total PADD IV Charge and Yield Data

II-11 PV Products Total PADD V Charge and Yield Data

II-12 US Products Total U.S. Charge and Yield Data

II-13 PI Balance PADD I Refinery Product Supply and Demand Balance

II-14 PII Balance PADD II Refinery Product Supply and Demand Balance

II-15 PIII Balance PADD III Refinery Product Supply and Demand Balance

II-16 PIV Balance PADD IV Refinery Product Supply and Demand Balance

II-17 PV Balance PADD V Refinery Product Supply and Demand Balance

II-18 US Balance U.S. Product Supply and Demand Balance

II-19 Crude Flows Crude Oil Flows

II-20 Crude Logistics Required Crude Oil Logistic Improvements

II-21 Gasoline Gasoline Supply and Demand Balance

II-22 Jet-Kero Jet/Kerosene Supply and Demand Balance

II-23 Distillate Distillate Supply and Demand Balance

II-24 Resid Residual Fuel Supply and Demand Balance

II-25 Other Other Products Supply and Demand Balance

II-26 Total Total U.S. Refined Products Supply and Demand Balance

II-27 Crude Exports U.S. and Canadian Crude Oil Exports

II-28 Product Exports U.S. Product Exports

II-29 Prices Crude Price Forecast - Low Production Case

Implications of Increasing U.S. Light Tight Oil Production

Low Production Crude Slate for Base and Export Cases
36

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 5 5

 Light Sour (API 35 - <40) 11 11

 Medium Medium Sour (API 27 - <35) 26 26

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 30 18 12

 Lease Condensate (API >=50) 28 15 13

101

Gulf Coast

 Light Sweet (API 35 - <40) 223 223

 Light Sour (API 35 - <40) 64 64

 Medium Medium Sour (API 27 - <35) 98 98

 Medium Sour (API 27 - <35) 17 17

 Heavy Sweet (API <27) 14 14

 Heavy Sour (API <27) 18 18

 Ultra Light Sweet (API 40 - <50) 238 10 228

 Lease Condensate (API >=50) 639 15 532 68 25

1,312

Midcontinent

 Light Sweet (API 35 - <40) 154 154

 Light Sour (API 35 - <40) 26 26

 Medium Medium Sour (API 27 - <35) 73 73

 Medium Sour (API 27 - <35) 13 13

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 2 2

 Ultra Light Sweet (API 40 - <50) 205 205

 Lease Condensate (API >=50) 122 122

599

Southwest

 Light Sweet (API 35 - <40) 332 225 107

 Light Sour (API 35 - <40) 124 75 49

 Medium Medium Sour (API 27 - <35) 93 93

 Medium Sour (API 27 - <35) 341 50 291

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 14 14

 Ultra Light Sweet (API 40 - <50) 647 647

 Lease Condensate (API >=50) 91 91

1,646

Rocky Mountains

 Light Sweet (API 35 - <40) 121 21 75 25

 Light Sour (API 35 - <40) 133 58 75

 Medium Medium Sour (API 27 - <35) 35 35

 Medium Sour (API 27 - <35) 16 16

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 56 56

 Ultra Light Sweet (API 40 - <50) 980 168 438 176 90 108

 Lease Condensate (API >=50) 54 49 5

1,399

West Coast, California

 West Coast, California 513 513

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 1,284 1,284

 Pacific California 90 90

1,374

Alaska

 North Slope Offshore Medium Medium 0

 North Slope Onshore Medium Medium 500 500

 South Alaska Medium Medium Sour 15 15

515

Total U.S. 7,459 231 1,578 3,925 316 1,208 68 0 0 0 0 133 0

Western Canada

 Condensate 0

 Super Light 52 16 3 0 0 11 21

 Light Sweet 766 382 8 48 57 29 243

 Light Sour 245 4 78 3 8 52 101

 Medium 491 65 200 5 11 26 183

 Heavy 1,864 25 1,070 166 187 51 300 65

3,418

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 232 103 129

 Light Sour 0

 Medium 0

 Heavy 0

232

Foreign Imports

 Condensate 7 5 0 3 0

 Super Light 68 39 0 19 10

 Light Sweet 942 329 1 166 100 347

 Light Sour 1,030 87 32 604 262 1 45

 Medium 1,393 49 8 964 327 45

 Heavy 2,248 68 2 1,899 198 80

5,689

Total Supply 16,798 1,022 3,354 7,761 569 2,303 68 0 0 1 613 1,108 0

Table II-1

EIA Low Production Crude Slate for Base and Export Cases - MPBD

Crude Oil Supply and Demand Balance - 2013

U.S. Canada
37

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 3 3

 Light Sour (API 35 - <40) 9 9

 Medium Medium Sour (API 27 - <35) 16 16

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 22 18 4

 Lease Condensate (API >=50) 24 15 9

74

Gulf Coast

 Light Sweet (API 35 - <40) 402 402

 Light Sour (API 35 - <40) 94 94

 Medium Medium Sour (API 27 - <35) 111 111

 Medium Sour (API 27 - <35) 42 42

 Heavy Sweet (API <27) 16 16

 Heavy Sour (API <27) 20 20

 Ultra Light Sweet (API 40 - <50) 798 10 20 718 50

 Lease Condensate (API >=50) 736 15 589 108 25

2,221

Midcontinent

 Light Sweet (API 35 - <40) 99 99

 Light Sour (API 35 - <40) 18 18

 Medium Medium Sour (API 27 - <35) 54 54

 Medium Sour (API 27 - <35) 9 9

 Heavy Sweet (API <27) 2 2

 Heavy Sour (API <27) 2 2

 Ultra Light Sweet (API 40 - <50) 128 128

 Lease Condensate (API >=50) 87 87

399

Southwest

 Light Sweet (API 35 - <40) 381 381

 Light Sour (API 35 - <40) 130 130

 Medium Medium Sour (API 27 - <35) 88 88

 Medium Sour (API 27 - <35) 308 50 258

 Heavy Sweet (API <27) 6 6

 Heavy Sour (API <27) 12 12

 Ultra Light Sweet (API 40 - <50) 890 393 497

 Lease Condensate (API >=50) 253 253

2,068

Rocky Mountains

 Light Sweet (API 35 - <40) 106 61 45

 Light Sour (API 35 - <40) 158 133 25

 Medium Medium Sour (API 27 - <35) 31 31

 Medium Sour (API 27 - <35) 13 13

 Heavy Sweet (API <27) 2 2

 Heavy Sour (API <27) 54 54

 Ultra Light Sweet (API 40 - <50) 1,641 458 465 176 210 332

 Lease Condensate (API >=50) 54 49 5

2,060

West Coast, California

 West Coast, California 530 530

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 1,697 1,697

 Pacific California 90 90

1,787

Alaska

 North Slope Offshore Medium Medium 44 44

 North Slope Onshore Medium Medium 397 397

 South Alaska Medium Medium Sour 9 9

450

Total U.S. 9,588 519 2,119 4,804 352 1,280 158 0 0 0 0 357 0

Western Canada

 Condensate 0

 Super Light 54 16 5 0 0 11 21

 Light Sweet 800 210 0 59 57 29 445

 Light Sour 255 4 90 0 8 52 101

 Medium 519 65 228 5 11 26 183

 Heavy 2,153 25 1,008 529 175 51 300 65

3,781

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 227 98 129

 Light Sour 0

 Medium 0

 Heavy 0

227

Foreign Imports

 Condensate 0

 Super Light 0

 Light Sweet 257 186 71

 Light Sour 911 95 489 327

 Medium 1,385 49 964 327 45

 Heavy 1,696 20 1,459 171 46

4,249

Total Supply 17,845 1,077 3,659 8,250 605 2,374 158 0 0 0 613 1,108 0

Table II-2

EIA Low Production Crude Slate for Base and Export Cases - MPBD

Crude Oil Supply and Demand Balance - 2015

U.S. Canada
38

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 1 1

 Light Sour (API 35 - <40) 8 8

 Medium Medium Sour (API 27 - <35) 7 7

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 17 17

 Lease Condensate (API >=50) 30 15 15

64

Gulf Coast

 Light Sweet (API 35 - <40) 351 351

 Light Sour (API 35 - <40) 151 151

 Medium Medium Sour (API 27 - <35) 118 118

 Medium Sour (API 27 - <35) 65 65

 Heavy Sweet (API <27) 14 14

 Heavy Sour (API <27) 20 20

 Ultra Light Sweet (API 40 - <50) 1,066 11 20 945 90

 Lease Condensate (API >=50) 593 15 381 172 25

2,376

Midcontinent

 Light Sweet (API 35 - <40) 121 121

 Light Sour (API 35 - <40) 20 20

 Medium Medium Sour (API 27 - <35) 70 70

 Medium Sour (API 27 - <35) 9 9

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 2 2

 Ultra Light Sweet (API 40 - <50) 110 110

 Lease Condensate (API >=50) 64 64

398

Southwest

 Light Sweet (API 35 - <40) 397 150 247

 Light Sour (API 35 - <40) 149 149

 Medium Medium Sour (API 27 - <35) 92 92

 Medium Sour (API 27 - <35) 326 50 276

 Heavy Sweet (API <27) 12 12

 Heavy Sour (API <27) 14 14

 Ultra Light Sweet (API 40 - <50) 1,051 674 377

 Lease Condensate (API >=50) 348 348

2,387

Rocky Mountains

 Light Sweet (API 35 - <40) 107 96 11

 Light Sour (API 35 - <40) 186 133 53

 Medium Medium Sour (API 27 - <35) 40 40

 Medium Sour (API 27 - <35) 15 15

 Heavy Sweet (API <27) 4 4

 Heavy Sour (API <27) 44 44

 Ultra Light Sweet (API 40 - <50) 2,061 691 315 225 305 525

 Lease Condensate (API >=50) 71 66 5

2,528

West Coast, California

 West Coast, California 594 594

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 2,234 2,234

 Pacific California 54 54

2,288

Alaska

 North Slope Offshore Medium Medium 72 72

 North Slope Onshore Medium Medium 340 340

 South Alaska Medium Medium Sour 6 6

418

Total U.S. 11,054 750 1,933 5,790 397 1,372 262 0 0 0 0 550 0

Western Canada

 Condensate 0

 Super Light 54 16 5 0 0 11 21

 Light Sweet 788 432 8 75 57 22 195

 Light Sour 250 4 82 3 8 52 101

 Medium 546 65 200 60 11 26 183

 Heavy 2,871 60 1,064 1,014 162 51 353 167

4,509

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 198 103 95

 Light Sour 0

 Medium 0

 Heavy 65 26 39

263

Foreign Imports

 Condensate 0

 Super Light 10 10

 Light Sweet 150 150

 Light Sour 262 262

 Medium 360 33 327

 Heavy 1,781 19 1,556 165 41

2,563

Total Supply 18,389 1,077 3,715 8,432 653 2,483 262 0 0 0 659 1,108 0

Table II-3

EIA Low Production Crude Slate for Base and Export Cases - MPBD

Crude Oil Supply and Demand Balance - 2020

U.S. Canada
39

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 1 1

 Light Sour (API 35 - <40) 9 9

 Medium Medium Sour (API 27 - <35) 3 3

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 15 15

 Lease Condensate (API >=50) 30 15 15

58

Gulf Coast

 Light Sweet (API 35 - <40) 335 335

 Light Sour (API 35 - <40) 148 148

 Medium Medium Sour (API 27 - <35) 126 126

 Medium Sour (API 27 - <35) 43 43

 Heavy Sweet (API <27) 15 15

 Heavy Sour (API <27) 20 20

 Ultra Light Sweet (API 40 - <50) 1,131 13 20 978 120

 Lease Condensate (API >=50) 459 15 177 242 25

2,275

Midcontinent

 Light Sweet (API 35 - <40) 232 232

 Light Sour (API 35 - <40) 24 24

 Medium Medium Sour (API 27 - <35) 111 111

 Medium Sour (API 27 - <35) 10 10

 Heavy Sweet (API <27) 8 8

 Heavy Sour (API <27) 3 3

 Ultra Light Sweet (API 40 - <50) 117 117

 Lease Condensate (API >=50) 67 67

573

Southwest

 Light Sweet (API 35 - <40) 411 411

 Light Sour (API 35 - <40) 182 182

 Medium Medium Sour (API 27 - <35) 101 101

 Medium Sour (API 27 - <35) 364 50 314

 Heavy Sweet (API <27) 22 22

 Heavy Sour (API <27) 19 19

 Ultra Light Sweet (API 40 - <50) 1,039 732 307

 Lease Condensate (API >=50) 395 395

2,533

Rocky Mountains

 Light Sweet (API 35 - <40) 91 86 5

 Light Sour (API 35 - <40) 182 182

 Medium Medium Sour (API 27 - <35) 58 58

 Medium Sour (API 27 - <35) 57 57

 Heavy Sweet (API <27) 62 62

 Heavy Sour (API <27) 48 48

 Ultra Light Sweet (API 40 - <50) 1,934 730 165 162 352 525

 Lease Condensate (API >=50) 89 84 5

2,521

West Coast, California

 West Coast, California 634 634

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 1,959 1,959

 Pacific California 47 47

2,006

Alaska

 North Slope Offshore Medium Medium 60 60

 North Slope Onshore Medium Medium 253 253

 South Alaska Medium Medium Sour 5 5

317

Total U.S. 10,917 789 1,919 5,550 397 1,350 362 0 0 0 0 550 0

Western Canada

 Condensate 0

 Super Light 57 16 8 0 0 11 21

 Light Sweet 884 406 8 184 57 22 207

 Light Sour 258 4 91 3 8 52 101

 Medium 567 65 200 81 11 26 183

 Heavy 3,602 105 1,049 1,826 53 58 353 158

5,368

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 145 53 92

 Light Sour 0

 Medium 0

 Heavy 30 15 15

175

Foreign Imports

 Condensate 0 0

 Super Light 10 10

 Light Sweet 156 156

 Light Sour 262 262

 Medium 327 327

 Heavy 1,183 30 915 173 65

1,938

Total Supply 18,398 1,077 3,673 8,383 653 2,483 362 0 0 0 659 1,108 0

Table II-4

EIA Low Production Crude Slate for Base and Export Cases - MPBD

Crude Oil Supply and Demand Balance - 2025

U.S. Canada
40

2013 2015 2020 2025

Refining Capacity

PADD I 1,330 1,330 1,330 1,330

PADD II 4,049 4,112 4,174 4,174

PADD III 9,584 9,706 9,804 9,804

PADD IV 658 672 726 726

PADD V 3,063 3,063 3,066 3,066

18,684 18,883 19,100 19,100

Splitter Capacity 75 175 325 575

Hydroskimming Capacity 0 0 0 0

Total U.S. Capacity 18,759 19,058 19,425 19,675

Canadian Refineries

Western Canada 666 666 716 716

Eastern Canada 1,206 1,206 1,206 1,206

1,872 1,872 1,922 1,922

Total U.S. and Canadian Capacity 20,631 20,930 21,347 21,597

Table II-5

U.S. and Canadian Distillation Capacities

MBPSD
41

2013 2015 2020 2025

Refineries

PADD I 76.9 81.0 81.0 81.0

PADD II 82.8 89.0 89.0 88.0

PADD III 81.0 85.0 86.0 85.5

PADD IV 86.5 90.0 90.0 90.0

PADD V 75.2 77.5 81.0 81.0

80.3 84.6 85.7 85.2

Splitters 90.0 90.0 80.6 63.0

Hydroskimmers - - - - - - - - 

Canadian Refineries

Western Canada 92.0 92.0 92.0 92.0

Eastern Canada 92.0 92.0 92.0 92.0

92.0 92.0 92.0 92.0

Table II-6

U.S. and Canadian Utilization Rates

MBPD
42

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 1,022 1,077 1,077 1,077 56 55 55

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 188 193 195 195 5 7 7

1,210 1,270 1,272 1,272 61 62 62

Products

Propane/Propylene 34 38 40 41 4 6 7

Normal Butane 2 5 8 9 3 6 7

Isobutane -1 -1 0 0 0 1 1

Gasoline 584 635 656 655 51 72 71

Jet/Kerosene 73 90 86 83 17 13 10

Distillate 361 357 332 331 -4 -29 -30

Resid/Asphalt 116 105 104 106 -11 -12 -10

Other2 92 91 92 94 -1 0 2

1,261 1,320 1,318 1,318 59 57 57

Splitter Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Yearly Volumes, MBPD Change from 2013, MBPD

Table II-7

PADD I Charge and Yield Data
43

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 3,353 3,659 3,715 3,673 306 362 319

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 669 686 686 683 17 17 14

4,022 4,345 4,401 4,356 323 379 333

Products

Propane/Propylene 107 116 117 115 9 10 8

Normal Butane 4 6 12 12 2 8 8

Isobutane -1 -3 1 2 -2 2 3

Gasoline 2,319 2,498 2,501 2,463 180 183 145

Jet/Kerosene 223 273 289 282 50 66 59

Distillate 1,013 1,069 1,091 1,080 56 78 67

Resid/Asphalt 195 203 168 165 8 -27 -30

Other2 365 381 420 433 16 55 68

4,225 4,545 4,600 4,554 320 376 329

Splitter Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-8

PADD II Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
44

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 7,761 8,250 8,432 8,383 489 670 622

Crude to Splitters 68 158 262 362 90 194 294

Other Feedstocks1 1,442 1,448 1,452 1,460 6 10 18

9,271 9,856 10,146 10,205 585 875 934

Refinery Products

Propane/Propylene 369 382 385 392 13 16 23

Normal Butane 48 72 86 87 24 38 39

Isobutane -1 3 12 7 4 13 8

Gasoline 4,216 4,282 4,323 4,409 66 106 193

Jet/Kerosene 760 825 834 770 65 74 10

Distillate 2,721 2,793 2,866 2,871 72 145 150

Resid/Asphalt 351 372 378 404 21 27 53

Other2 1,366 1,609 1,666 1,572 243 300 206

9,830 10,339 10,549 10,513 509 719 683

Splitter Products

LPG 4 9 15 20 5 10 16

Light Naphtha 17 35 58 80 18 41 63

Naphtha 22 46 77 106 25 55 84

Unfinished Distillate 18 44 73 101 26 55 83

Gas Oil 6 23 40 54 17 34 48

68 158 262 362 90 195 295

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-9

PADD III Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
45

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 569 605 653 653 36 84 84

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 53 55 55 55 2 2 2

622 660 708 708 38 86 86

Products

Propane/Propylene 9 10 11 10 1 2 1

Normal Butane 2 3 4 5 1 2 3

Isobutane -1 0 1 1 1 2 2

Gasoline 320 340 337 342 20 18 22

Jet/Kerosene 26 35 46 58 9 20 32

Distillate 194 200 211 215 6 17 21

Resid/Asphalt 44 46 49 33 2 5 -11

Other2 52 52 77 78 0 25 26

646 685 737 741 40 92 96

Splitter Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-10

PADD IV Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
46

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 2,303 2,374 2,483 2,483 71 181 181

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 591 589 595 595 -2 4 4

2,894 2,963 3,077 3,078 69 184 185

Products

Propane/Propylene 45 47 51 51 2 6 6

Normal Butane 8 11 12 12 3 4 4

Isobutane -1 -3 -8 -8 -2 -7 -7

Gasoline 1,600 1,579 1,637 1,639 -21 38 40

Jet/Kerosene 414 429 445 445 15 31 31

Distillate 568 583 621 621 15 53 53

Resid/Asphalt 130 131 133 133 1 3 3

Other2 313 369 372 370 56 59 57

3,077 3,145 3,263 3,263 68 187 186

Splitter Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-11

PADD V Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
47

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 15,008 15,965 16,360 16,269 959 1,352 1,261

Crude to Splitters 68 158 262 362 90 194 294

Other Feedstocks1 2,943 2,971 2,983 2,988 28 40 45

18,019 19,094 19,605 19,619 1,076 1,586 1,600

Products

Propane/Propylene 564 593 603 609 29 39 45

Normal Butane 64 97 122 125 33 58 61

Isobutane -5 -4 7 3 1 12 8

Gasoline 9,038 9,334 9,454 9,509 296 416 471

Jet/Kerosene 1,496 1,652 1,701 1,638 156 205 142

Distillate 4,857 5,002 5,121 5,119 145 264 262

Resid/Asphalt 836 856 832 841 20 -4 5

Other2 2,188 2,503 2,627 2,547 315 439 359

19,038 20,034 20,468 20,389 996 1,430 1,351

Splitter Products

LPG 4 9 15 20 5 10 16

Light Naphtha 17 35 58 80 18 41 63

Naphtha 22 46 77 106 25 55 84

Unfinished Distillate 18 44 73 101 26 55 83

Gas Oil 6 23 40 54 17 34 48

68 158 262 362 90 195 295

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-12

U.S. Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
48

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 584 3,139 -2,555 635 3,128 -2,493 656 2,909 -2,253 655 2,661 -2,006

Jet/Kerosene 73 404 -331 90 408 -318 86 407 -321 83 409 -326

Distillate 361 1,187 -826 357 1,226 -869 332 1,253 -922 331 1,246 -916

Residual Fuel 66 120 -54 55 106 -52 54 102 -48 56 107 -51

Other1 177 460 -283 183 455 -272 190 495 -305 193 544 -351

1,261 5,309 -4,048 1,320 5,324 -4,004 1,318 5,166 -3,848 1,318 4,967 -3,650

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

2020 2025

Table II-13

PADD I Product Supply and Demand Balance - MBPD

2013 2015
49

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 2,319 2,402 -83 2,498 2,393 105 2,501 2,179 322 2,463 1,971 492

Jet/Kerosene 223 267 -44 273 270 3 289 270 20 282 269 13

Distillate 1,013 1,174 -161 1,069 1,239 -170 1,091 1,290 -199 1,080 1,290 -210

Residual Fuel 48 36 12 56 13 43 21 14 7 18 16 2

Other1 622 1,003 -381 648 994 -346 697 1,103 -406 710 1,143 -433

4,225 4,881 -657 4,545 4,909 -364 4,600 4,856 -256 4,554 4,690 -135

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-14

PADD II Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
50

Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus

Gasoline 4,216 1,361 2,855 4,282 1,357 2,925 4,323 1,299 3,023 4,409 1,207 3,202

Jet/Kerosene 760 264 496 825 267 559 834 276 558 770 283 487

Distillate 2,721 786 1,935 2,793 835 1,958 2,866 902 1,964 2,871 911 1,959

Residual Fuel 281 102 179 302 72 230 308 64 244 334 71 263

Other2 1,920 2,559 -639 2,294 2,568 -274 2,481 2,993 -512 2,491 3,276 -785

9,898 5,072 4,826 10,496 5,099 5,397 10,811 5,534 5,277 10,875 5,749 5,126

1. Supply includes production from splitters and hydroskimmers.

2. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-15

PADD III Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
51

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 320 302 17 340 301 39 337 295 42 342 281 61

Jet/Kerosene 26 38 -12 35 39 -3 46 39 7 58 40 17

Distillate 194 167 27 200 176 23 211 185 27 215 188 27

Resid/Asphalt 11 2 9 13 2 11 16 2 14 0 2 -2

Other1 95 68 27 98 67 31 127 114 12 126 129 -3

646 577 69 685 585 100 737 635 102 741 640 101

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-16

PADD IV Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
52

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 1,600 1,505 94 1,579 1,500 79 1,637 1,434 203 1,639 1,329 310

Jet/Kerosene 414 447 -33 429 451 -23 445 461 -16 445 470 -25

Distillate 568 565 3 583 590 -7 621 624 -3 621 636 -14

Residual Fuel 111 120 -9 112 95 17 114 93 21 114 95 19

Other1 384 356 28 443 356 87 446 437 9 444 484 -40

3,077 2,993 83 3,145 2,992 153 3,263 3,050 213 3,263 3,013 250

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-17

PADD V Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
53

Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus

Gasoline 9,038 8,710 328 9,334 8,680 655 9,454 8,116 1,339 9,509 7,449 2,060

Jet/Kerosene 1,496 1,419 77 1,652 1,434 217 1,701 1,454 247 1,638 1,472 166

Distillate 4,857 3,878 979 5,002 4,066 936 5,121 4,254 867 5,119 4,272 847

Residual Fuel 517 380 137 537 288 249 513 275 238 522 291 232

Other2 1,677 2,125 -449 2,145 2,123 22 2,419 2,459 -39 2,443 2,666 -223

17,585 16,513 1,072 18,670 16,591 2,079 19,209 16,557 2,652 19,230 16,150 3,081

NGLs 2,606 2,320 286 3,350 2,318 1,032 4,177 2,684 1,493 3,962 2,910 1,052

Total Products 20,191 18,833 1,358 22,020 18,909 3,112 23,386 19,241 4,145 23,192 19,060 4,133

1. Supply includes production from splitters and hydroskimmers.

2. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-18

U.S. Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
54

I II III IV V Export WC EC Export Total I II III IV V Export WC EC Export Total

2013 2015-2013

Northeast 38 63 101 Northeast -2 -24 0 0 0 0 0 0 0 -26

Gulf Coast 25 2,546 25 2,596 Gulf Coast 0 20 1,302 0 0 0 0 0 0 1,322

Midcontinent 599 599 Midcontinent 0 -200 0 0 0 0 0 0 0 -200

Southwest 350 1,296 1,646 Southwest 0 604 -182 0 0 0 0 0 0 422

Rocky Mountain 168 566 150 316 90 108 1,398 Rocky Mountain 290 142 -150 36 120 0 0 224 0 662

California 603 603 California 0 0 0 0 17 0 0 0 0 17

Alaska 515 515 Alaska 0 0 0 0 -65 0 0 0 0 -65

W. Canada 110 1,733 182 253 198 613 329 3,418 W. Canada 0 -192 352 0 0 0 0 202 0 363

E. Canada 103 129 232 E. Canada -5 0 0 0 0 0 0 0 0 -5

Foreign 577 43 3,654 0 897 1 0 517 5,690 Foreign -227 -43 -743 0 -1 -1 0 -426 0 -1,441

Total 1,022 3,354 7,829 569 2,303 1 613 1,108 16,798 Total 56 306 579 36 71 -1 0 0 1,047

2015 2020-2015

Northeast 36 38 74 Northeast -3 -8 0 0 0 0 0 0 0 -11

Gulf Coast 25 20 3,848 25 3,918 Gulf Coast 1 0 691 0 0 0 0 0 0 692

Midcontinent 399 399 Midcontinent 0 0 0 0 0 0 0 0 0 0

Southwest 954 1,114 2,068 Southwest 0 -80 400 0 0 0 0 0 0 320

Rocky Mountain 458 708 352 210 332 2,060 Rocky Mountain 233 -98 0 45 95 0 0 193 0 468

California 620 620 California 0 0 0 0 28 0 0 0 0 28

Alaska 450 450 Alaska 0 0 0 0 -32 0 0 0 0 -32

W. Canada 110 1,541 535 253 198 613 531 3,780 W. Canada 35 242 550 3 0 0 46 -148 0 728

E. Canada 98 129 227 E. Canada 31 0 0 0 0 0 0 5 0 36

Foreign 350 2,912 896 91 4,249 Foreign -298 0 -1,356 0 18 0 0 -50 0 -1,686

Total 1,077 3,659 8,408 605 2,374 0 613 1,108 17,845 Total -1 56 286 48 109 0 46 0 544

2020 2025-2020

Northeast 33 30 64 Northeast -3 -3 0 0 0 0 0 0 0 -6

Gulf Coast 26 20 4,539 25 4,610 Gulf Coast 2 0 -378 0 0 0 0 0 0 -376

Midcontinent 398 398 Midcontinent 0 174 0 0 0 0 0 0 0 174

Southwest 874 1,513 2,387 Southwest 0 -92 238 0 0 0 0 0 0 146

Rocky Mountain 691 610 397 305 525 2,528 Rocky Mountain 39 -93 0 0 47 0 0 0 0 -7

California 648 648 California 0 0 0 0 33 0 0 0 0 33

Alaska 418 418 Alaska 0 0 0 0 -101 0 0 0 0 -101

W. Canada 145 1,783 1,085 256 198 659 383 4,508 W. Canada 45 -29 833 0 7 0 0 3 0 859

E. Canada 129 134 263 E. Canada -61 0 0 0 0 0 0 -27 0 -88

Foreign 52 1,556 914 41 2,563 Foreign -22 0 -641 0 14 0 0 24 0 -625

Total 1,077 3,715 8,694 653 2,483 0 659 1,108 18,389 Total 0 -43 51 0 0 0 0 0 8

2025 2025-2013

Northeast 31 27 58 Northeast -7 -35 0 0 0 0 0 0 0 -43

Gulf Coast 28 20 4,161 25 4,234 Gulf Coast 3 20 1,615 0 0 0 0 0 0 1,638

Midcontinent 573 573 Midcontinent 0 -26 0 0 0 0 0 0 0 -26

Southwest 782 1,751 2,533 Southwest 0 432 455 0 0 0 0 0 0 887

Rocky Mountain 730 517 397 352 525 2,522 Rocky Mountain 562 -49 -150 81 262 0 0 417 0 1,123

California 681 681 California 0 0 0 0 78 0 0 0 0 78

Alaska 317 317 Alaska 0 0 0 0 -198 0 0 0 0 -198

W. Canada 190 1,754 1,918 256 205 659 386 5,368 W. Canada 80 21 1,736 3 7 0 46 57 0 1,950

E. Canada 68 107 175 E. Canada -35 0 0 0 0 0 0 -22 0 -57

Foreign 30 915 928 65 1,938 Foreign -547 -43 -2,739 0 31 -1 0 -452 0 -3,752

Total 1,077 3,673 8,745 653 2,483 0 659 1,108 18,398 Total 55 319 916 84 181 -1 46 0 1,600

Table II-19

U.S. Canada

Crude Oil Flows, MBPD U.S. Canada
55

Planned Required

Movements Rail Rail Cap.

by Rail Capacity Additions

2013 278 555 - - 

2015 568 1,320 - - 

2020 836 - - 0 - 352

2025 920 - - 0 - 520

Comments

- Movements by rail into PADD I are expected to rise by nearly 650 MBPD from 2013 to 2025.

- Existing rail off-loading capacity exceeds short term rail capacity requirements.

- Projected rail expansion plans appear to be on track to keep pace with desired movements into PADD I.

- See Appendix 1 for existing and planned PADD I rail offloading facilities.

- Current pipeline and rail delivery systems from the Gulf Coast, the Southwest and Canada are sufficient to meet

 crude demand requirements through 2025.

Movements

Southwest Local/PADD II to Indirect

Production Demand Gulf Coast Direct (via Cushing) Total Surplus

2013 1,646 792 854 363 525 888 33

2015 2,068 1,419 649 925 525 1450 801

2020 2,387 1,339 1,049 1225 525 1750 701

2025 2,533 1,247 1,287 1225 525 1750 463

Comments

- The Permian Basin largely became debottlenecked with the startup of the Magellan Longhorn pipeline in 2013.

- Permian Basin volumes will shift into PADD II in 2015 to replace declining Midcontinent production.

- Movements to the Gulf Coast will peak in 2025 at nearly 1.3 million BPD.

- Pipeline capacity from the Permian Basin to the Gulf Coast is projected to exceed these movement requirements.

- No bottlenecks are expected in moving crude from the Southwest to the Gulf Coast in the Low Production Case.

- See Appendix 2 for existing and planned Permian Basin exit pipelines.

Table II-20

Required Crude Oil Logistic Improvements, MBPD

Pipelines from the Permian Basin with access the USGC

Pipeline Movements from Southwest to the Gulf Coast

Rail Movements into PADD I

Crude Movements into PADD II
56

Table II-20

Required Crude Oil Logistic Improvements, MBPD

Western Rocky

Canada Mountains Total Capacity Surplus

2013 182 150 332 550 218

2015 535 0 535 1,550 1,015

2020 1,085 0 1,085 2,210 1,125

2025 1,918 0 1,918 2,210 292

Comments

- Crude movements to the Gulf Coast will rise from 332 MBD in 2013 to 1.9 million BPD by 2025.

- Existing pipeline capacity out of Cushing/Patoka is 1.55 million BPD and will rise to 2.21 million BPD by 2017.

- The Enbridge/Energy Transfer Trunkline (or similar capacity pipeline) from Patoka, IL to St. James, LA may be

 required to flow the necessary volumes from Western Canada to the Gulf Coast around 2025.

- See Appendix 3 for existing and planned pipelines from Cushing, OK and Patoka, IL to the Gulf Coast.

- Current pipeline delivery systems from the Rocky Mountains and Western Canada are sufficient to meet crude

 demand requirements through 2025.

Planned Required

Movements Rail Rail Cap.

by Rail Capacity Additions

2013 90 148 - - 

2015 210 370 - - 

2020 305 - - 0 - 240

2025 352 - - 0 - 334

Comments

- Movements by rail into PADD V are expected to rise from 90 MBPD in 2013 to 352 MBPD in 2025.

- Existing rail off-loading capacity exceeds short term rail capacity requirements.

- Projected rail expansion plans appear to be on track to keep pace with desired movements into PADD V

 provided permits are not unduly constrained.

- See Appendix 4 for existing and planned PADD V rail offloading facilities.

Pipeline Movements from Western Canada and the Rocky Mountains to the Gulf Coast

Movements to the Gulf Coast Pipeline Capacity, South of

Cusking, OK and Patoka, IL

Crude Movements into PADD IV

Rail Movements into PADD V
57

Table II-20

Required Crude Oil Logistic Improvements, MBPD

to the to Eastern Rail

U.S. Canada Total Pipelines Movements Total Surplus

2013 2,476 329 2,805 3,568 120 3,688 883

2015 2,636 531 3,167 3,656 593 4,249 1,081

2020 3,466 383 3,849 3,918 750 4,668 819

2025 4,323 386 4,709 3,918 750 4,668 -41

Comments

- Movements out of Western Canada are expected to rise from 2.8 million BPD in 2013 to 4.7 million BPD in 2025.

- Existing exit pipeline capacity out of Western Canada is 3.6 million BPD.

- The Enbridge Alberta Clipper pipeline is viewed as highly likely with a capacity of 350 MBPD and a startup

 date in 3Q2015.

- Four other major exit pipelines are being discussed (see Appendix 5).

- At least one of these four new pipelines will need to be in place by 2025 to achieve the Canadian

 production forecast.

- Incremental movements to the U.S. between 2013 and 2025 are 1.85 million BPD.

- The Alberta Clipper (350 MBPD) and rail (630 MBPD) will absorb 980 MBPD of these movements leaving 

 nearly 900 MBPD of required capacity additions.

- Construction of additional pipelines by 2025 will be required to meet U.S. requirements.

Crude Movements out of Western Canada

Crude Movements out of Western Canada Existing Exit Capacity with the Alberta Clipper
58

2013 2015 2020 2025 Comments

PADD I -2,555 -2,493 -2,253 -2,006 - Reduced utilization of Colonial/Plantation systems.

PADD II -83 105 322 492 - Increased movements into PADD I from Ohio and into PADD III

 for export via Mississippi River.

PADD III 2,855 2,925 3,023 3,202 - Likely origin of PADD I-IV exports (increase of 1.5 million BPD).

PADD IV 17 39 42 61 - Surplus volumes to be moved into PADDs II and V.

PADD V 94 79 203 310 - Incremental 216 MBPD to be exported.

Total U.S. 328 655 1,339 2,060

Conclusions

- No incremental requirements for Colonial/Plantation systems.

- Modest pipeline upgrades to be made in moving PADD II volumes from Ohio into western Pennsylvania.

- The most significant logistic improvements to be focused on product exports (which are increasing by 1.7 million BPD).

- Exports will be primarilly from PADD III but also from PADD V beginning in 2020.

Table II-21

Gasoline Supply and Demand Balance - MBPD
59

2013 2015 2020 2025 Comments

PADD I -331 -318 -321 -326

PADD II -44 3 20 13 - Increased movements into PADD I from Ohio and into PADD III

 for export via Mississippi.

PADD III 496 559 558 487

PADD IV -12 -3 7 17 - Surplus volumes to be moved into PADDs II and V.

PADD V -33 -23 -16 -25

Total U.S. 77 217 247 166

Conclusions

- No incremental requirements for Colonial/Plantation systems.

- Modest pipeline upgrades to be made in moving PADD II volumes from Ohio into western Pennsylvania.

- No significant logistics improvements required for Jet/Kerosene movements.

Table II-22

Jet/Kerosene Supply and Demand Balance - MBPD
60

2013 2015 2020 2025 Comments

PADD I -826 -869 -922 -916 - Increased usage of Colonial/Plantation systems.

PADD II -161 -170 -199 -210 - Shortfall grows slightly, requires greater receipts from

 PADD III.

PADD III 1,935 1,958 1,964 1,959 - Surplus remains constant. Movements to PADDs I and II

 and exports.

PADD IV 27 23 27 27 - Surplus volumes to be moved into PADDs II and V.

PADD V 3 -7 -3 -14

Total U.S. 979 936 867 847

Conclusions

- Movements from PADD III to Padd I increase by 90 MBPD from 2013 to 2025. Surplus capacity will exist on Colonial/Plantation

 systems due to reduction of gasoline movements by 549 MBPD.

- Movements from PADD III to PADD II will increase slightly (Explorer Pipeline).

- Exports will decline by 132 MBPD as internal demand grows faster than production.

- No significant logistics improvements required for Distillate movements.

Table II-23

Distillate Supply and Demand Balance - MBPD
61

2013 2015 2020 2025 Comments

PADD I -54 -52 -48 -51

PADD II 12 43 7 2

PADD III 179 230 244 263 - Incremental 84 MBPD to be exported.

PADD IV 9 11 14 -2

PADD V -9 17 21 19

Total U.S. 137 249 238 232

Conclusions

- No significant logistics improvements required for Residual Fuel movements.

Table II-24

Residual Fuel Supply and Demand Balance - MBPD
62

2013 2015 2020 2025 Comments

PADD I -283 -272 -305 -351

PADD II -381 -346 -406 -433

PADD III -639 -274 -512 -785 - Predominantly NGL growth.

PADD IV 27 31 12 -3

PADD V 28 87 9 -40

Total Refining -1,248 -774 -1,202 -1,612

Adjustments -1521 -1521 -1521 -1521

NGL Demand 2,320 2,318 2,684 2,910

Total U.S. -449 22 -39 -223

Conclusions

- Increase in Other shortfall is predominantly the result of increased Natural Gas Liquids (NGLs) production.

- NGL logistics are being developed in conjunction with increased natural gas drilling.

- Logistic requirements for Other refining products (non-NGLs) are not viewed to be significant.

1. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-25

Other Products1 Supply and Demand Balance - MBPD
63

2013 2015 2020 2025 Comments

PADD I -4,048 -4,004 -3,848 -3,650 - PADD I product shortfall to decline by nearly 400 MBPD.

PADD II -657 -364 -256 -135 - PADD II product shortfall to deline by 522 MBPD.

PADD III 4,826 5,397 5,277 5,126 - PADD III exports to rise by around 1.8 million BPD.

PADD IV 69 100 102 101 - PADD IV movements generally flat.

PADD V 83 153 213 250 - PADD V exports to rise by 167 MBPD.

Total Refining 273 1,283 1,489 1,692

Adjustments -1521 -1521 -1521 -1521

NGL Demand 2,320 2,318 2,684 2,910

Total U.S. 1,072 2,079 2,652 3,081

Conclusions

- No major product infrastructure improvements are necessary for movements between PADDs.

- Logistic improvements will be necessary for the incremental export of 2.0 million BPD between 2013 and 2025.

Table II-26

Total U.S. Refined Products Supply and Demand Balance - MBPD
64

2013 2015 2020 2025 Likely Destinations

Crude Exports from the U.S.

Gulf Coast

Condensate 25 25 25 25 Canada

Rocky Mountains

Ultra Light Sweet 108 332 525 525 Canada

Total U.S. 133 357 550 550

Crude Exports from Canada*

Total Canada 0 0 0 0

Total U.S. and Canada 133 357 550 550

* Excluding movements to the U.S.

Table II-27

U.S. and Canadian Crude Oil Exports - MBPD
65

2013 2015 2020 2025 Likely Destinations

Refined Products

Gasoline 328 655 1,339 2,060 Mexico, other Latin America

Jet/Kerosene 77 217 247 166 Canada, Mexico, other Latin America

Distillate 979 936 867 847 Mexico, other Latin America, Europe

Residual Fuel 137 249 238 232 East Asia, Latin America, Europe

Other1 -449 22 -39 -223 Latin America, Europe, East Asia

1,072 2,079 2,652 3,081

NGLs 286 1,032 1,493 1,052 Canada, Mexico, Latin America

Total Exports 1,358 3,112 4,145 4,133

1. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table II-28

U.S. Product Exports - MBPD
66

Crude Price Forecast

Low Production Case

(current dollars per barrel)

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

BENCHMARKS

Brent (Sullom Voe) 103.01 99.92 98.89 97.37 99.18 104.51 109.97 115.59 121.37 127.28 133.38

LLS (St. James) 100.78 97.99 97.32 96.03 97.82 103.09 108.45 113.93 119.65 125.36 131.30

WTI (Cushing) 95.90 93.08 92.38 91.05 92.80 98.03 103.35 108.79 114.44 120.09 125.96

Bakken (Clearbrook) 91.47 88.72 88.03 86.76 88.51 93.76 99.10 104.54 110.17 115.67 121.30

Maya (FOB) 89.47 86.89 85.21 83.35 84.72 89.60 94.44 98.70 103.66 108.76 114.16

Canadian WCS (Hardisty) 82.42 79.67 77.98 76.00 77.50 82.15 87.02 91.18 96.04 101.05 106.36

DIFFERENTIALS

Brent - LLS 2.23 1.93 1.57 1.34 1.36 1.42 1.52 1.66 1.72 1.91 2.08

LLS - WTI 4.87 4.91 4.94 4.98 5.02 5.06 5.10 5.15 5.21 5.27 5.34

WTI - Bakken 4.43 4.36 4.35 4.29 4.29 4.27 4.25 4.25 4.27 4.42 4.66

LLS - Maya 11.31 11.10 12.12 12.68 13.10 13.49 14.01 15.24 15.99 16.60 17.14

Maya - WCS 7.05 7.22 7.23 7.35 7.22 7.45 7.41 7.52 7.63 7.71 7.80

Table II-29
67

Number Tab Table Name

III-1 2013 Crude Oil Supply and Demand Balance - 2013

III-2 2015 Crude Oil Supply and Demand Balance - 2015

III-3 2020 Crude Oil Supply and Demand Balance - 2020

III-4 2025 Crude Oil Supply and Demand Balance - 2025

III-5 Capacities U.S. and Canadian Distillation Capacities

III-6 Utilizations U.S. and Canadian Utilization Rates

III-7 PI Products Total PADD I Charge and Yield Data

III-8 PII Products Total PADD II Charge and Yield Data

III-9 PIII Products Total PADD III Charge and Yield Data

III-10 PIV Products Total PADD IV Charge and Yield Data

III-11 PV Products Total PADD V Charge and Yield Data

III-12 US Products Total U.S. Charge and Yield Data

III-13 PI Balance PADD I Refinery Product Supply and Demand Balance

III-14 PII Balance PADD II Refinery Product Supply and Demand Balance

III-15 PIII Balance PADD III Refinery Product Supply and Demand Balance

III-16 PIV Balance PADD IV Refinery Product Supply and Demand Balance

III-17 PV Balance PADD V Refinery Product Supply and Demand Balance

III-18 US Balance U.S. Product Supply and Demand Balance

III-19 Crude Flows Crude Oil Flows

III-20 Crude Logistics Required Crude Oil Logistic Improvements

III-21 Gasoline Gasoline Supply and Demand Balance

III-22 Jet-Kero Jet/Kerosene Supply and Demand Balance

III-23 Distillate Distillate Supply and Demand Balance

III-24 Resid Residual Fuel Supply and Demand Balance

III-25 Other Other Products Supply and Demand Balance

III-26 Total Total U.S. Refined Products Supply and Demand Balance

III-27 Crude Exports U.S. and Canadian Crude Oil Exports

III-28 Product Exports U.S. Product Exports

III-29 Prices Crude Price Forecast - High Resource Exports Restricted

Implications of Increasing U.S. Light Tight Oil Production

High Production Base Case
68

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 5 5

 Light Sour (API 35 - <40) 11 11

 Medium Medium Sour (API 27 - <35) 26 26

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 30 18 12

 Lease Condensate (API >=50) 28 15 13

101

Gulf Coast

 Light Sweet (API 35 - <40) 223 223

 Light Sour (API 35 - <40) 64 64

 Medium Medium Sour (API 27 - <35) 98 98

 Medium Sour (API 27 - <35) 17 17

 Heavy Sweet (API <27) 14 14

 Heavy Sour (API <27) 18 18

 Ultra Light Sweet (API 40 - <50) 238 10 228

 Lease Condensate (API >=50) 639 15 532 68 25

1,312

Midcontinent

 Light Sweet (API 35 - <40) 154 154

 Light Sour (API 35 - <40) 26 26

 Medium Medium Sour (API 27 - <35) 73 73

 Medium Sour (API 27 - <35) 13 13

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 2 2

 Ultra Light Sweet (API 40 - <50) 205 205

 Lease Condensate (API >=50) 122 122

599

Southwest

 Light Sweet (API 35 - <40) 332 225 107

 Light Sour (API 35 - <40) 124 75 49

 Medium Medium Sour (API 27 - <35) 93 93

 Medium Sour (API 27 - <35) 341 50 291

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 14 14

 Ultra Light Sweet (API 40 - <50) 647 647

 Lease Condensate (API >=50) 91 91

1,646

Rocky Mountains

 Light Sweet (API 35 - <40) 121 21 75 25

 Light Sour (API 35 - <40) 133 58 75

 Medium Medium Sour (API 27 - <35) 35 35

 Medium Sour (API 27 - <35) 16 16

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 56 56

 Ultra Light Sweet (API 40 - <50) 980 168 438 176 90 108

 Lease Condensate (API >=50) 54 49 5

1,399

West Coast, California

 West Coast, California 513 513

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 1,284 1,284

 Pacific California 90 90

1,374

Alaska

 North Slope Offshore Medium Medium 0

 North Slope Onshore Medium Medium 500 500

 South Alaska Medium Medium Sour 15 15

515

Total U.S. 7,459 231 1,578 3,925 316 1,208 68 0 0 0 0 133 0

Western Canada

 Condensate 0

 Super Light 52 16 3 0 0 11 21

 Light Sweet 766 382 8 48 57 29 243

 Light Sour 245 4 78 3 8 52 101

 Medium 491 65 200 5 11 26 183

 Heavy 1,864 25 1,070 166 187 51 300 65

3,418

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 232 103 129

 Light Sour 0

 Medium 0

 Heavy 0

232

Foreign Imports

 Condensate 7 5 0 3 0

 Super Light 68 39 0 19 10

 Light Sweet 942 329 1 166 100 347

 Light Sour 1,030 87 32 604 262 1 45

 Medium 1,393 49 8 964 327 45

 Heavy 2,248 68 2 1,899 198 80

5,689

Total Supply 16,798 1,022 3,354 7,761 569 2,303 68 0 0 1 613 1,108 0

Table III-1

EIA High Production Base Case - MPBD

Crude Oil Supply and Demand Balance - 2013

U.S. Canada
69

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 3 3

 Light Sour (API 35 - <40) 9 9

 Medium Medium Sour (API 27 - <35) 15 15

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 22 18 4

 Lease Condensate (API >=50) 31 15 16

80

Gulf Coast

 Light Sweet (API 35 - <40) 349 349

 Light Sour (API 35 - <40) 106 106

 Medium Medium Sour (API 27 - <35) 109 109

 Medium Sour (API 27 - <35) 58 58

 Heavy Sweet (API <27) 16 16

 Heavy Sour (API <27) 22 22

 Ultra Light Sweet (API 40 - <50) 800 10 20 720 50

 Lease Condensate (API >=50) 803 15 655 108 25

2,262

Midcontinent

 Light Sweet (API 35 - <40) 103 103

 Light Sour (API 35 - <40) 17 17

 Medium Medium Sour (API 27 - <35) 53 53

 Medium Sour (API 27 - <35) 9 9

 Heavy Sweet (API <27) 2 2

 Heavy Sour (API <27) 1 1

 Ultra Light Sweet (API 40 - <50) 128 128

 Lease Condensate (API >=50) 76 76

389

Southwest

 Light Sweet (API 35 - <40) 399 399

 Light Sour (API 35 - <40) 126 126

 Medium Medium Sour (API 27 - <35) 82 82

 Medium Sour (API 27 - <35) 287 50 237

 Heavy Sweet (API <27) 4 4

 Heavy Sour (API <27) 11 11

 Ultra Light Sweet (API 40 - <50) 894 393 501

 Lease Condensate (API >=50) 272 272

2,077

Rocky Mountains

 Light Sweet (API 35 - <40) 105 61 44

 Light Sour (API 35 - <40) 157 133 24

 Medium Medium Sour (API 27 - <35) 28 28

 Medium Sour (API 27 - <35) 19 19

 Heavy Sweet (API <27) 2 2

 Heavy Sour (API <27) 54 54

 Ultra Light Sweet (API 40 - <50) 1,782 546 452 177 275 332

 Lease Condensate (API >=50) 58 53 5

2,206

West Coast, California

 West Coast, California 554 554

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 1,697 1,697

 Pacific California 90 90

1,787

Alaska

 North Slope Offshore Medium Medium 44 44

 North Slope Onshore Medium Medium 397 397

 South Alaska Medium Medium Sour 9 9

450

Total U.S. 9,805 607 2,120 4,841 353 1,369 158 0 0 0 0 357 0

Western Canada

 Condensate 0

 Super Light 54 16 4 0 0 13 21

 Light Sweet 800 209 0 60 57 29 445

 Light Sour 255 4 91 0 7 52 101

 Medium 519 64 228 5 12 26 183

 Heavy 2,153 26 1,007 531 173 51 300 65

3,781

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 227 98 129

 Light Sour 0

 Medium 0

 Heavy 0

227

Foreign Imports

 Condensate 0

 Super Light 0

 Light Sweet 97 97

 Light Sour 805 95 386 324

 Medium 1,385 48 964 328 45

 Heavy 1,745 22 1,523 154 46

4,032

Total Supply 17,845 1,077 3,659 8,250 605 2,374 158 0 0 0 613 1,108 0

Table III-2

EIA High Production Base Case - MPBD

Crude Oil Supply and Demand Balance - 2015

U.S. Canada
70

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 1 1

 Light Sour (API 35 - <40) 7 7

 Medium Medium Sour (API 27 - <35) 7 7

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 17 17

 Lease Condensate (API >=50) 44 15 29

76

Gulf Coast

 Light Sweet (API 35 - <40) 513 513

 Light Sour (API 35 - <40) 218 218

 Medium Medium Sour (API 27 - <35) 114 114

 Medium Sour (API 27 - <35) 75 75

 Heavy Sweet (API <27) 13 13

 Heavy Sour (API <27) 20 20

 Ultra Light Sweet (API 40 - <50) 1,205 435 670 100

 Lease Condensate (API >=50) 966 22 193 193 534 25

3,124

Midcontinent

 Light Sweet (API 35 - <40) 110 110

 Light Sour (API 35 - <40) 18 18

 Medium Medium Sour (API 27 - <35) 70 70

 Medium Sour (API 27 - <35) 8 8

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 3 3

 Ultra Light Sweet (API 40 - <50) 136 136

 Lease Condensate (API >=50) 132 132

480

Southwest

 Light Sweet (API 35 - <40) 786 349 307 130

 Light Sour (API 35 - <40) 135 52 83

 Medium Medium Sour (API 27 - <35) 81 81

 Medium Sour (API 27 - <35) 305 50 57 198

 Heavy Sweet (API <27) 9 9

 Heavy Sour (API <27) 14 14

 Ultra Light Sweet (API 40 - <50) 1,182 496 686

 Lease Condensate (API >=50) 422 422

2,933

Rocky Mountains

 Light Sweet (API 35 - <40) 106 96 10

 Light Sour (API 35 - <40) 181 133 48

 Medium Medium Sour (API 27 - <35) 38 38

 Medium Sour (API 27 - <35) 15 15

 Heavy Sweet (API <27) 5 5

 Heavy Sour (API <27) 39 39

 Ultra Light Sweet (API 40 - <50) 2,665 304 713 245 878 525

 Lease Condensate (API >=50) 82 66 11 5

3,131

West Coast, California

 West Coast, California 634 634

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 2,437 2,437

 Pacific California 54 54

2,491

Alaska

 North Slope Offshore Medium Medium 72 72

 North Slope Onshore Medium Medium 340 54 286

 South Alaska Medium Medium Sour 6 6

418

Total U.S. 13,287 794 2,478 5,921 405 1,825 293 534 130 358 0 550 0

Western Canada

 Condensate 0

 Super Light 54 21 33

 Light Sweet 788 73 22 195 498

 Light Sour 250 8 52 101 89

 Medium 546 65 13 26 183 259

 Heavy 2,871 60 1,320 754 166 51 353 167

4,509

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 198 103 95

 Light Sour 0

 Medium 0

 Heavy 65 26 39

263

Foreign Imports

 Condensate 0

 Super Light 0

 Light Sweet 0

 Light Sour 0

 Medium 0

 Heavy 2,400 42 1,787 530 41

2,400

Total Supply 20,459 1,090 3,798 8,462 664 2,484 293 534 130 358 659 1,108 879

Table III-3

EIA High Production Base Case - MPBD

Crude Oil Supply and Demand Balance - 2020

U.S. Canada
71

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 1 1

 Light Sour (API 35 - <40) 9 9

 Medium Medium Sour (API 27 - <35) 3 3

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 16 16

 Lease Condensate (API >=50) 69 15 54

97

Gulf Coast

 Light Sweet (API 35 - <40) 480 480

 Light Sour (API 35 - <40) 296 170 126

 Medium Medium Sour (API 27 - <35) 142 142

 Medium Sour (API 27 - <35) 88 88

 Heavy Sweet (API <27) 14 14

 Heavy Sour (API <27) 19 19

 Ultra Light Sweet (API 40 - <50) 1,318 379 10 175 754

 Lease Condensate (API >=50) 868 15 200 343 285 25

3,225

Midcontinent

 Light Sweet (API 35 - <40) 205 205

 Light Sour (API 35 - <40) 24 24

 Medium Medium Sour (API 27 - <35) 103 103

 Medium Sour (API 27 - <35) 11 11

 Heavy Sweet (API <27) 8 8

 Heavy Sour (API <27) 4 4

 Ultra Light Sweet (API 40 - <50) 165 165

 Lease Condensate (API >=50) 177 177

697

Southwest

 Light Sweet (API 35 - <40) 1,054 200 247 127 480

 Light Sour (API 35 - <40) 165 115 0 50

 Medium Medium Sour (API 27 - <35) 98 98

 Medium Sour (API 27 - <35) 343 193 150

 Heavy Sweet (API <27) 17 17

 Heavy Sour (API <27) 19 19

 Ultra Light Sweet (API 40 - <50) 1,366 67 1,299

 Lease Condensate (API >=50) 509 509

3,570

Rocky Mountains

 Light Sweet (API 35 - <40) 92 74 18

 Light Sour (API 35 - <40) 180 91 89

 Medium Medium Sour (API 27 - <35) 104 104

 Medium Sour (API 27 - <35) 63 63

 Heavy Sweet (API <27) 205 101 104

 Heavy Sour (API <27) 44 44

 Ultra Light Sweet (API 40 - <50) 3,036 462 1,026 155 868 525

 Lease Condensate (API >=50) 112 107 5

3,837

West Coast, California

 West Coast, California 677 677

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 2,228 2,228

 Pacific California 47 47

2,276

Alaska

 North Slope Offshore Medium Medium 60 60

 North Slope Onshore Medium Medium 253 55 198

 South Alaska Medium Medium Sour 5 5

317

Total U.S. 14,696 887 2,443 5,834 582 1,930 518 285 1,410 258 0 550 0

Western Canada

 Condensate 0

 Super Light 57 21 36

 Light Sweet 884 75 22 207 580

 Light Sour 258 8 101 150

 Medium 567 183 384

 Heavy 3,602 103 1,356 1,530 102 353 158

5,368

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 145 92 53

 Light Sour 0

 Medium 0

 Heavy 30 15 15

175

Foreign Imports

 Condensate 0

 Super Light 0

 Light Sweet 0

 Light Sour 0

 Medium 0

 Heavy 1,748 85 1,116 482 65

1,748

Total Supply 21,987 1,090 3,799 8,480 665 2,514 518 285 1,410 258 659 1,108 1,203

Table III-4

EIA High Production Base Case - MPBD

Crude Oil Supply and Demand Balance - 2025

U.S. Canada
72

2013 2015 2020 2025

Refining Capacity

PADD I 1,330 1,330 1,330 1,330

PADD II 4,049 4,112 4,174 4,174

PADD III 9,584 9,706 9,804 9,804

PADD IV 658 672 726 726

PADD V 3,063 3,063 3,066 3,066

18,684 18,883 19,100 19,100

Splitter Capacity 75 175 325 575

Hydroskimming Capacity 0 0 144 1,567

Total U.S. Capacity 18,759 19,058 19,569 21,242

Canadian Refineries

Western Canada 666 666 716 716

Eastern Canada 1,206 1,206 1,206 1,206

1,872 1,872 1,922 1,922

Total U.S. and Canadian Capacity 20,631 20,930 21,491 23,164

Table III-5

U.S. and Canadian Distillation Capacities

MBPSD
73

2013 2015 2020 2025

Refineries

PADD I 76.9 81.0 82.0 82.0

PADD II 82.8 89.0 91.0 91.0

PADD III 81.0 85.0 86.3 86.5

PADD IV 86.5 90.0 91.5 91.5

PADD V 75.2 77.5 81.0 82.0

80.3 84.6 86.4 86.6

Splitters 90.0 90.0 90.0 90.0

Hydroskimmers - - - - 90.0 90.0

Canadian Refineries

Western Canada 92.0 92.0 92.0 92.0

Eastern Canada 92.0 92.0 92.0 92.0

92.0 92.0 92.0 92.0

Table III-6

U.S. and Canadian Utilization Rates

MBPD
74

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 1,022 1,077 1,090 1,090 55 69 69

Crude to Splitters 0 0 0 0 0 0 0

Crude to Hydroskimmers 0 0 0 0 0 0 0

Other Feedstocks1 188 194 192 192 6 4 4

1,210 1,271 1,282 1,282 61 72 73

Products

Propane/Propylene 34 39 38 39 5 4 5

Normal Butane 2 6 12 12 4 10 10

Isobutane -1 0 3 4 1 4 5

Gasoline 584 643 623 627 59 39 43

Jet/Kerosene 73 91 86 84 18 13 11

Distillate 361 345 325 321 -16 -36 -40

Resid/Asphalt 116 104 101 102 -12 -15 -14

Other2 92 92 141 138 0 49 46

1,261 1,319 1,329 1,327 58 68 66

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Yearly Volumes, MBPD Change from 2013, MBPD

Table III-7

PADD I Charge and Yield Data
75

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 3,353 3,659 3,798 3,799 306 445 445

Crude to Splitters 0 0 0 0 0 0 0

Crude to Hydroskimmers 0 0 0 0 0 0 0

Other Feedstocks1 669 686 687 688 17 18 19

4,022 4,345 4,485 4,488 323 463 465

Products

Propane/Propylene 107 116 122 124 9 15 17

Normal Butane 4 6 16 16 2 12 12

Isobutane -1 -3 6 5 -2 7 6

Gasoline 2,319 2,498 2,511 2,520 180 192 202

Jet/Kerosene 223 273 293 294 50 70 71

Distillate 1,013 1,069 1,091 1,092 56 78 79

Resid/Asphalt 195 203 173 174 8 -22 -21

Other2 365 381 463 449 16 98 84

4,225 4,544 4,674 4,674 320 449 450

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-8

PADD II Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
76

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 7,761 8,250 8,462 8,480 489 700 719

Crude to Splitters 68 158 293 518 90 225 450

Crude to Hydroskimmers 0 0 130 1,410 0 130 1,410

Other Feedstocks1 1,442 1,446 1,452 1,456 5 10 15

9,271 9,854 10,337 11,864 583 1,065 2,593

Refinery Products

Propane/Propylene 369 380 385 390 11 16 21

Normal Butane 48 75 83 93 27 35 45

Isobutane -1 6 12 11 7 13 12

Gasoline 4,216 4,264 4,324 4,370 48 108 154

Jet/Kerosene 760 824 857 818 64 97 58

Distillate 2,721 2,786 2,874 2,880 65 153 159

Resid/Asphalt 351 368 370 383 17 19 32

Other2 1,366 1,632 1,678 1,662 266 312 296

9,830 10,335 10,584 10,606 505 753 776

Splitter/Hydroskimmer Products

LPG 4 9 21 76 5 16 72

Light Naphtha 17 35 75 284 18 58 266

Naphtha 22 46 111 453 25 89 431

Unfinished Distillate 18 44 82 145 26 63 126

Distillate 0 0 42 434 0 42 434

Gas Oil 6 23 92 535 17 86 530

68 158 423 1,928 90 355 1,860

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-9

PADD III Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
77

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 569 605 664 665 36 95 96

Crude to Splitters 0 0 0 0 0 0 0

Crude to Hydroskimmers 0 0 0 0 0 0 0

Other Feedstocks1 53 55 55 55 2 2 2

622 660 719 720 38 97 98

Products

Propane/Propylene 9 10 11 11 1 2 2

Normal Butane 2 3 4 5 1 2 3

Isobutane -1 0 1 0 1 2 1

Gasoline 320 340 340 345 21 21 25

Jet/Kerosene 26 35 48 63 9 22 37

Distillate 194 200 213 218 6 19 24

Resid/Asphalt 44 46 50 26 2 6 -18

Other2 52 52 81 86 0 29 34

646 686 748 754 40 103 108

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-10

PADD IV Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
78

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 2,303 2,374 2,484 2,514 72 181 211

Crude to Splitters 0 0 0 0 0 0 0

Crude to Hydroskimmers 0 0 0 0 0 0 0

Other Feedstocks1 591 596 603 605 5 12 14

2,894 2,969 3,087 3,119 76 193 225

Products

Propane/Propylene 45 48 55 56 3 10 11

Normal Butane 8 10 13 14 2 5 6

Isobutane -1 -3 -2 -3 -2 -1 -2

Gasoline 1,600 1,647 1,725 1,742 47 125 142

Jet/Kerosene 414 428 443 445 14 29 31

Distillate 568 575 586 594 7 18 26

Resid/Asphalt 130 131 132 132 1 2 2

Other2 313 315 314 318 2 1 5

3,077 3,151 3,266 3,298 75 190 221

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-11

PADD V Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
79

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 15,008 15,965 16,498 16,548 958 1,490 1,540

Crude to Splitters 68 158 293 518 90 225 450

Crude to Hydroskimmers 0 0 130 1,410 0 130 1,410

Other Feedstocks1 2,943 2,977 2,989 2,997 34 46 54

18,019 19,100 19,910 21,473 1,082 1,891 3,454

Products

Propane/Propylene 564 593 612 620 29 48 56

Normal Butane 64 100 128 140 36 64 76

Isobutane -5 0 20 18 5 25 23

Gasoline 9,038 9,392 9,523 9,603 354 485 565

Jet/Kerosene 1,496 1,651 1,726 1,704 155 230 208

Distillate 4,857 4,976 5,089 5,105 119 232 248

Resid/Asphalt 836 851 826 817 15 -10 -19

Other2 2,188 2,472 2,678 2,653 284 490 465

19,038 20,035 20,601 20,659 997 1,563 1,621

Splitter/Hydroskimmer Products

LPG 4 9 21 76 5 16 72

Light Naphtha 17 35 75 284 18 58 266

Naphtha 22 46 111 453 25 89 431

Unfinished Distillate 18 44 82 145 26 63 126

Distillate 0 0 42 434 0 42 434

Gas Oil 6 23 92 535 17 86 530

68 158 423 1,928 90 355 1,860

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-12

U.S. Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
80

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 584 3,139 -2,555 643 3,128 -2,486 623 2,938 -2,315 627 2,742 -2,115

Jet/Kerosene 73 404 -331 91 408 -317 86 407 -322 84 410 -325

Distillate 361 1,187 -826 345 1,227 -882 325 1,262 -937 321 1,278 -957

Residual Fuel 66 120 -54 54 111 -57 51 104 -52 52 106 -55

Other1 177 460 -283 187 433 -247 244 489 -245 243 527 -284

1,261 5,309 -4,048 1,319 5,308 -3,989 1,329 5,200 -3,871 1,327 5,063 -3,736

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

2020 2025

Table III-13

PADD I Refinery Product Supply and Demand Balance - MBPD

2013 2015
81

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 2,319 2,402 -83 2,498 2,393 105 2,511 2,199 312 2,520 2,027 493

Jet/Kerosene 223 267 -44 273 270 3 293 270 23 294 269 25

Distillate 1,013 1,174 -161 1,069 1,239 -170 1,091 1,308 -217 1,092 1,335 -244

Residual Fuel 48 36 12 56 14 42 26 14 12 27 15 12

Other1 622 1,003 -381 648 1,032 -383 753 1,114 -360 741 1,159 -418

4,225 4,881 -657 4,544 4,948 -403 4,674 4,905 -231 4,674 4,806 -132

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-14

PADD II Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
82

Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus

Gasoline 4,216 1,361 2,855 4,264 1,358 2,906 4,324 1,313 3,011 4,370 1,249 3,121

Jet/Kerosene 760 264 496 824 267 558 857 276 580 818 283 534

Distillate 2,721 786 1,935 2,786 835 1,951 2,874 923 1,951 2,880 959 1,920

Residual Fuel 281 102 179 298 74 224 300 64 236 313 68 244

Other2 1,920 2,559 -639 2,320 2,643 -323 2,651 3,063 -413 4,154 3,357 797

9,898 5,072 4,826 10,493 5,176 5,317 11,006 5,640 5,366 12,533 5,917 6,617

1. Supply includes production from splitters and hydroskimmers.

2. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-15

PADD III Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
83

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 320 302 17 340 301 39 340 299 42 345 291 54

Jet/Kerosene 26 38 -12 35 39 -3 48 39 8 63 40 23

Distillate 194 167 27 200 177 23 213 185 28 218 192 26

Residual Fuel 11 2 9 13 2 11 17 2 15 -7 2 -8

Other1 95 68 27 98 71 27 130 117 13 135 132 3

646 577 69 686 589 97 748 642 106 754 656 97

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-16

PADD IV Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
84

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 1,600 1,505 94 1,647 1,500 147 1,725 1,448 277 1,742 1,371 371

Jet/Kerosene 414 447 -33 428 451 -24 443 462 -18 445 470 -25

Distillate 568 565 3 575 590 -15 586 633 -47 594 655 -61

Residual Fuel 111 120 -9 112 95 17 113 93 19 113 95 18

Other1 384 356 28 389 331 58 400 442 -42 404 489 -85

3,077 2,993 83 3,151 2,967 184 3,266 3,077 189 3,298 3,080 218

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-17

PADD V Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
85

Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus

Gasoline 9,038 8,710 328 9,392 8,680 712 9,523 8,196 1,327 9,603 7,679 1,925

Jet/Kerosene 1,496 1,419 77 1,651 1,434 217 1,726 1,455 271 1,704 1,473 231

Distillate 4,857 3,878 979 4,976 4,068 907 5,089 4,311 778 5,105 4,420 685

Residual Fuel 517 380 137 532 294 237 507 277 230 498 287 211

Other2 1,677 2,125 -449 2,121 2,192 -71 2,657 2,541 116 4,156 2,753 1,403

17,585 16,513 1,072 18,672 16,670 2,002 19,503 16,780 2,723 21,066 16,612 4,453

NGLs 2,606 2,320 286 3,467 2,318 1,149 5,357 2,684 2,673 5,645 2,910 2,735

Total Products 20,191 18,833 1,358 22,139 18,988 3,151 24,860 19,464 5,396 26,711 19,522 7,188

1. Supply includes production from splitters and hydroskimmers.

2. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-18

U.S. Refined Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
86

I II III IV V Export WC EC Export Total I II III IV V Export WC EC Export Total

2013 2015-2013

Northeast 38 63 101 Northeast -2 -19 0 0 0 0 0 0 0 -21

Gulf Coast 25 2,546 25 2,596 Gulf Coast 0 20 1,343 0 0 0 0 0 0 1,363

Midcontinent 599 599 Midcontinent 0 -210 0 0 0 0 0 0 0 -210

Southwest 350 1,296 1,646 Southwest 0 618 -187 0 0 0 0 0 0 431

Rocky Mountain 168 566 150 316 90 108 1,398 Rocky Mountain 378 133 -150 37 185 0 0 224 0 807

California 603 603 California 0 0 0 0 41 0 0 0 0 41

Alaska 515 515 Alaska 0 0 0 0 -65 0 0 0 0 -65

W. Canada 110 1,733 182 253 198 613 329 3,418 W. Canada 0 -194 354 -1 2 0 0 202 0 363

E. Canada 103 129 232 E. Canada -5 0 0 0 0 0 0 0 0 -5

Foreign 577 43 3,654 0 897 1 0 517 5,690 Foreign -315 -43 -781 0 -91 -1 0 -426 0 -1,658

Total 1,022 3,354 7,828 569 2,303 1 613 1,108 16,797 Total 55 306 580 36 72 -1 0 0 1,048

2015 2020-2015

Northeast 36 44 80 Northeast -3 -1 0 0 0 0 0 0 0 -4

Gulf Coast 25 20 3,889 25 3,959 Gulf Coast 432 -20 1,189 0 0 0 0 0 0 1,601

Midcontinent 389 389 Midcontinent 0 91 0 0 0 0 0 0 0 91

Southwest 968 1,109 2,077 Southwest 0 -21 679 0 198 0 0 0 0 855

Rocky Mountain 546 699 353 275 332 2,205 Rocky Mountain -242 309 11 51 603 0 0 193 0 925

California 644 644 California 0 0 0 0 45 0 0 0 0 45

Alaska 450 450 Alaska 0 0 0 0 -390 358 0 0 0 -32

W. Canada 110 1,539 537 252 199 613 531 3,781 W. Canada 15 -219 217 8 -70 0 46 -148 879 728

E. Canada 98 129 227 E. Canada 31 0 0 0 0 0 0 5 0 36

Foreign 262 2,873 806 91 4,032 Foreign -220 0 -1,086 0 -276 0 0 -50 0 -1,632

Total 1,077 3,659 8,408 605 2,374 0 613 1,108 17,845 Total 13 139 1,010 59 110 358 46 0 879 2,614

2020 2025-2020

Northeast 33 43 76 Northeast -2 23 0 0 0 0 0 0 0 21

Gulf Coast 457 5,079 25 5,561 Gulf Coast -63 0 -44 0 0 0 0 0 0 -107

Midcontinent 480 480 Midcontinent 0 216 0 0 0 0 0 0 0 216

Southwest 947 1,788 198 2,933 Southwest 0 -565 1,124 0 79 0 0 0 0 638

Rocky Mountain 304 1,008 11 405 878 525 3,131 Rocky Mountain 158 290 90 177 -10 0 0 0 0 706

California 688 688 California 0 0 0 0 36 0 0 0 0 36

Alaska 60 358 418 Alaska 0 0 0 0 0 -100 0 0 0 -100

W. Canada 125 1,320 754 260 129 659 383 879 4,508 W. Canada -22 36 776 -177 -27 0 0 3 271 860

E. Canada 129 134 263 E. Canada -114 0 0 0 0 0 0 -27 53 -88

Foreign 42 1,787 530 41 2,400 Foreign 43 0 -671 0 -48 0 0 24 0 -652

Total 1,090 3,798 9,418 664 2,484 358 659 1,108 879 20,459 Total 0 1 1,275 0 30 -100 0 0 1,530

2025 2025-2013

Northeast 31 66 97 Northeast -7 3 0 0 0 0 0 0 0 -3

Gulf Coast 394 5,034 25 5,453 Gulf Coast 369 0 2,488 0 0 0 0 0 0 2,857

Midcontinent 697 697 Midcontinent 0 98 0 0 0 0 0 0 0 98

Southwest 382 2,911 277 3,570 Southwest 0 32 1,615 0 277 0 0 0 0 1,924

Rocky Mountain 462 1,298 101 582 868 525 3,837 Rocky Mountain 294 732 -49 266 778 0 0 417 0 2,438

California 725 725 California 0 0 0 0 122 0 0 0 0 122

Alaska 60 258 318 Alaska 0 0 0 0 -455 258 0 0 0 -197

W. Canada 103 1,356 1,530 83 102 659 386 1,150 5,369 W. Canada -7 -377 1,348 -170 -96 0 46 57 1,150 1,951

E. Canada 15 107 53 175 E. Canada -88 0 0 0 0 0 0 -22 53 -57

Foreign 85 1,116 482 65 1,748 Foreign -492 -43 -2,538 0 -415 -1 0 -452 0 -3,942

Total 1,090 3,799 10,693 665 2,514 258 659 1,108 1,203 21,987 Total 69 445 2,865 96 211 257 46 0 5,191

Table III-19

U.S. Canada U.S. Canada

Crude Oil Flows, MBPD
87

Planned Required

Movements Rail Rail Cap.

by Rail Capacity Additions

2013 278 555 - - 

2015 656 1,320 - - 

2020 429 - - - - 

2025 565 - - - - 

Comments

- Movements by rail into PADD I are expected to rise by nearly 378 MBPD from 2013 to 2015.

- Existing rail off-loading capacity exceeds forecast rail capacity requirements.

- Projected rail expansion plans appear to be on track to keep pace with desired movements into PADD I.

- See Appendix 1 for existing and planned PADD I rail offloading facilities.

Planned

Movements

by Water

2013 25

2015 25

2020 457

2025 394

Comments

- Movements by vessel into PADD I are expected to rise by over 430 MBPD from 2013 to 2020.

- Forecast waterborne movements exceed current Jones Act vessel capabilities.

- Substantial coastwise compliant vessel additions will be necessary to achieve forcast movement requirements.

- Current pipeline and rail delivery systems from the Gulf Coast, the Southwest and Canada are sufficient to meet

 crude demand requirements through 2025.

Table III-20

Required Crude Oil Logistic Improvements, MBPD

Rail Movements into PADD I

Crude Movements into PADD II

Vessel Movements into PADD I
88

Table III-20

Required Crude Oil Logistic Improvements, MBPD

Movements

Southwest Local/P II/P V to Indirect

Production Demand Gulf Coast Direct (via Cushing) Total Surplus

2013 1,646 792 854 363 525 888 33

2015 2,077 1,433 645 925 525 1450 805

2020 2,933 1,610 1,323 1225 525 1750 427

2025 3,570 1,124 2,447 1225 525 1750 -697

Comments

- The Permian Basin largely became debottlenecked with the startup of the Magellan Longhorn pipeline in 2013.

- Permian Basin volumes will shift into PADD II in 2015 to replace declining Midcontinent production.

- Movements to the Gulf Coast will peak in 2025 at slightly over 2.4 million BPD.

- Pipeline capacity from the Permian Basin to the Gulf Coast is projected to exceed movements through 2020.

- A pipeline shortfall of 0.7 million BPD of capacity will develop by 2025.

- See Appendix 2 for existing and planned Permian Basin exit pipelines.

Western Rocky

Canada Mountains Total Capacity Surplus

2013 182 150 332 550 218

2015 536 0 536 1,550 1,014

2020 754 11 765 2,210 1,445

2025 1,530 101 1,631 2,210 579

Comments

- Crude movements to the Gulf Coast will rise from 332 MBD in 2013 to 1.6 million BPD by 2025.

- Existing pipeline capacity out of Cushing/Patoka is 1.55 million BPD and will rise to 2.21 million BPD by 2017.

- See Appendix 3 for existing and planned pipelines from Cushing, OK and Patoka, IL to the Gulf Coast.

- Current pipeline delivery systems from the Rocky Mountains and Western Canada are sufficient to meet crude

 demand requirements through 2025.

Movements to the Gulf Coast Pipeline Capacity, South of

Cusking, OK and Patoka, IL

Crude Movements into PADD IV

Pipeline Movements from Western Canada and the Rocky Mountains to the Gulf Coast

Pipelines from the Permian Basin with access the USGC

Pipeline Movements from Southwest to the Gulf Coast
89

Table III-20

Required Crude Oil Logistic Improvements, MBPD

Planned Required

Movements Rail Rail Cap.

by Rail Capacity Additions

2013 90 148 - - 

2015 275 370 - - 

2020 1,076 - - 706 - 1,782

2025 1,145 - - 775 - 1,920

Comments

- Movements by rail into PADD V are expected to rise from 90 MBPD in 2013 to over 1.1 million BPD in 2025.

- Existing rail off-loading capacity exceeds short term rail capacity requirements.

- Projected rail expansion plans appear to be insufficient to meet required movements in 2020 - 2025.

- See Appendix 4 for existing and planned PADD V rail offloading facilities.

to the to Eastern Rail

U.S. Can./Exports Total Pipelines Movements Total Surplus

2013 2,476 329 2,805 3,568 120 3,688 883

2015 2,637 531 3,168 3,656 593 4,249 1,081

2020 2,587 1,262 3,849 3,918 750 4,668 819

2025 3,174 1,536 4,710 3,918 750 4,668 -42

Comments

- Movements out of Western Canada are expected to rise from 2.8 million BPD in 2013 to 4.7 million BPD in 2025.

- Existing exit pipeline capacity out of Western Canada is 3.6 million BPD.

- The Enbridge Alberta Clipper pipeline is viewed as highly likely with a capacity of 350 MBPD and a startup

 date in 3Q2015.

- Four other major exit pipelines are being discussed (see Appendix 5).

- At least one of these four new pipelines will need to be in place by 2025 to achieve the Canadian

 production forecast.

- Incremental movements to the U.S. between 2013 and 2025 are 698 MBPD.

- The Alberta Clipper (350 MBPD) and rail (630 MBPD) will add 980 MBPD of capacity.

- Construction of the Energy East or Northern Gateway pipelines by 2025 will be required to meet Canadian

 export requirements.

Crude Movements out of Western Canada

Crude Movements out of Western Canada Existing Exit Capacity with the Alberta Clipper

Rail Movements into PADD V
90

2013 2015 2020 2025 Comments

PADD I -2,555 -2,486 -2,315 -2,115 - Reduced utilization of Colonial/Plantation systems.

PADD II -83 105 312 493 - Increased movements into PADD I from Ohio and into PADD III

 for export via Mississippi River.

PADD III 2,855 2,906 3,011 3,121 - Likely origin of PADD I-IV exports (increase of 1.3 million BPD).

PADD IV 17 39 42 54 - Surplus volumes to be moved into PADDs II and V.

PADD V 94 147 277 371 - Incremental 277 MBPD to be exported.

Total U.S. 328 712 1,327 1,925

Conclusions

- No incremental requirements for Colonial/Plantation systems.

- Modest pipeline upgrades to be made in moving PADD II volumes from Ohio into western Pennsylvania.

- The most significant logistic improvements to be focused on product exports (which are increasing by 1.6 million BPD).

- Exports will be primarilly from PADD III but also from PADD V.

Table III-21

Gasoline Supply and Demand Balance - MBPD
91

2013 2015 2020 2025 Comments

PADD I -331 -317 -322 -325

PADD II -44 3 23 25 - Increased movements into PADD I from Ohio and into PADD III

 for export via Mississippi.

PADD III 496 558 580 534

PADD IV -12 -3 8 23 - Surplus volumes to be moved into PADDs II and V.

PADD V -33 -24 -18 -25

Total U.S. 77 217 271 231

Conclusions

- No incremental requirements for Colonial/Plantation systems.

- Modest pipeline upgrades to be made in moving PADD II volumes from Ohio into western Pennsylvania.

- No significant logistics improvements required for Jet/Kerosene movements.

Table III-22

Jet/Kerosene Supply and Demand Balance - MBPD
92

2013 2015 2020 2025 Comments

PADD I -826 -882 -937 -957 - Increased usage of Colonial/Plantation systems.

PADD II -161 -170 -217 -244 - Shortfall grows slightly, requires greater receipts from

 PADD III.

PADD III 1,935 1,951 1,951 1,920 - Surplus remains constant. Movements to PADDs I and II

 and exports.

PADD IV 27 23 28 26 - Surplus volumes to be moved into PADDs II and V.

PADD V 3 -15 -47 -61 - Modest shortfall developing in PADD V.

Total U.S. 979 907 778 685

Conclusions

- Movements from PADD III to Padd I increase by 131 MBPD from 2013 to 2025. Surplus capacity will exist on Colonial/Plantation

 systems due to reduction of gasoline movements by 540 MBPD.

- Movements from PADD III to PADD II will increase slightly (Explorer Pipeline).

- Exports will decline by 294 MBPD as internal demand grows faster than production.

- No significant logistics improvements required for Distillate movements.

Table III-23

Distillate Supply and Demand Balance - MBPD
93

2013 2015 2020 2025 Comments

PADD I -54 -57 -52 -55

PADD II 12 42 12 12

PADD III 179 224 236 244 - Incremental 65 MBPD to be exported.

PADD IV 9 11 15 -8

PADD V -9 17 19 18

Total U.S. 137 237 230 211

Conclusions

- No significant logistics improvements required for Residual Fuel movements.

Table III-24

Residual Fuel Supply and Demand Balance - MBPD
94

2013 2015 2020 2025 Comments

PADD I -283 -247 -245 -284

PADD II -381 -383 -360 -418

PADD III -639 -323 -413 797 - Predominantly splitter and hydroskipper products partially

 offset by NGL growth.

PADD IV 27 27 13 3

PADD V 28 58 -42 -85

Total Refining -1,248 -868 -1,047 14

Adjustments -1521 -1521 -1521 -1521

NGL Demand 2,320 2,318 2,684 2,910

Total U.S. -449 -71 116 1,403

Conclusions

- Decrease in Other shortfall is predominantly the result of increased splitter and hydroskimmer yields, partially offset by NGL growth.

- NGL logistics are being developed in conjunction with increased natural gas drilling.

- Substantial logistic improvements for the export of Other products will be necessary. Many of these will be built in coordination

 with the splitter and hydroskimmer projects.

1. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-25

Other Products1 Supply and Demand Balance - MBPD
95

2013 2015 2020 2025 Comments

PADD I -4,048 -3,989 -3,871 -3,736 - PADD I product shortfall to decline by over 300 MBPD.

PADD II -657 -403 -231 -132 - PADD II product shortfall to deline by 525 MBPD.

PADD III 4,826 5,317 5,366 6,617 - PADD III exports to rise by around 3.2 million BPD.

PADD IV 69 97 106 97 - PADD IV movements generally flat.

PADD V 83 184 189 218 - PADD V exports to rise by 135 MBPD.

Total Refining 273 1,205 1,560 3,064

Adjustments -1521 -1521 -1521 -1521

NGL Demand 2,320 2,318 2,684 2,910

Total U.S. 1,072 2,002 2,723 4,453

Conclusions

- No major product infrastructure improvements are necessary for movements between PADDs.

- Substantial logistic improvements will be necessary for the incremental export of 3.4 million BPD between 2013 and 2025.

Table III-26

Total U.S. Products Supply and Demand Balance - MBPD
96

2013 2015 2020 2025 Likely Destinations

Crude Exports from the U.S.

Gulf Coast

Condensate 25 25 25 25 Canada

Rocky Mountains

Ultra Light Sweet 108 332 525 525 Canada

Alaska

Medium 358 258 Far East

Total U.S. 133 357 908 808

Crude Exports from Canada*

Western Canada

Super Light 33 36 Dependent on export pipeline:

Light Sweet 498 580 Far East if TransMountain or

Light Sour 89 150 Northern Gateway. Europe/

Medium 259 384 Latin America if Energy East.

879 1,150

Eastern Canada

Light Sweet 53 Europe

Total Canada 879 1,203

Total U.S. and Canada 133 357 1,787 2,011

* Excluding movements to the U.S.

Table III-27

U.S. and Canadian Crude Oil Exports - MBPD
97

2013 2015 2020 2025 Likely Destinations

Refined Products

Gasoline 328 712 1,327 1,925 Mexico, other Latin America

Jet/Kerosene 77 217 271 231 Canada, Mexico, other Latin America

Distillate 979 907 778 685 Mexico, other Latin America, Europe

Residual Fuel 137 237 230 211 East Asia, Latin America, Europe

Other1 -449 -71 116 1,403 Latin America, Europe, East Asia

1,072 2,002 2,723 4,453

NGLs 286 1,149 2,673 2,735 Canada, Mexico, Latin America

Total Exports 1,358 3,151 5,396 7,188

1. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table III-28

U.S. Product Exports - MBPD
98

Crude Price Forecast

High Production Base Case

(current dollars per barrel)

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

BENCHMARKS

Brent (Sullom Voe) 102.78 98.84 97.49 94.14 94.41 97.82 101.47 105.61 109.74 114.03 119.52

LLS (St. James) 99.58 92.10 87.55 80.84 81.61 86.76 92.31 98.16 102.54 106.68 112.02

WTI (Cushing) 94.71 87.19 82.61 75.85 76.59 81.70 87.21 93.01 97.33 101.41 106.68

Bakken (Clearbrook) 90.28 82.83 78.25 71.57 72.30 77.43 82.96 88.77 93.06 96.99 102.02

Maya (FOB) 88.43 83.80 80.16 73.92 74.66 78.71 82.48 86.70 90.44 94.08 98.62

Canadian WCS (Hardisty) 81.38 76.58 72.93 66.58 67.44 71.26 75.06 79.18 82.81 86.37 90.82

DIFFERENTIALS

Brent - LLS 3.20 6.74 9.94 13.30 12.80 11.06 9.16 7.45 7.20 7.35 7.50

LLS - WTI 4.87 4.91 4.94 4.98 5.02 5.06 5.10 5.15 5.21 5.27 5.34

WTI - Bakken 4.43 4.36 4.35 4.29 4.29 4.27 4.25 4.25 4.27 4.42 4.66

LLS - Maya 11.15 8.30 7.38 6.91 6.95 8.05 9.84 11.46 12.10 12.60 13.40

Maya - WCS 7.05 7.22 7.23 7.35 7.22 7.45 7.41 7.52 7.63 7.71 7.80

Table III-29
99

Number Tab Table Name

IV-1 2013 Crude Oil Supply and Demand Balance - 2013

IV-2 2015 Crude Oil Supply and Demand Balance - 2015

IV-3 2020 Crude Oil Supply and Demand Balance - 2020

IV-4 2025 Crude Oil Supply and Demand Balance - 2025

IV-5 Capacities U.S. and Canadian Distillation Capacities

IV-6 Utilizations U.S. and Canadian Utilization Rates

IV-7 PI Products Total PADD I Charge and Yield Data

IV-8 PII Products Total PADD II Charge and Yield Data

IV-9 PIII Products Total PADD III Charge and Yield Data

IV-10 PIV Products Total PADD IV Charge and Yield Data

IV-11 PV Products Total PADD V Charge and Yield Data

IV-12 US Products Total U.S. Charge and Yield Data

IV-13 PI Balance PADD I Refinery Product Supply and Demand Balance

IV-14 PII Balance PADD II Refinery Product Supply and Demand Balance

IV-15 PIII Balance PADD III Refinery Product Supply and Demand Balance

IV-16 PIV Balance PADD IV Refinery Product Supply and Demand Balance

IV-17 PV Balance PADD V Refinery Product Supply and Demand Balance

IV-18 US Balance U.S. Product Supply and Demand Balance

IV-19 Crude Flows Crude Oil Flows

IV-20 Crude Logistics Required Crude Oil Logistic Improvements

IV-21 Gasoline Gasoline Supply and Demand Balance

IV-22 Jet-Kero Jet/Kerosene Supply and Demand Balance

IV-23 Distillate Distillate Supply and Demand Balance

IV-24 Resid Residual Fuel Supply and Demand Balance

IV-25 Other Other Products Supply and Demand Balance

IV-26 Total Total U.S. Refined Products Supply and Demand Balance

IV-27 Crude Exports U.S. and Canadian Crude Oil Exports

IV-28 Product Exports U.S. Product Exports

IV-29 Prices Crude Price Forecast - High Resource Exports Allowed

Implications of Increasing U.S. Light Tight Oil Production

High Production Export Case
100

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 5 5

 Light Sour (API 35 - <40) 11 11

 Medium Medium Sour (API 27 - <35) 26 26

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 30 18 12

 Lease Condensate (API >=50) 28 15 13

101

Gulf Coast

 Light Sweet (API 35 - <40) 223 223

 Light Sour (API 35 - <40) 64 64

 Medium Medium Sour (API 27 - <35) 98 98

 Medium Sour (API 27 - <35) 17 17

 Heavy Sweet (API <27) 14 14

 Heavy Sour (API <27) 18 18

 Ultra Light Sweet (API 40 - <50) 238 10 228

 Lease Condensate (API >=50) 639 15 532 68 25

1,312

Midcontinent

 Light Sweet (API 35 - <40) 154 154

 Light Sour (API 35 - <40) 26 26

 Medium Medium Sour (API 27 - <35) 73 73

 Medium Sour (API 27 - <35) 13 13

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 2 2

 Ultra Light Sweet (API 40 - <50) 205 205

 Lease Condensate (API >=50) 122 122

599

Southwest

 Light Sweet (API 35 - <40) 332 225 107

 Light Sour (API 35 - <40) 124 75 49

 Medium Medium Sour (API 27 - <35) 93 93

 Medium Sour (API 27 - <35) 341 50 291

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 14 14

 Ultra Light Sweet (API 40 - <50) 647 647

 Lease Condensate (API >=50) 91 91

1,646

Rocky Mountains

 Light Sweet (API 35 - <40) 121 21 75 25

 Light Sour (API 35 - <40) 133 58 75

 Medium Medium Sour (API 27 - <35) 35 35

 Medium Sour (API 27 - <35) 16 16

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 56 56

 Ultra Light Sweet (API 40 - <50) 980 168 438 176 90 108

 Lease Condensate (API >=50) 54 49 5

1,399

West Coast, California

 West Coast, California 513 513

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 1,284 1,284

 Pacific California 90 90

1,374

Alaska

 North Slope Offshore Medium Medium 0

 North Slope Onshore Medium Medium 500 500

 South Alaska Medium Medium Sour 15 15

515

Total U.S. 7,459 231 1,578 3,925 316 1,208 68 0 0 0 0 133 0

Western Canada

 Condensate 0

 Super Light 52 16 3 0 0 11 21

 Light Sweet 766 382 8 48 57 29 243

 Light Sour 245 4 78 3 8 52 101

 Medium 491 65 200 5 11 26 183

 Heavy 1,864 25 1,070 166 187 51 300 65

3,418

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 232 103 129

 Light Sour 0

 Medium 0

 Heavy 0

232

Foreign Imports

 Condensate 7 5 0 3 0

 Super Light 68 39 0 19 10

 Light Sweet 942 329 1 166 100 347

 Light Sour 1,030 87 32 604 262 1 45

 Medium 1,393 49 8 964 327 45

 Heavy 2,248 68 2 1,899 198 80

5,689

Total Supply 16,798 1,022 3,354 7,761 569 2,303 68 0 0 1 613 1,108 0

Table IV-1

EIA High Production Export Case - MPBD

Crude Oil Supply and Demand Balance - 2013

U.S. Canada
101

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 3 3

 Light Sour (API 35 - <40) 9 9

 Medium Medium Sour (API 27 - <35) 15 15

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 22 18 4

 Lease Condensate (API >=50) 31 15 16

80

Gulf Coast

 Light Sweet (API 35 - <40) 349 349

 Light Sour (API 35 - <40) 106 106

 Medium Medium Sour (API 27 - <35) 109 109

 Medium Sour (API 27 - <35) 58 58

 Heavy Sweet (API <27) 16 16

 Heavy Sour (API <27) 22 22

 Ultra Light Sweet (API 40 - <50) 800 10 20 720 50

 Lease Condensate (API >=50) 803 15 655 108 25

2,262

Midcontinent

 Light Sweet (API 35 - <40) 103 103

 Light Sour (API 35 - <40) 17 17

 Medium Medium Sour (API 27 - <35) 53 53

 Medium Sour (API 27 - <35) 9 9

 Heavy Sweet (API <27) 2 2

 Heavy Sour (API <27) 1 1

 Ultra Light Sweet (API 40 - <50) 128 128

 Lease Condensate (API >=50) 76 76

389

Southwest

 Light Sweet (API 35 - <40) 399 399

 Light Sour (API 35 - <40) 126 126

 Medium Medium Sour (API 27 - <35) 82 82

 Medium Sour (API 27 - <35) 287 50 237

 Heavy Sweet (API <27) 4 4

 Heavy Sour (API <27) 11 11

 Ultra Light Sweet (API 40 - <50) 894 393 501

 Lease Condensate (API >=50) 272 272

2,077

Rocky Mountains

 Light Sweet (API 35 - <40) 105 61 44

 Light Sour (API 35 - <40) 157 133 24

 Medium Medium Sour (API 27 - <35) 28 28

 Medium Sour (API 27 - <35) 19 19

 Heavy Sweet (API <27) 2 2

 Heavy Sour (API <27) 54 54

 Ultra Light Sweet (API 40 - <50) 1,782 546 452 177 275 332

 Lease Condensate (API >=50) 58 53 5

2,206

West Coast, California

 West Coast, California 554 554

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 1,697 1,697

 Pacific California 90 90

1,787

Alaska

 North Slope Offshore Medium Medium 44 44

 North Slope Onshore Medium Medium 397 397

 South Alaska Medium Medium Sour 9 9

450

Total U.S. 9,805 607 2,120 4,841 353 1,369 158 0 0 0 0 357 0

Western Canada

 Condensate 0

 Super Light 54 16 4 0 0 13 21

 Light Sweet 800 209 0 60 57 29 445

 Light Sour 255 4 91 0 7 52 101

 Medium 519 64 228 5 12 26 183

 Heavy 2,153 26 1,007 531 173 51 300 65

3,781

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 227 98 129

 Light Sour 0

 Medium 0

 Heavy 0

227

Foreign Imports

 Condensate 0

 Super Light 0

 Light Sweet 97 97

 Light Sour 805 95 386 324

 Medium 1,385 48 964 328 45

 Heavy 1,745 22 1,523 154 46

4,032

Total Supply 17,845 1,077 3,659 8,250 605 2,374 158 0 0 0 613 1,108 0

Table IV-2

EIA High Production Export Case - MPBD

Crude Oil Supply and Demand Balance - 2015

U.S. Canada
102

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 1 1

 Light Sour (API 35 - <40) 7 7

 Medium Medium Sour (API 27 - <35) 7 7

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 17 17

 Lease Condensate (API >=50) 44 15 29

76

Gulf Coast

 Light Sweet (API 35 - <40) 513 258 255

 Light Sour (API 35 - <40) 218 218

 Medium Medium Sour (API 27 - <35) 114 114

 Medium Sour (API 27 - <35) 75 75

 Heavy Sweet (API <27) 13 13

 Heavy Sour (API <27) 20 20

 Ultra Light Sweet (API 40 - <50) 1,205 426 679 100

 Lease Condensate (API >=50) 966 22 193 193 534 25

3,124

Midcontinent

 Light Sweet (API 35 - <40) 110 110

 Light Sour (API 35 - <40) 18 18

 Medium Medium Sour (API 27 - <35) 70 70

 Medium Sour (API 27 - <35) 8 8

 Heavy Sweet (API <27) 3 3

 Heavy Sour (API <27) 3 3

 Ultra Light Sweet (API 40 - <50) 136 136

 Lease Condensate (API >=50) 132 132

480

Southwest

 Light Sweet (API 35 - <40) 786 317 469

 Light Sour (API 35 - <40) 135 52 83

 Medium Medium Sour (API 27 - <35) 81 81

 Medium Sour (API 27 - <35) 305 50 57 198

 Heavy Sweet (API <27) 9 9

 Heavy Sour (API <27) 14 14

 Ultra Light Sweet (API 40 - <50) 1,182 496 686

 Lease Condensate (API >=50) 422 422

2,933

Rocky Mountains

 Light Sweet (API 35 - <40) 106 34 62 10

 Light Sour (API 35 - <40) 181 133 48

 Medium Medium Sour (API 27 - <35) 38 38

 Medium Sour (API 27 - <35) 15 15

 Heavy Sweet (API <27) 5 5

 Heavy Sour (API <27) 39 39

 Ultra Light Sweet (API 40 - <50) 2,665 304 713 245 878 525

 Lease Condensate (API >=50) 82 66 16

3,131

West Coast, California

 West Coast, California 634 634

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 2,437 2,437

 Pacific California 54 54

2,491

Alaska

 North Slope Offshore Medium Medium 72 72

 North Slope Onshore Medium Medium 340 54 286

 South Alaska Medium Medium Sour 6 6

418

Total U.S. 13,287 785 2,384 5,904 400 1,825 293 534 0 613 0 550 0

Western Canada

 Condensate 0

 Super Light 54 21 33

 Light Sweet 788 73 22 195 498

 Light Sour 250 8 52 101 89

 Medium 546 66 12 26 183 259

 Heavy 2,871 59 1,352 722 167 51 353 167

4,509

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 198 103 95

 Light Sour 0

 Medium 0

 Heavy 65 26 39

263

Foreign Imports

 Condensate 0

 Super Light 0

 Light Sweet 0

 Light Sour 0

 Medium 0

 Heavy 2,436 44 1,821 530 41

2,436

Total Supply 20,495 1,083 3,736 8,447 659 2,484 293 534 0 613 0 659 1,108 879

Table IV-3

EIA High Production Export Case - MPBD

Crude Oil Supply and Demand Balance - 2020

U.S. Canada
103

Avail.

Supply I II III IV V Splitters Stab. Hydrosk. Exports Western Eastern Exports

Northeast

 Light Sweet (API 35 - <40) 1 1

 Light Sour (API 35 - <40) 9 9

 Medium Medium Sour (API 27 - <35) 3 3

 Medium Sour (API 27 - <35) 0

 Heavy Sweet (API <27) 0

 Heavy Sour (API <27) 0

 Ultra Light Sweet (API 40 - <50) 16 16

 Lease Condensate (API >=50) 69 15 54

97

Gulf Coast

 Light Sweet (API 35 - <40) 480 480

 Light Sour (API 35 - <40) 296 119 177

 Medium Medium Sour (API 27 - <35) 142 142

 Medium Sour (API 27 - <35) 88 88

 Heavy Sweet (API <27) 14 14

 Heavy Sour (API <27) 19 19

 Ultra Light Sweet (API 40 - <50) 1,318 371 18 175 754

 Lease Condensate (API >=50) 868 15 200 343 285 25

3,225

Midcontinent

 Light Sweet (API 35 - <40) 205 205

 Light Sour (API 35 - <40) 24 24

 Medium Medium Sour (API 27 - <35) 103 103

 Medium Sour (API 27 - <35) 11 11

 Heavy Sweet (API <27) 8 8

 Heavy Sour (API <27) 4 4

 Ultra Light Sweet (API 40 - <50) 165 165

 Lease Condensate (API >=50) 177 177

697

Southwest

 Light Sweet (API 35 - <40) 1,054 200 539 120 195

 Light Sour (API 35 - <40) 165 100 65

 Medium Medium Sour (API 27 - <35) 98 98

 Medium Sour (API 27 - <35) 343 233 110

 Heavy Sweet (API <27) 17 17

 Heavy Sour (API <27) 19 19

 Ultra Light Sweet (API 40 - <50) 1,366 1,366

 Lease Condensate (API >=50) 509 509

3,570

Rocky Mountains

 Light Sweet (API 35 - <40) 92 74 18

 Light Sour (API 35 - <40) 180 91 89

 Medium Medium Sour (API 27 - <35) 104 104

 Medium Sour (API 27 - <35) 63 63

 Heavy Sweet (API <27) 205 99 106

 Heavy Sour (API <27) 44 44

 Ultra Light Sweet (API 40 - <50) 3,036 462 1,027 146 876 525

 Lease Condensate (API >=50) 112 106 6

3,837

West Coast, California

 West Coast, California 677 677

Lower 48 Offshore

 Atlantic Medium Medium Sour 0

 Gulf of Mexico Medium Medium Sour 2,228 2,228

 Pacific California 47 47

2,276

Alaska

 North Slope Offshore Medium Medium 60 60

 North Slope Onshore Medium Medium 253 55 198

 South Alaska Medium Medium Sour 5 5

317

Total U.S. 14,696 879 2,361 5,774 576 1,891 518 285 0 1,864 0 550 0

Western Canada

 Condensate 0

 Super Light 57 21 36

 Light Sweet 884 75 22 207 580

 Light Sour 258 8 101 150

 Medium 567 183 384

 Heavy 3,602 103 1,375 1,511 102 353 158

5,368

Eastern Canada

 Condensate 0

 Super Light 0

 Light Sweet 145 92 53

 Light Sour 0

 Medium 0

 Heavy 30 15 15

175

Foreign Imports

 Condensate 0

 Super Light 0

 Light Sweet 0

 Light Sour 0

 Medium 0

 Heavy 1,804 86 1,147 506 65

1,804

Total Supply 22,045 1,083 3,736 8,432 659 2,499 518 285 0 1,864 659 1,108 1,203

Table IV-4

EIA High Production Export Case - MPBD

Crude Oil Supply and Demand Balance - 2025

U.S. Canada
104

2013 2015 2020 2025

Refining Capacity

PADD I 1,330 1,330 1,330 1,330

PADD II 4,049 4,112 4,174 4,174

PADD III 9,584 9,706 9,804 9,804

PADD IV 658 672 726 726

PADD V 3,063 3,063 3,066 3,066

18,684 18,883 19,100 19,100

Splitter Capacity 75 175 325 575

Hydroskimming Capacity 0 0 0 0

Total U.S. Capacity 18,759 19,058 19,425 19,675

Canadian Refineries

Western Canada 666 666 716 716

Eastern Canada 1,206 1,206 1,206 1,206

1,872 1,872 1,922 1,922

Total U.S. and Canadian Capacity 20,631 20,930 21,347 21,597

Table IV-5

U.S. and Canadian Distillation Capacities

MBPSD
105

2013 2015 2020 2025

Refineries

PADD I 76.9 81.0 81.5 81.5

PADD II 82.8 89.0 89.5 89.5

PADD III 81.0 85.0 86.2 86.0

PADD IV 86.5 90.0 90.8 90.8

PADD V 75.2 77.5 81.0 81.5

80.3 84.6 85.9 85.9

Splitters 90.0 90.0 90.0 63.0

Hydroskimmers - - - - - - - - 

Canadian Refineries

Western Canada 92.0 92.0 92.0 92.0

Eastern Canada 92.0 92.0 92.0 92.0

92.0 92.0 92.0 92.0

Table IV-6

U.S. and Canadian Utilization Rates

MBPD
106

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 1,022 1,077 1,083 1,083 55 62 62

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 188 194 192 192 6 3 4

1,210 1,271 1,274 1,275 61 65 66

Products

Propane/Propylene 34 39 38 39 5 4 5

Normal Butane 2 6 12 12 4 10 10

Isobutane -1 0 3 4 1 4 5

Gasoline 584 643 620 624 59 36 40

Jet/Kerosene 73 91 84 83 18 11 10

Distillate 361 345 323 320 -16 -38 -41

Resid/Asphalt 116 104 101 102 -12 -15 -14

Other2 92 92 140 137 0 48 45

1,261 1,319 1,322 1,320 58 61 59

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Yearly Volumes, MBPD Change from 2013, MBPD

Table IV-7

PADD I Charge and Yield Data
107

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 3,353 3,659 3,736 3,736 306 383 382

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 669 686 686 687 17 17 18

4,022 4,345 4,422 4,424 323 400 401

Products

Propane/Propylene 107 116 121 122 9 14 15

Normal Butane 4 6 16 15 2 12 11

Isobutane -1 -3 7 6 -2 8 7

Gasoline 2,319 2,498 2,501 2,511 180 183 192

Jet/Kerosene 223 273 279 283 50 56 60

Distillate 1,013 1,069 1,079 1,080 56 66 67

Resid/Asphalt 195 203 172 173 8 -23 -22

Other2 365 381 433 419 16 68 54

4,225 4,544 4,609 4,609 320 384 384

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-8

PADD II Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
108

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 7,761 8,250 8,447 8,432 489 685 670

Crude to Splitters 68 158 293 518 90 225 450

Other Feedstocks1 1,442 1,446 1,451 1,455 5 10 13

9,271 9,854 10,191 10,405 583 919 1,133

Refinery Products

Propane/Propylene 369 380 384 388 11 15 19

Normal Butane 48 75 82 92 27 34 44

Isobutane -1 6 12 12 7 13 13

Gasoline 4,216 4,264 4,316 4,351 48 100 134

Jet/Kerosene 760 824 856 809 64 96 49

Distillate 2,721 2,786 2,870 2,869 65 149 148

Resid/Asphalt 351 368 368 381 17 17 30

Other2 1,366 1,632 1,677 1,653 266 311 287

9,830 10,335 10,565 10,554 505 735 724

Splitter/Hydroskimmer Products

LPG 4 9 16 29 5 10 16

Light Naphtha 17 35 64 114 18 41 63

Naphtha 22 46 85 151 25 55 84

Unfinished Distillate 18 44 82 145 26 55 83

Gas Oil 6 23 44 78 17 34 48

68 158 293 518 90 195 295

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-9

PADD III Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
109

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 569 605 659 659 36 90 90

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 53 55 55 55 2 2 2

622 660 714 714 38 92 92

Products

Propane/Propylene 9 10 11 11 1 2 2

Normal Butane 2 3 4 5 1 2 3

Isobutane -1 0 1 1 1 2 2

Gasoline 320 340 341 343 21 21 23

Jet/Kerosene 26 35 47 62 9 21 36

Distillate 194 200 213 217 6 19 23

Resid/Asphalt 44 46 50 26 2 6 -18

Other2 52 52 77 84 0 25 32

646 686 743 747 40 98 102

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-10

PADD IV Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
110

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 2,303 2,374 2,484 2,499 72 181 196

Crude to Splitters 0 0 0 0 0 0 0

Other Feedstocks1 591 596 603 604 5 12 13

2,894 2,969 3,087 3,103 76 193 209

Products

Propane/Propylene 45 48 55 56 3 10 11

Normal Butane 8 10 13 13 2 5 5

Isobutane -1 -3 -2 -2 -2 -1 -1

Gasoline 1,600 1,647 1,725 1,737 47 125 137

Jet/Kerosene 414 428 443 443 14 29 29

Distillate 568 575 586 590 7 18 22

Resid/Asphalt 130 131 132 132 1 2 2

Other2 313 315 314 314 2 1 1

3,077 3,151 3,266 3,282 75 190 206

Splitter/Hydroskimmer Products

LPG 0 0 0 0 0 0 0

Light Naphtha 0 0 0 0 0 0 0

Naphtha 0 0 0 0 0 0 0

Unfinished Distillate 0 0 0 0 0 0 0

Gas Oil 0 0 0 0 0 0 0

0 0 0 0 0 0 0

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-11

PADD V Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
111

2013 2015 2020 2025 2015 2020 2025

Feedstocks

Crude to Refineries 15,008 15,965 16,409 16,409 958 1,401 1,400

Crude to Splitters 68 158 293 518 90 225 450

Other Feedstocks1 2,943 2,977 2,987 2,993 34 44 50

18,019 19,100 19,689 19,920 1,082 1,670 1,900

Products

Propane/Propylene 564 593 609 616 29 45 52

Normal Butane 64 100 127 137 36 63 73

Isobutane -5 0 21 20 5 26 25

Gasoline 9,038 9,392 9,503 9,565 354 465 527

Jet/Kerosene 1,496 1,651 1,710 1,680 155 214 184

Distillate 4,857 4,976 5,070 5,075 119 213 218

Resid/Asphalt 836 851 824 813 15 -12 -23

Other2 2,188 2,472 2,642 2,607 284 454 419

19,038 20,035 20,505 20,512 997 1,467 1,474

Splitter Products

LPG 4 9 16 29 5 10 16

Light Naphtha 17 35 64 114 18 41 63

Naphtha 22 46 85 151 25 55 84

Unfinished Distillate 18 44 82 145 26 55 83

Gas Oil 6 23 44 78 17 34 48

68 158 293 518 90 195 295

1. Includes butane, isobutane, naphtha, gas oil, fuel oil, ethanol, hydrogen, and other finished and 

 unfinished intermediate products.

2. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-12

U.S. Charge and Yield Data

Yearly Volumes, MBPD Change from 2013, MBPD
112

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 584 3,139 -2,555 643 3,128 -2,486 620 2,938 -2,318 624 2,742 -2,118

Jet/Kerosene 73 404 -331 91 408 -317 84 407 -323 83 410 -327

Distillate 361 1,187 -826 345 1,227 -882 323 1,262 -938 320 1,278 -959

Residual Fuel 66 120 -54 54 111 -57 51 104 -52 52 106 -55

Other1 177 460 -283 187 433 -247 243 489 -246 242 527 -285

1,261 5,309 -4,048 1,319 5,308 -3,989 1,322 5,200 -3,878 1,320 5,063 -3,743

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

2020 2025

Table IV-13

PADD I Refinery Product Supply and Demand Balance - MBPD

2013 2015
113

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 2,319 2,402 -83 2,498 2,393 105 2,501 2,199 302 2,511 2,027 484

Jet/Kerosene 223 267 -44 273 270 3 279 270 10 283 269 13

Distillate 1,013 1,174 -161 1,069 1,239 -170 1,079 1,308 -229 1,080 1,335 -256

Residual Fuel 48 36 12 56 14 42 25 14 11 26 15 10

Other1 622 1,003 -381 648 1,032 -383 724 1,114 -390 709 1,159 -449

4,225 4,881 -657 4,544 4,948 -403 4,609 4,905 -296 4,609 4,806 -198

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-14

PADD II Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
114

Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus

Gasoline 4,216 1,361 2,855 4,264 1,358 2,906 4,316 1,313 3,003 4,351 1,249 3,102

Jet/Kerosene 760 264 496 824 267 558 856 276 580 809 283 525

Distillate 2,721 786 1,935 2,786 835 1,951 2,870 923 1,947 2,869 959 1,910

Residual Fuel 281 102 179 298 74 224 298 64 234 311 68 242

Other2 1,920 2,559 -639 2,320 2,643 -323 2,518 3,063 -546 2,732 3,357 -625

9,898 5,072 4,826 10,493 5,176 5,317 10,858 5,640 5,218 11,071 5,917 5,155

1. Supply includes production from splitters and hydroskimmers.

2. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-15

PADD III Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
115

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 320 302 17 340 301 39 341 299 42 343 291 52

Jet/Kerosene 26 38 -12 35 39 -3 47 39 7 62 40 22

Distillate 194 167 27 200 177 23 213 185 27 217 192 25

Residual Fuel 11 2 9 13 2 11 17 2 15 -7 2 -9

Other1 95 68 27 98 71 27 127 117 9 133 132 1

646 577 69 686 589 97 743 642 101 747 656 91

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-16

PADD IV Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
116

Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus Supply Demand Surplus

Gasoline 1,600 1,505 94 1,647 1,500 147 1,725 1,448 277 1,737 1,371 366

Jet/Kerosene 414 447 -33 428 451 -24 443 462 -18 443 470 -27

Distillate 568 565 3 575 590 -15 586 633 -47 590 655 -65

Residual Fuel 111 120 -9 112 95 17 113 93 19 113 95 18

Other1 384 356 28 389 331 58 400 442 -42 400 489 -88

3,077 2,993 83 3,151 2,967 184 3,266 3,077 189 3,282 3,080 202

1. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-17

PADD V Refinery Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
117

Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus Supply1 Demand Surplus

Gasoline 9,038 8,710 328 9,392 8,680 712 9,503 8,196 1,306 9,565 7,679 1,886

Jet/Kerosene 1,496 1,419 77 1,651 1,434 217 1,710 1,455 255 1,680 1,473 206

Distillate 4,857 3,878 979 4,976 4,068 907 5,070 4,311 760 5,075 4,420 655

Residual Fuel 517 380 137 532 294 237 505 277 227 494 287 206

Other2 1,677 2,125 -449 2,121 2,192 -71 2,490 2,541 -51 2,696 2,753 -57

17,585 16,513 1,072 18,672 16,670 2,002 19,277 16,780 2,497 19,509 16,612 2,897

NGLs 2,606 2,320 286 3,467 2,318 1,149 5,357 2,684 2,673 5,645 2,910 2,735

Total Products 20,191 18,833 1,358 22,139 18,988 3,151 24,634 19,464 5,170 25,154 19,522 5,631

1. Supply includes production from splitters and hydroskimmers.

2. Includes aviation gasoline, gasoline blending components, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-18

U.S. Product Supply and Demand Balance - MBPD

2013 2015 2020 2025
118

I II III IV V Export WC EC Export Total I II III IV V Export WC EC Export Total

2013 2015-2013

Northeast 38 63 101 Northeast -2 -19 0 0 0 0 0 0 0 -21

Gulf Coast 25 2,546 25 2,596 Gulf Coast 0 20 1,343 0 0 0 0 0 0 1,363

Midcontinent 599 599 Midcontinent 0 -210 0 0 0 0 0 0 0 -210

Southwest 350 1,296 1,646 Southwest 0 618 -187 0 0 0 0 0 0 431

Rocky Mountain 168 566 150 316 90 108 1,398 Rocky Mountain 378 133 -150 37 185 0 0 224 0 807

California 603 603 California 0 0 0 0 41 0 0 0 0 41

Alaska 515 515 Alaska 0 0 0 0 -65 0 0 0 0 -65

W. Canada 110 1,733 182 253 198 613 329 3,418 W. Canada 0 -194 354 -1 2 0 0 202 0 363

E. Canada 103 129 232 E. Canada -5 0 0 0 0 0 0 0 0 -5

Foreign 577 43 3,654 0 897 1 0 517 5,690 Foreign -315 -43 -781 0 -91 -1 0 -426 0 -1,658

Total 1,022 3,354 7,829 569 2,303 1 613 1,108 16,798 Total 55 306 579 36 72 -1 0 0 1,047

2015 2020-2015

Northeast 36 44 80 Northeast -3 -1 0 0 0 0 0 0 0 -4

Gulf Coast 25 20 3,889 25 3,959 Gulf Coast 423 -20 943 0 0 255 0 0 0 1,601

Midcontinent 389 389 Midcontinent 0 91 0 0 0 0 0 0 0 91

Southwest 968 1,109 2,077 Southwest 0 -53 711 0 198 0 0 0 0 855

Rocky Mountain 546 699 353 275 332 2,205 Rocky Mountain -242 247 78 46 603 0 0 193 0 925

California 644 644 California 0 0 0 0 45 0 0 0 0 45

Alaska 450 450 Alaska 0 0 0 0 -390 358 0 0 0 -32

W. Canada 110 1,539 537 252 199 613 531 3,781 W. Canada 15 -187 185 8 -70 0 46 -148 879 728

E. Canada 98 129 227 E. Canada 31 0 0 0 0 0 0 5 0 36

Foreign 262 2,873 806 91 4,032 Foreign -218 0 -1,052 0 -276 0 0 -50 0 -1,596

Total 1,077 3,659 8,408 605 2,374 0 613 1,108 17,845 Total 6 77 865 54 110 613 46 0 2,650

2020 2025-2020

Northeast 33 43 76 Northeast -2 23 0 0 0 0 0 0 0 21

Gulf Coast 448 4,833 255 25 5,561 Gulf Coast -62 0 -1,201 0 0 1,156 0 0 0 -107

Midcontinent 480 480 Midcontinent 0 216 0 0 0 0 0 0 0 216

Southwest 915 1,820 198 2,933 Southwest 0 -615 1,026 0 32 195 0 0 0 638

Rocky Mountain 304 946 78 400 878 525 3,131 Rocky Mountain 158 352 21 176 -2 0 0 0 0 706

California 688 688 California 0 0 0 0 36 0 0 0 0 36

Alaska 60 358 418 Alaska 0 0 0 0 0 -100 0 0 0 -100

W. Canada 125 1,352 722 260 129 659 383 879 4,508 W. Canada -22 23 789 -177 -27 0 0 3 271 860

E. Canada 129 134 263 E. Canada -114 0 0 0 0 0 0 -27 53 -88

Foreign 44 1,821 530 41 2,436 Foreign 42 0 -674 0 -24 0 0 24 0 -632

Total 1,083 3,736 9,273 659 2,484 613 659 1,108 20,495 Total 0 0 -39 -1 15 1,251 0 0 1,550

2025 2025-2013

Northeast 31 66 97 Northeast -7 3 0 0 0 0 0 0 0 -3

Gulf Coast 386 3,632 1,411 25 5,454 Gulf Coast 361 0 1,086 0 0 1,411 0 0 0 2,858

Midcontinent 697 697 Midcontinent 0 98 0 0 0 0 0 0 0 98

Southwest 300 2,845 230 195 3,570 Southwest 0 -50 1,549 0 230 195 0 0 0 1,924

Rocky Mountain 462 1,298 99 576 876 525 3,837 Rocky Mountain 294 732 -51 260 786 0 0 417 0 2,438

California 725 725 California 0 0 0 0 122 0 0 0 0 122

Alaska 60 258 318 Alaska 0 0 0 0 -455 258 0 0 0 -197

W. Canada 103 1,375 1,511 83 102 659 386 1,150 5,369 W. Canada -7 -358 1,329 -170 -96 0 46 57 1,150 1,951

E. Canada 15 107 53 175 E. Canada -88 0 0 0 0 0 0 -22 53 -57

Foreign 86 1,147 506 65 1,804 Foreign -491 -43 -2,507 0 -391 -1 0 -452 0 -3,886

Total 1,083 3,736 9,234 659 2,499 1,864 659 1,108 1,203 22,045 Total 62 382 1,405 90 196 1,863 46 0 5,247

Table IV-19

U.S. Canada U.S. Canada

Crude Oil Flows, MBPD
119

Planned Required

Movements Rail Rail Cap.

by Rail Capacity Additions

2013 278 555 - - 

2015 656 1,320 - - 

2020 429 - - - - 

2025 565 - - - - 

Comments

- Movements by rail into PADD I are expected to rise by nearly 378 MBPD from 2013 to 2015.

- Existing rail off-loading capacity exceeds forecast rail capacity requirements.

- Projected rail expansion plans appear to be on track to keep pace with desired movements into PADD I.

- See Appendix 1 for existing and planned PADD I rail offloading facilities.

Planned

Movements

by Water

2013 25

2015 25

2020 448

2025 386

Comments

- Movements by vessel into PADD I are expected to rise by over 420 MBPD from 2013 to 2020.

- Forecast waterborne movements exceed current Jones Act vessel capabilities.

- Substantial coastwise compliant vessel additions will be necessary to achieve forcast movement requirements.

- Current pipeline and rail delivery systems from the Gulf Coast, the Southwest and Canada are sufficient to meet

 crude demand requirements through 2025.

Table IV-20

Required Crude Oil Logistic Improvements, MBPD

Rail Movements into PADD I

Crude Movements into PADD II

Vessel Movements into PADD I
120

Table IV-20

Required Crude Oil Logistic Improvements, MBPD

Movements

Southwest Local/P II/P V to Indirect

Production Demand Gulf Coast Direct (via Cushing) Total Surplus

2013 1,646 792 854 363 525 888 33

2015 2,077 1,433 645 925 525 1450 805

2020 2,933 1,578 1,355 1225 525 1750 395

2025 3,570 995 2,576 1225 525 1750 -826

Comments

- The Permian Basin largely became debottlenecked with the startup of the Magellan Longhorn pipeline in 2013.

- Permian Basin volumes will shift into PADD II in 2015 to replace declining Midcontinent production.

- Movements to the Gulf Coast will peak in 2025 at nearly 2.6 million BPD.

- Pipeline capacity from the Permian Basin to the Gulf Coast is projected to exceed movements through 2020.

- A pipeline shortfall of 0.8 million BPD of capacity will develop by 2025.

- See Appendix 2 for existing and planned Permian Basin exit pipelines.

Western Rocky

Canada Mountains Total Capacity Surplus

2013 182 150 332 550 218

2015 537 0 537 1,550 1,013

2020 722 78 800 2,210 1,410

2025 1,511 99 1,610 2,210 600

Comments

- Crude movements to the Gulf Coast will rise from 332 MBD in 2013 to 1.6 million BPD by 2025.

- Existing pipeline capacity out of Cushing/Patoka is 1.55 million BPD and will rise to 2.21 million BPD by 2017.

- See Appendix 3 for existing and planned pipelines from Cushing, OK and Patoka, IL to the Gulf Coast.

- Current pipeline delivery systems from the Rocky Mountains and Western Canada are sufficient to meet crude

 demand requirements through 2025.

Movements to the Gulf Coast Pipeline Capacity, South of

Cusking, OK and Patoka, IL

Crude Movements into PADD IV

Pipeline Movements from Western Canada and the Rocky Mountains to the Gulf Coast

Pipelines from the Permian Basin with access the USGC

Pipeline Movements from Southwest to the Gulf Coast
121

Table IV-20

Required Crude Oil Logistic Improvements, MBPD

Planned Required

Movements Rail Rail Cap.

by Rail Capacity Additions

2013 90 148 - - 

2015 275 370 - - 

2020 1,076 - - 706 - 1,782

2025 1,106 - - 736 - 1,842

Comments

- Movements by rail into PADD V are expected to rise from 90 MBPD in 2013 to over 1.1 million BPD in 2025.

- Existing rail off-loading capacity exceeds short term rail capacity requirements.

- Projected rail expansion plans appear to be insufficient to meet required movements in 2020 - 2025.

- See Appendix 4 for existing and planned PADD V rail offloading facilities.

to the to Eastern Rail

U.S. Can./Exports Total Pipelines Movements Total Surplus

2013 2,476 329 2,805 3,568 120 3,688 883

2015 2,637 531 3,168 3,656 593 4,249 1,081

2020 2,587 1,262 3,849 3,918 750 4,668 819

2025 3,174 1,536 4,710 3,918 750 4,668 -42

Comments

- Movements out of Western Canada are expected to rise from 2.8 million BPD in 2013 to 4.7 million BPD in 2025.

- Existing exit pipeline capacity out of Western Canada is 3.6 million BPD.

- The Enbridge Alberta Clipper pipeline is viewed as highly likely with a capacity of 350 MBPD and a startup

 date in 3Q2015.

- Four other major exit pipelines are being discussed (see Appendix 5).

- At least one of these four new pipelines will need to be in place by 2025 to achieve the Canadian

 production forecast.

- Incremental movements to the U.S. between 2013 and 2025 are 698 MBPD.

- The Alberta Clipper (350 MBPD) and rail (630 MBPD) will add 980 MBPD of capacity.

- Construction of the Energy East or Northern Gateway pipelines by 2025 will be required to meet Canadian

 export requirements.

Crude Movements out of Western Canada

Crude Movements out of Western Canada Existing Exit Capacity with the Alberta Clipper

Rail Movements into PADD V
122

2013 2015 2020 2025 Comments

PADD I -2,555 -2,486 -2,318 -2,118 - Reduced utilization of Colonial/Plantation systems.

PADD II -83 105 302 484 - Increased movements into PADD I from Ohio and into PADD III

 for export via Mississippi River.

PADD III 2,855 2,906 3,003 3,102 - Likely origin of PADD I-IV exports (increase of 1.3 million BPD).

PADD IV 17 39 42 52 - Surplus volumes to be moved into PADDs II and V.

PADD V 94 147 277 366 - Incremental 272 MBPD to be exported.

Total U.S. 328 712 1,306 1,886

Conclusions

- No incremental requirements for Colonial/Plantation systems.

- Modest pipeline upgrades to be made in moving PADD II volumes from Ohio into western Pennsylvania.

- The most significant logistic improvements to be focused on product exports (which are increasing by 1.6 million BPD).

- Exports will be primarilly from PADD III but also from PADD V.

Table IV-21

Gasoline Supply and Demand Balance - MBPD
123

2013 2015 2020 2025 Comments

PADD I -331 -317 -323 -327

PADD II -44 3 10 13 - Increased movements into PADD I from Ohio and into PADD III

 for export via Mississippi.

PADD III 496 558 580 525

PADD IV -12 -3 7 22 - Surplus volumes to be moved into PADDs II and V.

PADD V -33 -24 -18 -27

Total U.S. 77 217 255 206

Conclusions

- No incremental requirements for Colonial/Plantation systems.

- Modest pipeline upgrades to be made in moving PADD II volumes from Ohio into western Pennsylvania.

- No significant logistics improvements required for Jet/Kerosene movements.

Table IV-22

Jet/Kerosene Supply and Demand Balance - MBPD
124

2013 2015 2020 2025 Comments

PADD I -826 -882 -938 -959 - Increased usage of Colonial/Plantation systems.

PADD II -161 -170 -229 -256 - Shortfall grows slightly, requires greater receipts from

 PADD III.

PADD III 1,935 1,951 1,947 1,910 - Surplus remains constant. Movements to PADDs I and II

 and exports.

PADD IV 27 23 27 25 - Surplus volumes to be moved into PADDs II and V.

PADD V 3 -15 -47 -65 - Modest shortfall developing in PADD V.

Total U.S. 979 907 760 655

Conclusions

- Movements from PADD III to Padd I increase by 133 MBPD from 2013 to 2025. Surplus capacity will exist on Colonial/Plantation

 systems due to reduction of gasoline movements by 437 MBPD.

- Movements from PADD III to PADD II will increase slightly (Explorer Pipeline).

- Exports will decline by 324 MBPD as internal demand grows faster than production.

- No significant logistics improvements required for Distillate movements.

Table IV-23

Distillate Supply and Demand Balance - MBPD
125

2013 2015 2020 2025 Comments

PADD I -54 -57 -52 -55

PADD II 12 42 11 10

PADD III 179 224 234 242 - Incremental 63 MBPD to be exported.

PADD IV 9 11 15 -9

PADD V -9 17 19 18

Total U.S. 137 237 227 206

Conclusions

- No significant logistics improvements required for Residual Fuel movements.

Table IV-24

Residual Fuel Supply and Demand Balance - MBPD
126

2013 2015 2020 2025 Comments

PADD I -283 -247 -246 -285

PADD II -381 -383 -390 -449

PADD III -639 -323 -546 -625 - Splitter and hydroskimmer products offset by NGL growth.

PADD IV 27 27 9 1

PADD V 28 58 -42 -88

Total Refining -1,248 -868 -1,215 -1,446

Adjustments -1521 -1521 -1521 -1521

NGL Demand 2,320 2,318 2,684 2,910

Total U.S. -449 -71 -51 -57

Conclusions

- Increase in Other shortfall is predominantly the result of increased Natural Gas Liquids (NGLs) production.

- NGL logistics are being developed in conjunction with increased natural gas drilling.

- Logistic requirements for Other refining products (non-NGLs) are not viewed to be significant.

1. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-25

Other Products1 Supply and Demand Balance - MBPD
127

2013 2015 2020 2025 Comments

PADD I -4,048 -3,989 -3,878 -3,743 - PADD I product shortfall to decline by over 300 MBPD.

PADD II -657 -403 -296 -198 - PADD II product shortfall to deline by 459 MBPD.

PADD III 4,826 5,317 5,218 5,155 - PADD III exports to rise by around 1.7 million BPD.

PADD IV 69 97 101 91 - PADD IV movements generally flat.

PADD V 83 184 189 202 - PADD V exports to rise by 119 MBPD.

Total Refining 273 1,205 1,334 1,507

Adjustments -1521 -1521 -1521 -1521

NGL Demand 2,320 2,318 2,684 2,910

Total U.S. 1,072 2,002 2,497 2,897

Conclusions

- No major product infrastructure improvements are necessary for movements between PADDs.

- Logistic improvements will be necessary for the incremental export of over 1.8 million BPD between 2013 and 2025.

Table IV-26

Total U.S. Refined Products Supply and Demand Balance - MBPD
128

2013 2015 2020 2025 Likely Destinations

Crude Exports from the U.S.

Gulf Coast

Light Sweet 255 480 Europe, Latin America

Light Sour 177 Europe, Latin America

Ultra Light Sweet 754 Far East, Europe

Condensate 25 25 25 25 Canada

25 25 280 1,436

Southwest

Light Sweet 195 Europe, Latin America

Rocky Mountains

Ultra Light Sweet 108 332 525 525 Canada

Alaska

Medium 358 258 Far East

Total U.S. 133 357 1,163 2,414

Crude Exports from Canada*

Western Canada

Super Light 33 36 Dependent on export pipeline:

Light Sweet 498 580 Far East if TransMountain or

Light Sour 89 150 Northern Gateway. Europe/

Medium 259 384 Latin America if Energy East.

879 1,150

Eastern Canada

Light Sweet 53 Europe

Total Canada 879 1,203

Total U.S. and Canada 133 357 2,042 3,617

* Excluding movements to the U.S.

Table IV-27

U.S. and Canadian Crude Oil Exports - MBPD
129

2013 2015 2020 2025 Likely Destinations

Refined Products

Gasoline 328 712 1,306 1,886 Mexico, other Latin America

Jet/Kerosene 77 217 255 206 Canada, Mexico, other Latin America

Distillate 979 907 760 655 Mexico, other Latin America, Europe

Residual Fuel 137 237 227 206 East Asia, Latin America, Europe

Other1 -449 -71 -51 -57 Latin America, Europe, East Asia

1,072 2,002 2,497 2,897

NGLs 286 1,149 2,673 2,735 Canada, Mexico, Latin America

Total Exports 1,358 3,151 5,170 5,631

1. Includes aviation gasoline, petrochemical feedstocks, naphtha, lubricants, waxes, petroleum coke,

 refinery gas and other miscellaneous products.

Table IV-28

U.S. Product Exports - MBPD
130

Crude Price Forecast

High Production Export Case

(current dollars per barrel)

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

BENCHMARKS

Brent (Sullom Voe) 102.78 98.84 97.49 94.14 94.41 97.82 101.47 105.61 109.74 114.03 119.52

LLS (St. James) 100.58 96.94 95.95 92.86 93.14 96.53 100.12 104.15 108.25 112.38 117.72

WTI (Cushing) 95.71 92.03 91.01 87.87 88.12 91.48 95.02 99.00 103.04 107.11 112.38

Bakken (Clearbrook) 91.28 87.67 86.65 83.59 83.83 87.21 90.77 94.76 98.77 102.69 107.72

Maya (FOB) 89.29 85.91 83.93 80.41 80.38 83.51 86.70 89.61 93.07 96.71 101.55

Canadian WCS (Hardisty) 82.24 78.69 76.70 73.06 73.16 76.07 79.29 82.09 85.45 89.00 93.75

DIFFERENTIALS

Brent - LLS 2.15 1.51 1.14 0.88 0.87 0.89 0.95 1.05 1.09 1.25 1.40

LLS - WTI 4.87 4.91 4.94 4.98 5.02 5.06 5.10 5.15 5.21 5.27 5.34

WTI - Bakken 4.43 4.36 4.35 4.29 4.29 4.27 4.25 4.25 4.27 4.42 4.66

LLS - Maya 11.29 11.03 12.02 12.45 12.76 13.02 13.42 14.54 15.17 15.67 16.17

Maya - WCS 7.05 7.22 7.23 7.35 7.22 7.45 7.41 7.52 7.63 7.71 7.80

Table IV-29
131

Number Tab Table Name

Appendix 1 Appendix 1 PADD I Rail Offloading Facilities

Appendix 2 Appendix 2 Permian Basin Exit Pipelines

Appendix 3 Appendix 3 Cushing, OK and Patoka, IL Exit Pipelines

Appendix 4 Appendix 4 PADD V Rail Offloading Facilities

Appendix 5 Appendix 5 Western Canada Exit Pipelines

Implications of Increasing U.S. Light Tight Oil Production

Appendix Tables
132

Capacity

Company Location MBPD Online

Online in 2012

Global Energy Partners Albany, NY 160 2012

Buckeye Partners Albany, NY 130 2012

Plains All American Yorktown, VA 130 2012

Sunoco Logistics Westville, NJ 70 2012

United Refining Warren, PA 65 2012

555

Online in 2013/2014

PBF Energy Delaware City, DE 210 2013

Monroe Energy Trainer, PA 60 1H2013

Phillips 66 Linden, NJ 60 1H2013

Philadelphia Energy Solutions Philadelphia, PA 240 1H2013

Enbridge/Canopy Eddystone, PA 80 2Q2014

Phillips 66 Linden, NJ 50 2Q2014

PBF Energy Delaware City, DE 65 2Q2014

765

Proposed Additions

Global Energy New Windsor, NY 70 TBD

Enbridge/Canopy Eddystone, PA 80 TBD

Appendix 1

PADD I Rail Offloading Facilities
133

Capacity

Company Pipeline MBPD Startup Destination

Existing Direct Pipelines

Sunoco * West Texas Gulf 250 Houston/Nederland, TX

Magellan Longhorn 225 2Q2013 Houston, TX

475

Existing Indirect Pipelines

Plains Basin 450 Cushing, OK

Oxy Centurion 75 Cushing, OK

525

Planned Pipelines

Magellan Longhorn Expansion 50 3Q2014 Houston, TX

Oxy/Magellan BridgeTex 300 4Q2014 Houston, TX

Sunoco Permian Express II 200 3Q2015 Nederland/Beaumont, TX

Plains All American Cactus 200 3Q2015 Gardendale/Corpus Christi, TX

750

* The Sunoco West Texas Gulf pipeline also supplies the Mid-Valley pipeline into PADD II (not included).

Appendix 2

Permian Basin Exit Pipelines
134

Company Pipeline Startup Origin Destination Capacity

Existing Pipelines

Enbridge/Enterprise Seaway I 2Q2012 Cushing, OK Houston/Beaumont, TX 150

Seaway II 4Q2012 Cushing, OK Houston/Beaumont, TX 250

TransCanada Keystone 1Q2014 Cushing, OK Houston/Nederland, TX 700

Seaway III 4Q2014 Cushing, OK Houston/Beaumont, TX 450

1,550

Planned Pipelines

Enbridge/Energy Transfer Trunkline 2H2016 Patoka, IL St. James, LA 660

Total Capacity 2,210

Appendix 3

Cushing, OK and Patoka, IL Exit Pipelines
135

Capacity

Company Location MBPD Online

Online in 2012

Tesoro Anacortes, WA 50 2012

U.S. Oil Tacoma, WA 40 2012

Westway Terminal Co. Port of Grays, WA 10

Imperium Terminal Services Port of Grays, WA 10

Tesoro Martinez, CA 12 2012

Alon Long Beach, CA 12 2012

Alon Paramount, CA 14 2012

148

Online in 2013/2014

Global Partners Port of St. Helens, OR 30 1H2013

BP Cherry Point, WA 20 1H2014

Kinder Morgan Richmond, CA 72 2Q2014

Phillips 66 Ferndale, WA 30 4Q2014

Plains Bakersfield, CA 70 4Q2014

222

Proposed Additions

Savage/Tesoro Vacouver, WA 380 2H2015

Alon Bakersfield, CA 125 4Q2015

U.S. Development Port of Grays, WA 45 1H2016

Phillips 66 Rodeo, CA 30 1Q2016

Valero Benicia, CA 40 1Q2016

Questar Paramount, CA tbd 3Q2016

Targa Stockton, CA 40 2016

NuStar Energy Vancouver, WA 50 tbd

Shell Anacortes, WA tbd tbd

WesPac Pittsburg, CA 242 tbd

Westway Terminals Port of Grays, WA tbd tbd

Imperium Terminal Services Port of Grays, WA tbd tbd

952

Appendix 4

PADD V Rail Offloading Facilities
136

Company Pipeline Origin Destination Capacity Startup

Existing Pipelines

TransCanada Keystone Hardisty, AB Houston/Nederland,TX 590

Enbridge Line 1 Edmonton, AB Cushing, OK, PADD II, E. Canada 1,865

Enbridge Line 67 Hardisty, AB Cushing, OK, PADD II, E. Canada 450

Plains Rangeland Edmonton, AB PADD IV 83

Spectra Express Hardisty, AB Casper, WY and Wood River, IL 280

Kinder Morgan Trans Mountain Edmonton, AB Anacortes, WA 300

3,568

Proposed Pipelines

Enbridge Alberta Clipper Hardisty, AB Superior, WI 350 3Q2015

Kinder Morgan Trans Mountain Exp. Edmonton, AB Anacortes, WA 590 2018+

TransCanada Energy East Hardisty, AB St. John, NB 1,100 2018+

TransCanada Keystone XL Hardisty, AB Steele City, NE 800 2018+

Enbridge Northern Gateway Broderheim, AB Kitimat, BC 525 2018+

3,365

Appendix 5

Western Canada Exit Pipelines