POTENTIAL SUPPLY AND COST IMPACTS 

OF LOWER SULFUR, LOWER RVP 

GASOLINE 

PREPARED FOR 

THE AMERICAN PETROLEUM INSTITUTE 

JULY 2011 

David C. Tamm 

Kevin P. Milburn 

Richard X. Thomas 
- i - 

TABLE OF CONTENTS

I. ABSTRACT .................................................................................................... 1

II. INTRODUCTION ............................................................................................ 3

III. EXECUTIVE SUMMARY ................................................................................ 5

REGULATORY ASSUMPTIONS .................................................................... 8

TECHNOLOGY AND INVESTMENT COSTS ................................................. 9

ANALYTICAL BASIS .................................................................................... 10

STUDY RESULTS ........................................................................................ 11

IV. REGULATORY ASSUMPTIONS .................................................................. 17

GREENHOUSE GAS EMISSIONS ............................................................... 20

OTHER REGULATIONS .............................................................................. 20

V. GASOLINE CONSUMPTION FORECAST ................................................... 21

VI. TECHNOLOGY AND CAPITAL INVESTMENT COSTS ............................... 22

FRACTIONATION ........................................................................................ 22

FCC FEED AND GASOLINE DESULFURIZATION ..................................... 22

CAPITAL COSTS FOR GRASSROOTS UNITS ........................................... 23

REVAMP/EXPANSION COSTS ................................................................... 24

NATURAL GAS LIQUID (NGL) STORAGE AND LOADING COSTS ........... 24

OTHER OFF-SITE CAPITAL COSTS .......................................................... 25

CONTINGENCY ALLOWANCE .................................................................... 25

CAPITAL INVESTMENT CHARGE .............................................................. 25

VII. INPUT COSTS ............................................................................................. 26

NATURAL GAS COST ................................................................................. 26

HYDROGEN COSTS ................................................................................... 26

VIII. ANALYTICAL BASIS .................................................................................... 27

REFINERY MODELING ............................................................................... 27

REFINERY CAPACITY AND UTILIZATION ................................................. 28

CRUDE SLATE ............................................................................................ 29

SEASONALITY ............................................................................................. 29

CALIFORNIA REFINERIES.......................................................................... 30

DISPOSITION OF EXCESS NGLS .............................................................. 30
- ii - 

REDUCE NGL IMPORTS .................................................................. 30

DISPLACE OTHER ETHYLENE CRACKER FEEDSTOCKS ............ 30

EXPORT MARKETS .......................................................................... 32

CONSUME OR SELL AS FUEL OR HYDROGEN FEEDSTOCK ...... 33

ALKYLATION ..................................................................................... 33

STOCKPILE FOR WINTER CONSUMPTION ................................... 33

NGLS TRANSPORTATION ............................................................... 34

VALUATION OF EXCESS NGLS ................................................................. 35

COMPLIANCE RESPONSE ......................................................................... 36

OTHER GASOLINE SUPPLY ....................................................................... 38

IMPORTS ..................................................................................................... 38

ETHANOL QUALITY .................................................................................... 38

IX. STUDY RESULTS ........................................................................................ 39

BASE CASE GASOLINE SUPPLY BALANCE AND REFINERY 

OPERATIONS .............................................................................................. 39

COMPLIANCE RESPONSE ......................................................................... 40

STUDY AND SENSITIVITY CASES GASOLINE SUPPLY BALANCE 

AND REFINERY OPERATIONS .................................................................. 42

DISPOSITION OF SURPLUS NGLS ............................................................ 44

GREENHOUSE GAS EMISSIONS ............................................................... 48

TOTAL COMPLIANCE COSTS .................................................................... 49

COMPARISON TO AAM REPORT .............................................................. 51

X. CONCLUSIONS ........................................................................................... 53
- 1 - 

I. ABSTRACT

A proposal has been made by the Alliance of Automobile Manufacturers for a 

single national (excluding California) summertime gasoline specification that they 

referred to as National Clean Gasoline (NCG). NCG, as proposed, would require 

significantly lower sulfur limits than current United States gasoline and, for much of the 

nation, also significantly lower limits on Reid vapor pressure (RVP). 

This report examines four potential scenarios with lower sulfur and lower RVP 

requirements than current gasoline specifications. In two, summertime RVP is reduced 

nationwide (excluding California) to 7 pounds per square inch absolute (psia). In the 

other two, summer time RVP’s are limited to 7.8 psia and 8.8 psia (including a 1 psia 

waiver for ethanol blending) in regions that currently allow the waiver for conventional 

gasoline. Reformulated gasoline (RFG) maintains an RVP of 7.0 psia. In three of the 

cases, sulfur in individual batches is limited to 20 parts per million (ppm) with a 

company annual average limit of 10 ppm. In one case, the sulfur limits are 10 and 5 

ppm, respectively. 

The results of the analysis show that four to seven refineries are likely to shut 

down rather than make the necessary investments to produce gasoline with lower sulfur 

and lower RVP specifications. A substantial volume of domestically-produced light 

hydrocarbon currently blended into gasoline would be removed from gasoline and would 

be sold into other markets. Total domestically-produced gasoline (excluding ethanol) is 

estimated to decrease by 0.6 to 1.3 million barrels per day during the summer. If 

gasoline consumption remains at Base Case levels, gasoline imports would more than 

double in three of the cases, leaving the U.S. more exposed to supply disruptions. 

Annualized marginal compliance costs for U.S. refineries are estimated in the range of 

12 to 25 cents per gallon. Summer-only costs are nearly double that of annualized 

costs. Additional hydrotreating and fractionation required to comply would result in an 
- 2 - 

increase in carbon dioxide (CO2) emission from refineries that continue to operate. On 

an annual average basis, the total increase in CO2 emissions at domestic and foreign 

refineries is estimated at 2.9 to 7.4 million tonnes per year. 
- 3 - 

II. INTRODUCTION

In 2009, the Alliance of Automobile Manufacturers published a report1 (the AAM 

Report) documenting purported costs and benefits of a single national standard for 

gasoline quality that would apply to all states except California. The AAM Report calls 

the new gasoline standard “National Clean Gasoline.” The American Petroleum 

Institute (API) engaged Baker and O’Brien, Inc. (Baker & O’Brien) to perform an 

independent analysis to determine the potential supply and cost impacts of lowering the 

specifications for sulfur and RVP in gasoline. This study was prepared by Baker and 

O’Brien using its own models and analysis. 

General industry conditions, corporate profiles, geographic considerations, and 

unique refinery characteristics can influence potential responses to regulatory 

requirements. Therefore, Baker & O’Brien undertook a refinery-by-refinery approach in 

evaluating the potential impacts of lowering the specifications for sulfur and RVP in 

gasoline. Compliance options were evaluated and production estimates calculated for 

each refinery using Baker & O’Brien’s PRISMTM Refining Industry Analysis modeling 

system. The PRISM model is based on publicly-available information, and incorporates 

Baker & O'Brien's industry experience and knowledge. 

Baker & O’Brien conducted this analysis and prepared this report with 

reasonable care and skill, utilizing methods we believe to be consistent with normal 

industry practice. No other representations or warranties, expressed or implied, are 

made by Baker & O’Brien. All results and observations are based on information 

available at the time of this report. To the extent that additional information becomes 

 

1

 Alliance of Automobile Manufacturers, “National Clean Gasoline: An Investigation of Costs and 

Benefits,” June 2009. TM PRISM is a trademark of Baker & O’Brien, Inc. All rights reserved. 
- 4 - 

available or the factors upon which our analysis is based change, our opinions could be 

subsequently affected. 
- 5 - 

III. EXECUTIVE SUMMARY

In 2009, the Alliance of Automobile Manufacturers published a report2 (the AAM 

Report) documenting purported costs and benefits of a single national standard for 

gasoline quality with significant reductions in sulfur and Reid vapor pressure (RVP) that 

would apply to all states except California. The AAM Report calls the new gasoline 

standard “National Clean Gasoline.” 

The American Petroleum Institute (API) engaged Baker and O’Brien, Inc. (Baker 

& O’Brien) to perform an independent analysis to determine the potential supply and 

cost impacts of lowering the specifications for sulfur and RVP in gasoline. A refinery-byrefinery analysis was performed that considered each refinery’s compliance options 

accounting for technical, strategic, market, and economic factors, and then estimated a 

likely response based on this information. It is believed this approach is superior to 

aggregate or notional-type modeling, given the likely variation in refinery response to 

regulation, based on each refinery’s unique position. 

Implementing a nationwide (except California) summer season 7 pounds per 

square inch (psia) RVP specification and sulfur limits of 20 parts per million (ppm) per 

gallon cap and 10 ppm company annual average (the Study Case) would remove a 

large quantity of natural gas liquids (NGLs)3

 from gasoline. Our modeling indicates that 

domestic gasoline production would decrease by 1,157 thousand barrels per calendar 

 

2

 Alliance of Automobile Manufacturers, “National Clean Gasoline: An Investigation of Costs and 

Benefits,” June 2009. 

3

 NGLs refer to a class of hydrocarbons in natural gas that are separated from the gas as liquids. NGLs 

include ethane, propane, butane, isobutane, and “Pentanes Plus.” Pentanes Plus is a term used by the 

U.S. Department of Energy to describe a mixture of mainly pentanes and heavier hydrocarbon which 

may contain some butanes and which is obtained from the processing of raw natural gas, condensate or 

crude oil. The term “Pentanes Plus” is sometimes used interchangeably with the terms condensates 

and natural gasoline. These hydrocarbons are also produced in refineries, and in this report the term 

NGLs is used to describe these hydrocarbons regardless of the source. 
- 6 - 

day (MB/CD) during the summer,4 this is equivalent to 14 percent (%) of projected 

summer 2016 hydrocarbon gasoline consumption.5 If gasoline consumption remains at 

Base Case levels, summer gasoline imports would need to increase by 125% from 923 

MB/CD in the Base Case to 2,080 MB/CD in the Study Case. It is not clear that this 

volume of gasoline with lower sulfur and lower RVP would be available from foreign 

refineries, and United States (U.S.) vulnerability to supply disruptions is obviously much 

greater in the Study Case. 

Three Sensitivity Cases were also examined. In the first, even lower sulfur limits 

were imposed, and the modeling indicates a further reduction in domestic gasoline 

production and a still greater need for imports. In the other two, sulfur levels were the 

same as in the Study Case and RVP limits were relaxed slightly in some regions. The 

relaxation of RVP limits in these cases increased gasoline production relative to the 

Study Case, but the lost gasoline production relative to the Base Case was still 

significant. 

Domestic refinery investment costs for implementing the lower sulfur and lower 

RVP standards considered range from $10 to $17 billion.6

 Based on investmentdecision criteria described below, four to seven refineries would likely shut down rather 

than make the required investments. There are additional investments that would be 

required outside the refineries that are not included in these totals. On an annual basis, 

total domestic refining industry compliance costs are estimated at $5 to $13 billion. 

Additional hydrotreating and fractionation required to comply would result in an 

increase in carbon dioxide (CO2) emissions from refineries that continue to operate. On 

 

4

 The analysis divided the year into two seasons. In this report, “summer” includes the months April 

through September inclusively. “Winter” is the remaining six months. 5

 Changes in gasoline production and imports throughout the report are hydrocarbon only. It was 

assumed that domestic ethanol production and consumption remain constant at Base Case levels. 6

 All costs in this report are expressed in constant 2009 U.S. Dollars. 
- 7 - 

an annual average basis, the total increase in CO2 emissions at domestic and foreign 

refineries is estimated at 2.9 to 7.4 million tonnes per year. 

These results are significantly different than those reported in the AAM Report. 

While a detailed reconciliation was not performed, there are several obvious differences 

in approach. The refining section of the AAM Report only considered refineries in 

PADDs 1, 2, and 3. According to the AAM Report, modeling was done using three 

aggregate refinery models, one for each of these PADDs.7 Our analysis was done with 

individual models of 112 refineries, including refineries in PADDs 4 and 5. As noted in 

the AAM Report, the aggregate modeling approach may lead to “over-optimization” and 

an understatement of compliance costs.8

The AAM Report does not appear to consider the lost value of NGLs that would 

be removed from the gasoline pool, and their estimate of the volumes that would be 

removed appear to be much smaller than what is reported herein. The AAM Report 

assumes that many refineries already have the capability to produce 5 ppm sulfur 

gasoline.9 Our analysis indicates that most will require capital investments to produce 5 

or 10 ppm sulfur gasoline. The AAM Report also uses a capital cost estimate for new 

fluid catalytic cracker (FCC) gasoline hydrotreater capacity that is approximately 25% of 

the figure used in this report.10 The AAM analysis does not appear to include FCC feed 

hydrodesulfurization revamps, expansions, or new units. These items were included in 

this analysis. 

 

7

 Alliance of Automobile Manufacturers, “National Clean Gasoline: An Investigation of Costs and 

Benefits,” June 2009, p.1-2. 

8

 Ibid, p. 1-23. 

9

 Ibid, p.1-19. 10 Ibid, p.1-19. 
- 8 - 

REGULATORY ASSUMPTIONS 

The Base Case in this analysis assumes that all existing fuel regulations based 

on existing law are fully implemented. The Study Case assumes that a lower sulfur and 

lower RVP standard with a nationwide (excluding California) RVP limit of 7 psia and 

sulfur limits of 20 ppm on individual batches and 10 ppm company annual average is 

implemented. Three Sensitivity Cases were also analyzed. A comparison of the key 

gasoline specifications in those cases and those proposed in the AAM Report is shown 

below. All other gasoline specifications were assumed to remain unchanged. 

Regulatory Assumptions 

Case 1 Case 2 Case 3

Company 

annual 

average

30 10 5 10*

Individual 

batch 80 20 10 *

Base 7.0

1 psia 

Waiver Varies *

Base

1 psia 

Waiver

*

Regular 87

Premium 93

Summer 1,250*

Winter *

0.62

1.3

Varies regionally Octane, minimum 

(R+M)/2

Benzene, 

maximum 

Vol.%

Varies regionally

Ethanol, fixed Vol.%

ASTM Driveability 

Index (DI), 

maximum***

10

Company annual 

average

Refinery annual 

average

AAM 

Study

Summer

Sulfur, maximum ppm

Winter

Maximum 

RVP, psia

Varies 

regionally

Varies regionally

Property

*

7.0

Base 

Case

Study 

Case

Sensitivity Cases

7.0 to 7.8**

10

20

No

* It is not clear from the AAM Report how the sulfur, RVP, and ASTM DI maximums would be applied. A 

blending limit of 5 ppm, 6.8 psia, and 1,220 for sulfur, RVP, and DI, respectively, was reportedly used in 

the refinery modeling work. It is also not clear what volatility limits would apply during the non-summer 

seasons or if the refinery annual average for benzene would remain unchanged. 

**RVP limited to 7.0 psia in current RFG areas and other areas currently requiring 7.0 psia. RVP limited 

to 7.8 psia in all other regions except California. 

*** No units apply, but in this context, temperatures are measured in degrees Fahrenheit (°F). 
- 9 - 

Most of the analysis described in this report was completed before the 

Environmental Protection Agency (EPA) approval of a gasoline formulation with 15% 

ethanol for late-model automobiles. Because of the uncertainty in what specifications 

for motor gasoline containing more than 10% ethanol might be, it was assumed that the 

10% limit would remain in place on all motor gasoline other than E85.11 The analysis is, 

therefore, focused on the impact of the potential lower sulfur and lower RVP 

specifications, and complications related to changes in ethanol content are avoided. 

TECHNOLOGY AND INVESTMENT COSTS 

There are significant differences in gasoline sulfur and summer RVP 

specifications between the Base, Study, and Sensitivity Cases. The summer RVP limits 

in the Study and Sensitivity Cases would require removal of additional low boiling point, 

high RVP blendstocks from the gasoline pool at many refineries. New fractionation 

towers would be required at many refineries to accomplish this. 

To reduce sulfur in finished gasoline, further reductions in FCC gasoline sulfur 

would be required. The Tier 2 gasoline regulations that took effect in 2004 caused 

almost all refiners to lower FCC gasoline sulfur by desulfurizing FCC gasoline and/or 

FCC feed. Additional reductions would be required to meet the Study and Sensitivity 

Cases’ sulfur standards. This would require a combination of new desulfurization units 

and revamps and expansions of existing units. 

New or expanded loading and unloading facilities (storage tanks, piping, vapor 

recovery systems, pumps, rail car loading spots, etc.) would be required at refineries to 

handle the volume of NGLs that would be extracted and sold as a result of lower 

summer RVP specifications. The scope of such modifications would vary by refinery 

and depends on a refiner’s existing loading/unloading infrastructure and capability. 

 

11 E85 refers to a gasoline-ethanol blend containing a nominal 85% ethanol by volume. 
- 10 - 

Transportation of the displaced surplus NGLs would be a challenge. Much of this 

material would need to be shipped in special-purpose rail cars. Additional rail cars, 

storage, and handling facilities would be required. 

ANALYTICAL BASIS 

Each refinery is unique, given its current technology, location, product slate, etc. 

Therefore, a refinery-by-refinery analysis was performed that considered each refinery’s 

compliance options accounting for technical, strategic, market, and economic factors, 

and then estimated a likely response based on this information. It is believed this 

approach is superior to aggregate or notional-type modeling, given the likely variation in 

refinery response to regulation, based on each refinery’s unique position. 

Baker & O’Brien’s proprietary PRISMTM Refining Industry Analysis modeling 

system was used extensively throughout this study. The PRISM system includes a 

sophisticated, mass-balanced refinery simulator and models of virtually every refinery in 

North America. 

The Study Case summer RVP requirement would cause many refineries to 

produce additional NGLs that cannot be blended in gasoline. A surplus of NGLs would 

likely be resolved through a combination of a number of actions including: 

 A reduction in butane and/or pentane imports; 

 Substitution of butane and/or pentane for other chemical industry feedstock; 

 An increase in butane and/or pentane exports to foreign markets; 

 Consumption or sales of butane and/or pentane as fuel or as feedstock for 

hydrogen production; 

 Alkylation of FCC Pentanes;12 and 

 Seasonal stockpiling of NGLs. 

 

 PRISM is a registered trademark of Baker & O'Brien, Inc. All rights reserved. 12 The term FCC Pentanes refers to the mix of 5-carbon molecules produced from an FCC unit and 

includes C5 olefins and di-olefins. 
- 11 - 

The quantity of NGLs that would need to be removed from gasoline during the 

summer in both the Study and Sensitivity Cases is quite large. This would have a 

significant impact on the value of these hydrocarbons. Because the incremental or 

lowest value market for the surplus NGLs would be a substitute for natural gas, that 

portion of the displaced NGLs would have to compete with natural gas. Refiners selling 

these hydrocarbons into that market would only realize a value roughly equivalent to 

natural gas. Using a pricing scenario consistent with Annual Energy Outlook 2010 

(AEO 2010), this value is significantly less than the value as gasoline blendstocks. This 

lost value has been treated as a cost to refiners, in addition to the investment and 

operating costs required to meet the gasoline specifications in the Study and Sensitivity 

Cases. 

A stepwise refinery-by-refinery approach was utilized in analyzing compliance 

options. If the investment required at any refinery exceeded its value as an ongoing 

concern (assumed to be five times the future annual net cash flow), then it was 

assumed that the refinery would stop making gasoline and/or shut down. 

The demand side response to the Study and Sensitivity Case scenarios has not 

been analyzed. Gasoline consumption has been held constant in all Cases. Imports in 

the Base Case are consistent with the AEO 2010 Reference Case and history. The 

availability of imports to meet the requirements of the other Cases was not assessed. 

STUDY RESULTS 

In the Base Case, U.S. refiners are projected to supply 7,435 MB/CD of gasoline 

during the summer, meeting 87% of the domestic requirement in 2016. Non-refinery 

domestic gasoline production is estimated to be 200 MB/CD, and 923 MB/CD of 

imported gasoline (excluding ethanol) would be required to meet the summer U.S. 

consumption forecast of 8,558 MB/CD. Foreign refiners have supplied the U.S. market 
- 12 - 

with this magnitude of gasoline in recent years, but the ability of foreign refineries to 

supply the 2016 requirements was not analyzed. 

In the Base Case, 112 refineries were producing non-California gasoline 

(including some California refineries). In the Study Case and Sensitivity Cases 2 and 3, 

it was projected that four refineries would likely shut down rather than make the 

investments required to comply with the lower sulfur and lower RVP specifications. In 

Sensitivity Case 1 the number of refineries that are projected to shut down increases to 

seven. These refineries are projected to have the potential to make 110 MB/CD of 

gasoline with lower sulfur and lower RVP in the Study Case, 170 MB/CD in Sensitivity 

Cases 2 and 3, and 206 MB/CD in Sensitivity Case 1 if they did make the investment. 

The estimated compliance investments for the remaining refineries (net of shutdowns) 

are shown below. 
- 13 - 

Expected Refinery Compliance Investments 

Study Case Sensitivity 

Case 1 

Sensitivity 

Case 2 

Sensitivity 

Case 3 

Refinery Shutdowns 4 7 4 4 

Number of New Units 

 Naphtha Depentanizer 45 43 27 16 

 FCC Depentanizer 40 38 9 9 

 Hydrocracker Depentanizer 23 22 2 2 

 FCC Feed Hydrotreater 1 8 1 1 

 FCC Gasoline Hydrotreater 9 20 9 9 

Number of Revamps and 

Expansions 

 FCC Feed Hydrotreater 30 28 27 27 

 FCC Gasoline Hydrotreater 32 38 30 30 

 

Logistics/Tankage, $MM 977 1,114 609 366 

 

Total Investment Cost, $MM 11,488 17,343 9,957 9,577 

Note: Individual refineries may appear in multiple categories for each case. 

To meet the Study and Sensitivity Case summer RVP specification, 315 to 934 

MB/CD of NGLs would be removed from the gasoline blend pool. In the Study Case, 

the resulting decrease in summer refinery gasoline production is estimated at 1,157 

MB/CD versus (vs.) the Base Case. This is equivalent to 14% of projected 2016 

summer hydrocarbon gasoline consumption. In Sensitivity Case 1 the lost production 

increases to 1,377 MB/CD of domestic gasoline production. In Sensitivity Cases 2 and 

3, the reduction vs. the Base Case is 873 and 622 MB/CD, respectively. 

Because refiners are already running at maximum volatility limits during the 

winter, there is no room to reabsorb the NGLs displaced during the summer into the 
- 14 - 

winter gasoline pool. Other outlets would need to be found. The magnitude of these 

volumes would likely have a significant impact on the U.S. refining, chemicals, and NGL 

markets. Investments required by refiners to modify their storage, loading, and 

unloading facilities to store and transport surplus summer butanes and pentanes are 

estimated at $400 million (in Sensitivity Case 3) to $1.1 billion (in Sensitivity Case 1). 

Additional investments would be required outside the refining industry to transport and 

handle these NGLs. 

The downgrade in NGLs value is by far the largest compliance cost. Capital 

investment costs are second. Refinery investment costs range from $9.6 billion (in 

Sensitivity Case 3) to $17.3 billion (in Sensitivity Case 1). As mentioned, there are 

additional investments that would be required outside the refineries that are not included 

in these totals. 

The total annual compliance cost borne by refiners for the Study and Sensitivity 

Cases is shown below: 

Total Annual Compliance Cost 

2009 $MM per Year 

 Study Case Sensitivity 

Case 1 

Sensitivity 

Case 2 

Sensitivity 

Case 3 

Purchased Hydrogen 305 546 354 354 

Other Variable Operating 

Expenses 498 749 342 303 

Fixed Operating 

Expenses 269 404 37 35 

Capital Recovery 1,953 2,949 1,693 1,628 

Light Hydrocarbon 

Downgrading 7,368 8,572 4,363 2,528 

Total Cost 10,393 13,220 6,789 4,848 
- 15 - 

The annualized and summer compliance costs for individual refineries are shown 

for the Study and Sensitivity Cases in graphs that follow. 

2016 Domestic Gasoline Production (excluding Ethanol) 

Study Case

Cost vs. Volume

(10)

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline Production

¢/Gal.

Annualized Costs

Summer Costs

2016 Domestic Gasoline Production (excluding Ethanol) 

Sensitivity Case 1

Cost vs. Volume

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline Production

¢/Gal.

Annualized Costs

Summer Costs

 
- 16 - 

2016 Domestic Gasoline Production (excluding Ethanol) 

Sensitivity Case 2

Cost vs. Volume

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline Production

¢/Gal.

Annualized Costs

Summer Costs

 

2016 Domestic Gasoline Production (excluding Ethanol) 

Sensitivity Case 3

Cost vs. Volume

(10)

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline 

Production

¢/Gal.

Annualized Costs

Summer Costs
- 17 - 

IV. REGULATORY ASSUMPTIONS

Historically, ASTM International (formerly known as the American Society for 

Testing and Materials) has published standards for minimum gasoline quality that varied 

seasonally and geographically. These standards have been adopted by many, but not 

all, states and have long been the minimum standards for gasoline sold in the U.S. 

Over the last several decades, the U.S. federal government has imposed a number of 

additional and more stringent gasoline quality requirements in an effort to reduce 

emissions from the combustion of gasoline and improve air quality. These standards 

vary seasonally and geographically. Additionally, the federal government has required 

individual states to develop State Implementation Plans (SIPs) to meet federal air 

quality standards. Several of the SIPs have imposed additional gasoline quality 

standards that create unique gasoline specification requirements for small geographical 

regions. 

In June 2009, the Alliance of Automobile Manufacturers published a report (the 

AAM Report) documenting purported costs and benefits of a single national standard for 

gasoline quality that would apply to all states except California. The AAM Report calls 

the new gasoline standard “National Clean Gasoline” or NCG. The proposed NCG 

standard has some elements that would impact refinery operations all year long (i.e., 

the reduced sulfur specification) and some that would only impact summer blending 

(i.e., the reduced Reid vapor pressure [RVP] specification). This report examines four 

possible regulatory scenarios for gasoline with lower sulfur and lower RVP: a Study 

Case and three Sensitivity Cases. 

The Base Case for the analysis assumes that the existing Tier-2 gasoline sulfur 

(maximum annual average of 30 parts per million [ppm]) and Mobile Source Air Toxics 

([MSAT2] maximum annual average of 0.62 volume percent [Vol.%] benzene in 

gasoline) are fully implemented. The impacts of potential changes in fuel specifications 
- 18 - 

that could result from “proposed” regulations, such as more stringent ground level 

ozone standards or NAAQS requirements, were not analyzed in any of the Cases. 

Most of the analysis described in this report was completed before the 

Environmental Protection Agency (EPA) approval of a gasoline formulation with 15% 

ethanol for late-model automobiles. Because of the uncertainty in what specifications 

for motor gasoline containing more than 10% ethanol might be, it was assumed that the 

10% limit would remain in place on all motor gasoline other than E85.13 The analysis is, 

therefore, focused on the impact of the potential lower sulfur and lower RVP 

specifications, and complications related to changes in ethanol content are avoided. 

In the Study Case and Sensitivity Cases 2 and 3, it was assumed that each 

refining company would be required to meet an average annual sulfur limit of 10 ppm, 

with a maximum cap of 20 ppm on individual gasoline batches by 2016. In Sensitivity 

Case 1, the company average limit is set at 5 ppm, and the cap is set at 10 ppm. To 

ensure compliance, it was assumed that companies would actually produce gasoline 

with sulfur levels slightly below the standard. In the Study Case and Sensitivity Cases 2 

and 3, company average sulfur was limited to 9 ppm, and the individual batch limit was 

set at 18 ppm. In Sensitivity Case 1, these were limited to 4.5 and 9 ppm, respectively. 

No inter-company trading of sulfur credits was assumed. 

In all Cases a summer (April to September) 7 pounds per square inch absolute 

(psia) maximum RVP specification was assumed in all Reformulated Gasoline (RFG) 

Areas,14 and in Conventional Gasoline (CG) area that currently require this RVP during 

the summer. It was assumed this RVP standard would replace the existing EPA 

complex model volatile organic compounds limits. In the Study Case and Sensitivity 

Case 1, it was assumed that the 7 psia summer limit would also apply in all other 

regions, except California. In Sensitivity Case 2, a 7.8 psia limit was assumed in these 

 

13 E85 refers to a gasoline-ethanol blend containing a nominal 85% ethanol by volume. 14 Including the Chicago-Milwaukee region. 
- 19 - 

other regions. In Sensitivity Case 3, the RVP limit in these regions was set at 7.8 psia, 

plus a 1 psia “waiver” for ethanol blending. 

For the remainder of the year, it was assumed that the existing regional and 

seasonal RVP specifications would remain in effect. All other gasoline specifications 

were assumed to be the same as in the Base Case. A comparison of the key gasoline 

specifications considered in this report and those proposed in the AAM Report is shown 

in the table below. 

Regulatory Assumptions 

Case 1 Case 2 Case 3

Company 

annual 

average

30 10 5 10*

Individual 

batch 80 20 10 *

Base 7.0

1 psia 

Waiver Varies *

Base

1 psia 

Waiver

*

Regular 87

Premium 93

Summer 1,250*

Winter *

0.62

1.3

Varies regionally Octane, minimum 

(R+M)/2

Benzene, 

maximum 

Vol.%

Varies regionally

Ethanol, fixed Vol.%

ASTM Driveability 

Index (DI), 

maximum***

10

Company annual 

average

Refinery annual 

average

AAM 

Study

Summer

Sulfur, maximum ppm

Winter

Maximum 

RVP, psia

Varies 

regionally

Varies regionally

Property

*

7.0

Base 

Case

Study 

Case

Sensitivity Cases

7.0 to 7.8**

10

20

No

* It is not clear from the AAM Report how the sulfur, RVP, and ASTM DI maximums would be applied. A 

blending limit of 5 ppm, 6.8 psia, and 1,220 for sulfur, RVP, and DI, respectively, was reportedly used in 

the refinery modeling work. It is also not clear what volatility limits would apply during the non-summer 

seasons or if the refinery annual average for benzene would remain unchanged. 

**RVP limited to 7.0 psia in current RFG areas and other areas currently requiring 7.0 psia. RVP limited 

to 7.8 psia in all other regions except California. 

*** No units apply, but in this context, temperatures are measured in degrees Fahrenheit (°F). 
- 20 - 

The above specifications were assumed to apply in all states except California, 

where existing California Air Resource Board (CARB) specifications were assumed to 

remain unchanged. 

GREENHOUSE GAS EMISSIONS 

Carbon dioxide (CO2) emissions from refineries were calculated for all cases, but 

no cost was assigned to these emissions. Because a cost has not been assigned to 

CO2 emissions, there is a possibility that refineries that have been assumed to be 

operating in this analysis could be shut down as a result of regulations to control and 

reduce CO2 emissions. These potential shutdowns could significantly change the 

results shown in this report. 

OTHER REGULATIONS 

In addition to the gasoline specification changes, impacts of the following existing 

fuel-quality regulations were included in the all cases: 

 Ultra Low Sulfur Diesel (15 ppm maximum at retail location); 

 Marine diesel limited to 0.1 weight percent sulfur; and 

 All No. 2 heating oil is limited to 500 ppm sulfur. 
- 21 - 

V. GASOLINE CONSUMPTION FORECAST

In December 2009, the Energy Information Administration (EIA) published an 

early release of its Annual Energy Outlook 2010 (AEO 2010). In this study, 2016 U.S. 

consumption of petroleum products is assumed to be constant in all cases and 

consistent with the AEO 2010 Reference Case15, and is reported on a Petroleum 

Administration Defense District (PADD) basis. Because AEO 2010 projections are 

presented on a different regional basis, the AEO 2010 regional forecasts have been 

disaggregated and then re-aggregated on a PADD basis.16 The 2016 consumption 

forecast was further divided between the summer and winter sub-cases on the basis of 

seasonal consumption in 2005 to 2006. The 2005 to 2006 time frame was selected, 

because it represents a more normal consumption pattern, unaffected by the volatile 

economic conditions in 2008 and 2009. 

The AEO 2010 Reference Case includes separate line items for “motor gasoline” 

and “E85”. Each of these categories includes both ethanol and petroleum-sourced 

gasoline; motor gasoline is assumed to be E10.17 Because of the uncertainty 

associated with potential specifications for motor gasoline containing more than 10% 

ethanol and to keep this study focused on its primary purpose, it was assumed that all 

motor gasoline would be E10 in the analysis period. 

The 2016 gasoline consumption forecast and a comparison to 2005 to 2006 are 

shown in Table 1. (Numbered tables are located at the end of this report.) 

 

15 Subsequent to the completion of our analysis, the EIA published an early release of the AEO 2011. 

The 2016 gasoline consumption forecast in the AEO 2011 early release is 1.2% above the forecast used 

in this report. The revision does not significantly impact the conclusions of this report. 16 The AEO 2010 forecast of motor gasoline and E85 consumption was allocated to individual states 

based on vehicle miles traveled in 2005-2006, as reported by the U.S. Department of Transportation. 

Consumption of other products was allocated to individual states based on average annual 

consumption patterns in 2005-2006, as published by the EIA in Petroleum Marketing Monthly. 17 E10 refers to a gasoline-ethanol blend containing a nominal 10% ethanol by volume. 
- 22 - 

VI. TECHNOLOGY AND CAPITAL INVESTMENT COSTS

All costs in this report are expressed in constant 2009 U.S. dollars. 

FRACTIONATION 

The summer RVP limits in the Study and Sensitivity Cases would require 

additional removal of low boiling point, high-RVP blendstocks from the gasoline pool at 

many refineries. Butanes would likely be the first to be rejected, followed by pentanes 

and pentenes contained in the light straight run, light hydrocrackate, and the light FCC 

gasoline. It is expected that new depentanizers would be required at many refineries. 

The removal of butanes and pentanes from the gasoline blend pool raises the DI 

of the remaining pool. Therefore, refineries that must install depentanizers to meet the 

summertime RVP limit would also need to reduce naphtha and/or fluid catalytic cracker 

(FCC) gasoline endpoints to meet summer DI specifications. In some cases, the 

butanes and pentanes/pentenes removed from the gasoline pool have lower sulfur 

content than the remainder of the pool. Removing butane and pentanes/pentenes from 

the pool would tend to complicate the task of meeting gasoline sulfur limits in these 

refineries. 

 FCC FEED AND GASOLINE DESULFURIZATION 

Tier 2 gasoline regulations took effect in 2004 and required almost all refiners to 

lower their annual average gasoline pool sulfur to a maximum of 30 ppm by December 

31, 2009. FCC gasoline is the primary source of sulfur in the gasoline pools in most 

U.S. refineries. As a result, most refiners responded to Tier 2 requirements by reducing 

FCC gasoline sulfur though FCC feed hydrodesulfurization, FCC gasoline 

desulfurization, or a combination of the two. Further reduction in finished gasoline sulfur 
- 23 - 

would require revamps and expansions of existing FCC feed and gasoline 

desulfurization units and/or construction of new units. 

In this report, a revamp is defined as the addition of catalyst volume to lower the 

space velocity and increase desulfurization without adding additional feed capacity. 

Revamps may require additional reactor vessels or significant modifications to reactor 

vessels and possibly compressors, but modifications to the remainder of the unit are not 

required. An expansion is an increase in unit capacity which likely would include 

additional reactor/catalyst volume and also modifications to the feed preheat and 

product fractionation sections. 

To meet Tier 2 sulfur limits, some refiners installed FCC gasoline fractionators in 

combination with heavy FCC gasoline hydrotreaters, but did not install reactors to 

hydrotreat light FCC gasoline. Many of these refiners would need to hydrotreat light 

FCC gasoline to meet the Study and Sensitivity Cases’ sulfur requirements. The 

addition of a light FCC gasoline hydrotreater reactor has been treated as an expansion 

rather than a revamp in this analysis. 

CAPITAL COSTS FOR GRASSROOTS UNITS 

Inside the battery limits (ISBL) capital costs for the technologies used in this 

study were estimated using the formula: 

ISBL Cost = Base Cost * (Actual Capacity/Base Capacity)SF

where: 

 Base Capacity refers to the capacity of a unit for which there is an estimated 

construction cost; 

 Base Cost refers to the estimated construction cost for that unit; 

 Actual Capacity refers to the capacity of a unit for which a cost estimate is 

required, and would vary by refinery; and 

 SF = Scale Factor (typically 0.6 to 0.7). 
- 24 - 

The following table shows the base cost, base capacity, and SF coefficients for 

each technology. 

FCC Gasoline 

Hydrodesulfurization1

FCC Feed 

Hydrodesulfurization2 Depentanizer3

Capacity (B/D) 35,000 35,000 20,000

Capital cost (million $) 228.8 163.6 7.0

Scale Factor 0.67 0.67 0.39

Initial Catalyst & Chemical $/MB/D) 0.08 0.08

3. Baker & O'Brien estimate.

Process Unit Inside Battery Limits Capital Cost Assumptions

Second Quarter 2009

1. Based on reported total installation costs of several units since 2001 minus assumed 20% outside battery limits 

(OSBL) costs and inflation based on discussions with refiners.

2. Assumed an ISBL cost between the reported total installed cost of ULSD units and mild hydrocracker units 

minus assumed 20% OSBL costs.

REVAMP/EXPANSION COSTS 

For revamps as defined above, it was assumed the investment cost would be 

30% to 70% of the ISBL replacement cost of a grassroots unit, depending on the extent 

of the revamp. For expansions, the investment cost was assumed to be 150% of the 

difference in ISBL replacement cost between the Base Case and the alternate Case. 

NATURAL GAS LIQUID (NGL) STORAGE AND LOADING COSTS 

New or expanded loading and unloading facilities (storage tanks, piping, vapor 

recovery systems, pumps, rail car loading spots, etc.) would be required at refineries to 

handle the volume of NGLs that would be sold if the summer gasoline RVP specification 

is lowered to 7 psia nationwide. The scope of such modifications would vary by refinery 

and depend on a refiner’s existing loading/unloading infrastructure and capability. A 
- 25 - 

capital investment cost of $140 per barrel (Bbl.) of storage capacity18 on a U.S. Gulf 

Coast (USGC) basis was assumed, and it was further assumed that refiners would 

install storage capacity equal to 10 days of production. 

OTHER OFF-SITE CAPITAL COSTS 

It was assumed that no additional investment for off-sites would be required 

unless new units or new equipment were installed (i.e., a depentanizer). Process offsite investment costs were estimated at 20% of the ISBL cost. Non-process off-sites 

costs were estimated at 15% of the ISBL, and spare parts and catalyst at 1.2% of the 

ISBL cost. 

CONTINGENCY ALLOWANCE 

Because of the considerable uncertainty associated with actual capital costs, it is 

prudent to apply some reasonable "contingency" allowance to capture unidentified costs 

that can be expected during construction. A contingency allowance of 20% of the 

combined ISBL and outside battery limits costs was assumed. 

CAPITAL INVESTMENT CHARGE 

Estimated capital costs were converted into a unit charge based on the barrels of 

product produced and an assumed return on total investment. Refiners would not 

normally invest in a project unless they anticipate a rate of return commensurate with 

the opportunity cost of capital. It was assumed that refiners would require a 10% aftertax rate of return based on a 15-year operating life, a ten-year accelerated depreciation 

schedule, a 38% tax rate, and a two-year construction period. 

 

18 Based on applying a cost representing the midpoint of the range recommended for butane storage in 

the 5th edition (2007) of “Petroleum Refining: Technology and Economics,” by James H. Gary, Glenn 

E. Handwerk, Mark J. Kaiser, and escalated to 2009 dollars by using the Nelson Farrar Refinery 

Construction Cost Index. 
- 26 - 

VII. INPUT COSTS

NATURAL GAS COST 

The most significant operating cost was natural gas. Natural gas costs used in 

this study are above current levels, but within 10% of those reflected in both the New 

York Mercantile Exchange annual average futures values and the AEO 2010 for 2011 

and 2012. 

HYDROGEN COSTS 

If individual refineries were unable to meet increased hydrogen requirements 

associated with additional gasoline desulfurization, it was assumed incremental 

hydrogen requirements would be supplied by outside sources. The cost of natural gas 

usually comprises approximately half the total cost (including capital charges) of 

manufacturing or purchasing hydrogen from outside sources. The cost of purchased 

hydrogen was assumed to be 2.38 times the cost of natural gas on an energyequivalent basis. Such a value has historically been adequate to encourage third-party 

companies to build hydrogen production capacity using steam methane reforming 

technology and supply hydrogen to refiners under term-sales contracts. 

In some situations, refiners may find lower-cost sources for small increases in 

hydrogen production by making changes to reformer operations, from expansion of 

existing hydrogen plants, and through recovery of hydrogen from refinery fuel systems. 

These sources are expected to be limited and are not included in this study. 
- 27 - 

VIII. ANALYTICAL BASIS

Even without new gasoline sulfur and RVP rules, compliance with existing 

regulation is placing difficult and expensive burdens on the refining industry. Numerous 

federal and state regulations are adding to the cost of merely staying in business. State 

and federal emissions standards at refineries in non-attainment areas necessitate the 

expenditure of capital on new emissions control equipment. Revisions to new source 

review standards are currently being challenged in court. Depending upon the 

outcome, there could be an increase in the cost of investments needed to comply with 

fuel quality regulations. 

Each refinery is unique given its current technology, location, product slate, etc. 

Therefore, a refinery-by-refinery analysis was performed that considered each refinery’s 

compliance options accounting for technical, strategic, market, and economic factors, 

and then predicted a likely response based on this information. It is believed this 

approach is superior to aggregate or notional-type modeling, given the likely variation in 

refinery response to regulation, based on each refinery’s unique position. 

REFINERY MODELING 

The PRISM Refining Industry Analysis modeling system was used extensively 

throughout this study. The PRISM system includes a sophisticated, mass-balanced 

refinery simulator that is based on non-linear yield correlations for conversion units and 

optimized blending of gasolines and distillate fuels. Variable operating costs are 

calculated on a process unit by process unit basis, and detailed estimates of fixed

operating costs are made based on the refinery capacity and configuration. The 

complete PRISM system includes models of virtually every refinery in North America, 

along with a crude assay library (containing over 210 different crude oils), product 

distribution channels, market prices for products, and pipeline tariffs. It includes fixed 
- 28 - 

and variable operating cost and capital replacement cost estimates for each refinery, 

and provides a systematic method of evaluating and comparing refinery operating and 

financial performance over time and across different markets. The PRISM system was 

used to model the operations of individual U.S. refineries for each of the Cases. 

REFINERY CAPACITY AND UTILIZATION 

Baker & O’Brien routinely makes an independent assessment of process unit 

capacity for individual refineries based on publicly-available information, including the 

EIA annual survey of refinery capacity and other sources. Refining capacity is usually 

reported on either a calendar day (CD) or a stream day (SD) basis. We define SD 

capacity as the maximum rate at which a unit can produce or consume material during a 

continuous 24-hour period. 

CD capacity represents the maximum sustainable capacity to produce or 

consume material over an extended period of operation and accounts for the capacity 

that is lost during planned and unplanned outages. CD capacities are typically around 

90% of SD capacities. All the capacities used in this report are CD capacities, and by 

definition it is possible for individual process units to sustain operations at 100% of 

these capacities. CD capacity utilization of 100% is typically equivalent to 90% 

utilization of SD capacity. 

The Base Case refinery capacity estimate began with our estimates of 2009 

capacities. Announced refinery projects that are expected to be completed before 2016 

include: 

 BP – Whiting Expansion; 

 Holly – Tulsa Refineries Integration; 

 Marathon – Garyville Expansion; 

 Motiva – Port Arthur Expansion; 

 Total – Port Arthur Coker; and 

 WRB Refining – Wood River Coker Expansion. 
- 29 - 

It was also assumed that the capacity associated with announced permanent 

refinery closures would not be available in 2016. These closures include: 

 Sunoco – Eagle Point; 

 Western – Bloomfield; and 

 Valero – Delaware City.19

Modifications required to comply with existing regulations listed in Section IV of 

this report were assumed to be completed before 2016. No other refinery investments, 

capacity “creep,” or shutdowns are included in the 2016 Base Case. Current and 2016 

Base Case refining capacities are shown in Table 2. The AEO 2010 Reference Case 

figures are provided for comparison. 

Refinery utilization rates in the Base Case were calibrated to match the AEO 

2010 Reference Case crude throughputs and utilization rates as closely as possible. 

CRUDE SLATE 

Except at those refineries with announced projects that impact their crude slates, 

it was assumed that refineries would continue running crude slates comparable to those 

currently being run. It is recognized that domestic crude production is declining, and it 

was assumed that foreign crudes with equivalent qualities would be purchased to 

replace the declining domestic crudes. Crude slates are the same in the Base, Study, 

and Sensitivity Cases. 

SEASONALITY 

To adequately evaluate the impact of the Study and Sensitivity Cases’ summer 

RVP reduction, it was necessary to run the individual refinery models in both a summer 

and winter mode. This made it possible to address the full magnitude of NGLs 

disposition and management issues in the summer. 

 

19 Subsequent to the completion of the initial modeling work, the Delaware City refinery was purchased by 

a subsidiary of PBF Energy Company LLC, which announced its intention to restart the refinery. 
- 30 - 

CALIFORNIA REFINERIES 

Although the specifications for California gasoline do not change in the Study and 

Sensitivity Cases, there are several California refineries that produce non-California 

gasoline. These refineries were included in the analysis. 

DISPOSITION OF EXCESS NGLS 

Imposition of the Study or Sensitivity Cases’ summer RVP specifications would 

cause large quantities of NGLs to be removed from gasoline and to be sold as NGLs by 

refiners. This would likely cause some combination of the following: 

 A reduction in butane and/or pentane imports; 

 Substitution of butane and/or pentane for other ethylene cracker feedstocks; 

 An increase in butane and/or pentane exports to foreign markets; 

 Consumption or sales of butane and/or pentane as fuel or as feedstock for 

hydrogen production; 

 Alkylation of FCC Pentanes,20 and; 

 Increased seasonal stockpiling of NGLs. 

REDUCE NGL IMPORTS 

The U.S. imported an average of 42 thousand barrels per calendar day (MB/CD) 

of n-butane, 26 MB/CD of Pentanes Plus, and roughly 100 MB/CD of petrochemical 

feedstock naphtha during 2006 through 2008. It would be expected that any scenario 

which resulted in a large surplus of refinery produced NGLs would trigger a significant 

curtailment or elimination of these imports. 

DISPLACE OTHER ETHYLENE CRACKER FEEDSTOCKS 

The U.S. ethylene industry has the capability to consume nearly 2 million barrels 

per calendar day (MMB/CD) of combined ethane, propane, butane, and other petroleum 

 

20 FCC Pentanes refers to the mix of 5-carbon molecules produced from an FCC unit and includes C5 

olefins and di-olefins. 
- 31 - 

liquids.21 Feedstock consumption for U.S. ethylene producers during the 2000 through 

2008 period was within the ranges below:22

Feedstock Consumption 

in U.S. Ethylene Plants 

Consumption 

Range 

2000-2008, 

MB/CD 

Consumption 

Midpoint 

MB/CD 

Ethane 400 - 800 650 

Propane 200 - 450 350 

Butane 0 - 140 50 

Light and Heavy Liquids 400 - 750 550 

 Total 1,600 

The relative portion of feedstock consumed by ethylene crackers varies 

dynamically, as most producers optimize their feedstock slates based on real-time 

feedstock and product prices. Not all ethylene crackers have the flexibility to consume 

all types of feedstock. Approximately 50% of U.S. ethylene is produced from crackers, 

which have the flexibility to consume either NGLs or liquid feedstocks.23 

If the surplus refinery-produced NGLs are substituted for other ethylene cracker 

feedstocks, the displaced ethylene feedstocks would need to be accommodated 

elsewhere. While there are options available for balancing the supply of these 

feedstocks, these options are somewhat limited. 

 Ethane has no market outlet other than as ethylene feedstock. If ethane is 

displaced from ethylene crackers, the only option for balancing ethane supply 

is to reduce the quantity of ethane extracted from natural gas to the extent 

permitted by common carrier natural gas pipeline specifications. 

 Displacing propane and heavier NGLs would likely cause a reduction in U.S. 

waterborne imports. The U.S. imported an average of 165 MB/CD of propane 

and 150 MB/CD of “heavy liquids” (greater than 400°F end point) during 2006 

 

21 Baker & O’Brien analysis based on information provided in the Oil & Gas Journal “Special Report - 

International Survey of Ethylene From Steam Crackers – 2009,” July 27, 2009. 22 U.S. Ethane Outlook – Conclusion: “Midstream, petchem players must face problems of increased 

ethane capacity,” Oil & Gas Journal, February 23, 2009. 23 Ibid. 
- 32 - 

through 2008. While propane competes with heating oil in the home heating 

market, it is unlikely that fuel switching would become a major factor in 

balancing propane supply. 

It is important to note that changes in ethylene cracker feed composition would 

result in changes in product mix. For instance, if U.S. crackers substitute butanes for 

naphtha, these crackers would produce much lower quantities of aromatics. If they 

substitute butanes for ethane, they would produce higher quantities of propylene and 

C4 co-products. The change in product mix would have repercussions throughout the 

U.S. petrochemicals supply chain. A detailed analysis of ethylene cracker feedstocks is 

beyond the scope of this study. 

EXPORT MARKETS 

The U.S. exported a relatively small quantity of n-butane during 2006 through 

2008, averaging 14 MB/CD. Over the past 20 years, the U.S. has demonstrated peak 

n-butane export volumes of roughly 45 MB/CD. Therefore, the U.S. has the capability 

to export at least an additional 30 MB/CD of n-butane above the 2006 to 2008 average. 

Export capacity could be significantly higher since Enterprise Products Partners 

reportedly has the capability to export over 100 MB/CD of propane and butane.24 

U.S. exports of Pentanes Plus have increased from 12 MB/CD in 2006 to 39 

MB/CD in 2009. These exports were all destined for Canada for use as a diluent to 

facilitate the pipeline transport of heavy Canadian crude oil and bitumen. While 

increases in Pentanes Plus exports may continue, this increase would likely be a simple 

recycling of diluent imported from Canada; diluent is probably not a significant new 

market for Pentanes Plus produced in the U.S. from other sources. 

 

24 Enterprise Products Partners reported in their 2009 Form 10K Filing (p.12) that they can load 

refrigerated propane and butane onto tanker vessels at rates up to 6,700 barrels per hour. 
- 33 - 

CONSUME OR SELL AS FUEL OR HYDROGEN FEEDSTOCK 

Some refiners may elect to modify their hydrogen plants to consume butanes 

and/or pentanes, while others may elect to consume these materials as fuel in their 

steam boilers, furnaces, or nearby combined heat and power plants. 

ALKYLATION 

FCC Pentanes can be alkylated with isobutane to yield a low RVP gasoline 

blendstock. This would not only consume the FCC Pentanes, it would also allow 

additional pentanes and butanes to be blended into gasoline and partially mitigate lost 

gasoline production. Traditionally, economics have not favored the alkylation of FCC 

Pentanes, partially because the octane ratings of the resulting alkylate are lower than 

those produced with other feedstocks and because acid catalyst consumption and 

resulting operating costs are significantly higher than for other feedstock. 

Alkylation of FCC Pentanes, as a partial solution to the problem of excess 

refinery NGLs generated by the Study and Sensitivity Cases RVP limits, would require 

capital investments in alkylation capacity. The Study and Sensitivity Cases assume that 

refiners only make investments required for compliance. Since investment in additional 

alkylation capacity is not required for compliance, they were not included in the analysis. 

The potential that some refiners might make these investments certainly exists. 

Refiners would make these incremental investments if they anticipated earning an 

adequate return on the investment. This was accounted for in the valuation of excess 

refinery NGLs. 

STOCKPILE FOR WINTER CONSUMPTION 

The U.S. stockpiled just over 360 MB/CD of NGLs during the summer months of 

2006 through 2008 for consumption during the winter months.25 Summer stockpiling of 

propane and n-butane for winter consumption is commonplace in the U.S. These 

 

25 Based on an analysis of statistics reported by the EIA through the Petroleum Navigator located at 

http://tonto.eia.doe.gov. 
- 34 - 

products are stockpiled in underground salt dome caverns, primarily in the USGC. The 

seasonal stockpiling of Pentanes Plus is an option that would be considered by 

participants in the refining, chemical, and NGLs industries to respond to a summer 

surplus of Pentanes Plus. 

NGLS TRANSPORTATION 

The vast majority of refinery Pentanes Plus is blended into gasoline, so there is 

very limited logistics infrastructure dedicated to Pentanes Plus transportation. Mont 

Belvieu, Texas, is a major clearing hub for U.S. NGLs, and could be the primary 

destination for surplus NGLs produced by refineries in the Study and Sensitivity Cases. 

Mont Belvieu is connected by an extensive pipeline network to a large number of 

refineries and petrochemical facilities, as well as to the largest U.S. NGL import/export 

facility. Those refineries that are either connected to Mont Belvieu by two-way 

pipelines, or are located adjacent to flexible feed ethylene crackers, would not be 

expected to require any significant infrastructure modifications to enable the disposition 

of surplus NGLs. Some refiners, particularly those on the Houston Ship Channel, may 

be able to utilize pressurized barges to transport surplus NGLs. However, refineries 

located outside of USGC would most likely need to transport their surplus NGLs by rail 

car to the USGC. 

Rail transport of NGLs requires special-purpose rail cars, referred to as highpressure tank cars. It is estimated that high-pressure tank cars represent approximately 

3% of the 1.75MM U.S. rail car fleet.26 These cars typically transport NGLs and a 

number of chemical products. High-pressure tank cars typically hold about 30,000 

gallons of product. 

The number of rail cars that would be required to transport surplus refinery 

produced NGLs was calculated by dividing the aggregate daily surplus for each PADD 

 

26 Baker & O’Brien estimate. 
- 35 - 

that would be transported to the USGC by the average rail car size (30,000 gallons) and 

then multiplying by the round-trip transit time between the respective PADD and the 

USGC. 

VALUATION OF EXCESS NGLS 

The quantity of NGLs removed from gasoline during the summer in the Study 

and Sensitivity Cases is very large and would impact the domestic and international 

markets for NGLs. This would have a significant impact on the value that refiners 

receive for these products. For the most part, these are relatively clean burning 

gasoline components with higher than average hydrogen to carbon atomic ratios (i.e., 

iso-pentane produces less CO2 per British thermal unit when burned than iso-octane). 

Because the incremental or lowest value market for the excess NGLs would be 

as a substitute for natural gas, a portion of the displaced NGLs would have to compete 

directly with natural gas. Refiners selling these hydrocarbons into that market would 

realize a value equivalent to natural gas. Using a pricing scenario consistent with AEO 

2010, this value is significantly less than the NGLs’ value as gasoline blendstocks. This 

reduction in value has been treated as a cost to refiners. 

Some portion of the displaced NGLs is likely to achieve values greater than 

natural gas equivalence, but the fact that the incremental value is natural gas 

equivalence would tend to drive values lower in alternative markets as well. A detailed 

analysis of the markets for these NGLs was beyond the scope of this study and would 

not have a significant impact on the results or conclusions. It has been assumed that 

refiners would realize natural gas equivalent values for volumes used as fuel or sold into 

export markets. All other light hydrocarbon sales have been valued at the mid-point of 

their Base Case gasoline blending value and natural gas equivalence. 
- 36 - 

COMPLIANCE RESPONSE 

Faced with the regulations in any of the study scenarios, refiners would have 

three options: 

1) Make the necessary investments to facilitate compliance, 

2) Stop making gasoline, or 

3) Shut down. 

A stepwise approach was taken in analyzing compliance responses. The first 

step was to determine the minimum capital necessary to comply with the new gasoline 

standards at each individual refinery. Since summer compliance with both sulfur and 

RVP reductions would be more difficult than winter, investment decisions would be 

based on meeting the summer specifications. Any capital improvements installed to 

meet the summer requirements would obviously be in place in the winter, regardless as 

to whether they are needed in the winter. 

Each refinery was reviewed using the following procedure: 

1. Debutanizers and depentanizers were added to the extent needed to meet 

the 7 psi RVP specification. 

2. If debutanization or depentanization caused problems with the DI 

specification, then FCC heavy gasoline end points were reduced, but no 

lower than 360°F. 

3. If reducing the FCC heavy gasoline end point was insufficient to meet the 

existing DI specifications, crude naphtha end points were reduced. 

4. If a refinery had an existing FCC feed desulfurization unit and no FCC 

gasoline hydrotreater, the existing unit was revamped to the extent possible 

to meet the lower gasoline sulfur limit. 

5. Existing FCC gasoline desulfurization units were revamped or expanded as 

needed to meet the lower gasoline sulfur specification. 

6. If expansions and revamps of existing desulfurization units were insufficient to 

meet the sulfur limits, then new FCC gasoline hydrotreaters were added. 

The modified refineries were modeled using the PRISM refinery simulator to 

generate new product yields, expense, and cash margin data. In calculating the new 
- 37 - 

cash margins, crude and product prices were held constant with the Base Case with the 

exception of the adjustment to light hydrocarbon prices discussed above (i.e., at this 

point in the analysis, it was assumed that none of the compliance cost would be 

recovered by refiners). 

The new estimated net cash flow for each refinery was reviewed relative to the 

required investment. If the investment required at any refinery exceeded its “value as 

an ongoing concern” (assumed to be five times the future annual net cash flow), then it 

was assumed that the refinery would stop making gasoline. In almost every case, the 

decision to not make gasoline led to a decision to shut down the refinery. 

For the refineries where compliance investments met the value as an ongoing 

concern, criteria summer variable cash margins27 were reviewed. If a refinery met the 

ongoing concern investment test, but was operating with a negative variable cash 

margin during the summer, it was assumed that the refiner would consider not making 

gasoline or shutting down entirely during the summer and only make the investments 

required to comply with the winter gasoline standards. 

In practice, each refiner would make investment decisions based on its own 

forecasts and expectations of compliance cost recovery. After identifying the refineries 

that might stop making gasoline or shut down completely if they anticipated none of the 

compliance cost would be recovered, individual refineries were reviewed in the context 

of their unique situation. Best judgment was applied on a case-by-case basis, and 

some of these marginal refineries with relatively low compliance costs were assumed to 

make the necessary compliance investments. 

 

27 Variable cash margin is defined as the sum of all product revenue less the cost of feedstocks and only 

expenses that vary with operating rates. For example, fuel and power consumption will vary with 

operating rates, but property taxes and insurance do not. Expenses that do not vary with operating rate 

are defined as fixed costs. 
- 38 - 

OTHER GASOLINE SUPPLY 

The AEO 2010 Reference Case includes 300 MB/CD of “other” supply to the 

transportation fuels market in 2016. EIA staff28 indicated that one-third to one-half of 

this is Non-Esterified Renewable Diesel (NERD). The remainder is other blending 

components, other hydrocarbons, and renewable feedstocks for the on-site production 

of diesel and gasoline. In the Base Case it has been assumed that 100 MB/CD NERD 

and 200 MB/CD of gasoline blending components would be supplied to the domestic 

market from sources other than domestic refineries and imports. It is reasonable to 

assume that the reduction in RVP in the Study and Sensitivity Cases would impact the 

supply of the non-refinery domestic gasoline components to at least the same extent 

proportionally as refinery produced gasoline, but a detailed analysis was not performed. 

IMPORTS 

As discussed in Section V of this report, demand side response has not been 

analyzed for the Study and Sensitivity Cases. Gasoline consumption was held constant 

in all cases. Imports in the Base Case are consistent with the AEO 2010 Reference 

Case and history. The availability of imports to meet the requirements of the Study and 

Sensitivity Cases has not been analyzed. 

ETHANOL QUALITY 

It was assumed that ethanol has a sulfur content of 10 ppm consistent with the 

default ethanol properties values specified by California Air Resources Board.29 

 

28 Conversation with an EIA AEO Forecast Analyst, December 15, 2009. 29 Procedures for Using the California Model for California Reformulated Gasoline Blendstocks for 

Oxygenate Blending (CARBOB), August 7, 2008. 
- 39 - 

IX. STUDY RESULTS

BASE CASE GASOLINE SUPPLY BALANCE AND REFINERY 

OPERATIONS 

Using the PRISM refining industry model, adjusted for the capacity changes 

discussed in Section VIII, 2016 domestic gasoline production for each individual refinery 

was estimated under Base Case regulations. Supply balances for the Base Case 

summer, winter, and annual averages are provided in Table 3, Table 4, and Table 5, 

respectively. On an annual basis, U.S. refiners are projected to produce 7,296 MB/CD 

of hydrocarbon gasoline,30 meeting 87% of the domestic requirement. As discussed in 

Section VIII, non-refinery gasoline production in 2016 is estimated to be 200 MB/CD. 

Therefore, 885 MB/CD of imported hydrocarbon gasoline would be required to meet the 

AEO 2010 U.S. consumption forecast for 2016. During the summer, imports of 923 

MB/CD are required to balance supply with consumption. Foreign refiners have 

supplied the U.S. market with this magnitude of gasoline in recent years, but an analysis 

of the ability to supply the 2016 requirement was not part of this study. 

Refinery annual average utilization rates for key process units are provided in 

Table 6. As mentioned in Section VIII, these utilization rates are based on our 

estimates of CD capacities. Utilization rates based on SD capacities would be lower. In 

the Base Case, regional average crude unit utilization rates range from a low of 79% in 

PADD 5 to a high of 93% in PADD 4. The Base Case U.S. average crude utilization 

rate of 82% is in line with the AEO 2010 forecast for 2016 of 83%. Average Base Case 

utilization rates for key process units are within 5% of those observed during the period 

of October 2008 through September 2009, with the exception of hydrocrackers, which 

 

30 Changes in gasoline production and imports throughout the report are hydrocarbon only. It was 

assumed that domestic ethanol production and consumption remain constant at Base Case levels. 
- 40 - 

are at 91% utilization in the Base Case vs. 80% during October 2008 through 

September 2009. The higher hydrocracker operating rate is required to achieve a 

higher production level of light oil products in 2016. 

Tables 7A through 7D provide summaries of key gasoline quality results for the 

summer and winter, with and without ethanol. (As discussed in Section V, all U.S. 

gasoline is assumed to be either E10 or E85.) Tables 8 and 9 show the domestic 

production by crude oil refiners for the summer and winter, respectively. 

COMPLIANCE RESPONSE 

In the Base Case, 112 refineries were producing non-California gasoline 

(including some California refineries). To meet the lower summer RVP specifications in 

the Study and Sensitivity Cases additional depentanizers will be required. In the Study 

Case, a total of 46 refineries will require a total of 108 new depentanizers. In the 

Sensitivities Cases, the total number of new depentanizers is 103, 38, and 27 

respectively. The removal of NGLs from the gasoline blend pool raises the DI of the 

remaining pool. Many of the refineries must also reduce naphtha and/or FCC gasoline 

endpoints to meet summer DI specifications. 

To meet the Study Case sulfur limits, 30 refineries would need to upgrade 

existing FCC feed hydrotreaters, one refinery would require installation of a new FCC 

feed hydrotreater, nine would need to install new FCC gasoline hydrotreaters, and 32 

would need to expand or upgrade their existing FCC gasoline hydrotreaters. In 

Sensitivity Case 1, the required investments are greater. 

Applying the methodology and criteria described in the previous section, an 

estimate of the most likely investment decisions was made for each refinery. That 

analysis indicated that four refineries would likely shut down rather than make the 

investments required to comply with the lower sulfur and lower RVP specifications in the 

Study Case and in Sensitivity Cases 2 and 3. In Sensitivity Case 1, the number of 
- 41 - 

refineries estimated to shut down increases to seven. These refineries are projected to 

have the potential to make 110 MB/CD of gasoline with lower sulfur and lower RVP in 

the Study Case, 170 MB/CD in Sensitivity Cases 2 and 3, and 206 MB/CD in Sensitivity 

Case 1 if they did make the investment. Assuming those refineries do shut down, the 

expected compliance investments are shown below. 

Expected Refinery Compliance Investments 

Study Case Sensitivity 

Case 1 

Sensitivity 

Case 2 

Sensitivity 

Case 3 

Refinery Shutdowns 4 7 4 4 

Number of New Units 

 Naphtha Depentanizer 45 43 27 16 

 FCC Depentanizer 40 38 9 9 

 Hydrocracker Depentanizer 23 22 2 2 

 FCC Feed Hydrotreater 1 8 1 1 

 FCC Gasoline Hydrotreater 9 20 9 9 

Number of Revamps and 

Expansions 

 FCC Feed Hydrotreater 30 28 27 27 

 FCC Gasoline Hydrotreater 32 38 30 30 

 

Logistics/Tankage, $MM 977 1,114 609 366 

 

Total Investment Cost, $MM 11,488 17,343 9,957 9,577 

Note: Individual refineries may appear in multiple categories for each case. 
- 42 - 

STUDY AND SENSITIVITY CASES GASOLINE SUPPLY BALANCE AND 

REFINERY OPERATIONS 

The low summer RVP specification in the Study and Sensitivity Cases results in 

the removal of a large quantity of domestically-produced hydrocarbon from the gasoline 

blend pool. In the Study Case, the resulting decrease in summer refinery gasoline 

production is estimated at 1,157 MB/CD vs. the Base Case. This is equivalent to 14% 

of projected 2016 summer hydrocarbon gasoline consumption. In Sensitivity Case 1 the 

loss in production increases to 1,377 MB/CD of domestic summer gasoline supply. In 

Sensitivity Cases 2 and 3, the reduction vs. the Base Case is 873 and 622 MB/CD, 

respectively. 

Consideration was given to increasing refinery operating rates to offset the 

decline in gasoline production. An increase in refinery operating rates would increase 

distillate and NGLs production, requiring additional U.S. exports of these products. The 

U.S. currently exports diesel fuel and additional exports may be possible. However, 

even without an increase in crude processing, significant exports of NGLs are required 

in the Study and Sensitivity Cases, and it is not obvious that foreign markets would 

accommodate these exports. Therefore, crude utilization rates were held constant at 

Base Case levels in refineries that continued to operate in the Study and Sensitivity 

Cases. 

In the Base Case, 200 MB/CD of gasoline is provided by non-refining domestic 

suppliers. As discussed in the previous section, it would be reasonable to assume that 

the implementation of the Study or Sensitivity RVP limits would impact this supply at 

least proportionally to the supply lost from refineries. 

The net result in both the Study Case and Sensitivity Case 1 and 2 is that 

summer imports of gasoline (excluding ethanol) would need to more than double vs. the 

Base Case and almost double in sensitivity Case 3 vs. the Base Case, if projected 

consumption is to be supplied. At the same time, incremental NGLs removed from U.S. 
- 43 - 

gasoline would be exported or burned as a substitute for natural gas. The capability of 

foreign refineries to supply this volume of gasoline with lower sulfur and lower RVP was 

not studied, but it is questionable. At the very least, the increased dependence on 

gasoline imports would cause the U.S. to be more vulnerable to supply disruptions. 

Because the winter RVP specifications are unchanged from the Base Case, 

there were no significant changes in refinery production rates compared to the Base 

Case. The desulfurization facilities required for summer compliance were sufficient to 

meet the sulfur specification in the winter. Refiners would incur higher winter operating 

costs vs. the Base Case, primarily because of an increase in hydrogen consumption 

related to additional FCC feed and FCC gasoline desulfurization. 

The details of all modeled scenarios’ gasoline quality and supply balances are 

reported in Tables 10 through 25. 

Refinery hydrogen production was reduced in the Study and Sensitivity Cases 

due to the reduced reformer utilization associated with undercutting naphtha. The 

combination of the decline in reformer hydrogen production and an increase in 

consumption for desulfurization results in an annualized increase in net hydrogen 

purchases of 164 million standard cubic feet per calendar day (MMscf/CD) at refineries 

operating in the Study Case, and 293, 185, and 185 MMscf/CD at refineries operating in 

Sensitivity Cases 1, 2, and 3, respectively. These numbers assume that existing 

refinery hydrogen plants produce at capacity where needed. It was assumed that the 

incremental hydrogen purchases would be available from third-party steam methane 

reformers. 
- 44 - 

Hydrogen Purchases, MMscf/CD 

Total U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5 

 Base Case*

 1,629.7 20.1 36.5 1326.7 0.8 245.5 

Study Case purchases 1,793.6 28.4 64.8 1424.5 1.5 274.5 

 Delta vs. Base Case** 163.9 8.2 28.3 97.7 0.6 29.0 

 Delta, % 10% 41% 77% 7% 72% 12% 

 Base Case*

 1,618.4 20.1 36.5 1315.4 0.8 245.5 

Sensitivity Case 1,911.2 46.3 93.5 1,469.3 1.5 300.5 

 Delta vs. Base Case** 292.8 26.2 57.0 153.9 0.6 55.0 

 Delta, % 18% 130% 156% 12% 74% 22% 

 Base Case*

 1,629.7 20.1 36.5 1,326.7 0.8 245.5 

Sensitivity Case 2 1,814.4 28.3 64.5 1,416.6 0.8 304.1 

 Delta vs. Base Case** 184.7 8.2 28.0 89.9 0.0 58.6 

 Delta, % 11% 41% 77% 7% 0% 24% 

 Base Case*

 1,629.7 20.1 36.5 1,326.7 0.8 245.5 

Sensitivity Case 3 1,814.6 28.3 64.5 1,416.5 0.8 304.4 

 Delta vs. Base Case** 184.9 8.2 28.0 89.8 0.0 58.9 

 Delta, % 11% 41% 77% 7% 0% 24% 

 

* The hydrogen purchases are based on the same refineries operating in the Base Case as the 

Study Case and the Sensitivity Cases, respectively 

** Difference in reported delta values are due to rounding. 

DISPOSITION OF SURPLUS NGLS 

During the summer, the reduction in gasoline RVP would result in 850 MB/CD of 

NGLs being removed from the domestic gasoline pool in the Study Case and 934, 559, 

and 315 MB/CD in Sensitivity Cases 1, 2, and 3, respectively. The breakdown of the 

material rejected during the summer is summarized below: 
- 45 - 

Change in Summer NGL Supply vs. the Base Case, MB/CD 

 Study 

Case 

Sensitivity 

Case 1 

Sensitivity 

Case 2 

Sensitivity 

Case 3 

Additional 

Refinery 

Production 

 

 n-butane 73 71 72 57 

 Pentanes Plus 664 751 374 197 

Reduced Refinery 

Purchases 

 n-butane 7 9 7 7 

 Pentanes Plus 106 103 106 54 

Total Surplus 850 934 559 315 

Because refiners are already running at maximum volatility limits during the 

winter, there is no room to reabsorb these volumes into the winter gasoline pool. Other 

outlets would need to be found. The magnitude of these volumes would have a 

significant impact on the U.S. refining, chemicals, and NGL markets. It is estimated that 

investments required by refiners to modify their storage, loading, and unloading facilities 

to store and transport surplus summer NGLs would be nearly $1 billion for the Study 

Case, $1.1 billion for Sensitivity Case 1, $600 million for Sensitivity Case 2, and $400 

million for Sensitivity Case 3. For reasons discussed below, existing transportation and 

handling infrastructure outside the refinery gate likely cannot accommodate the 

additional NGLs volume without significant investments. The cost of these outside the 

battery limits investments has not been estimated as part of this study. 
- 46 - 

The following table presents a potential scenario for disposing of surplus NGLs: 

Potential Disposition of Surplus Refinery Produced NGLs, MB/CD 

Study 

Case 

Sensitivity 

Case 1 

Sensitivity 

Case 2 

Sensitivity 

Case 3 

Reduce imports of 

NGLs and light naphtha 160 160 160 80 

Increase exports of 

NGLs 150 150 150 140 

Displace ethylene 

cracker feedstock* 250 250 168 80 

Stockpile for winter 

consumption 75 75 33 15 

Consume as fuel, 

hydrogen feedstock, or 

other use. 

215 299 48 

 TOTAL 850 934 559 315 

* Excludes the displacement of imported NGLs and light naphtha that are accounted for in the first item above.

This scenario includes the elimination of all waterborne imports of NGLs, plus an 

increase in NGLs exports to a level exceeding demonstrated maximum export levels. 

Butane/pentane cracking for ethylene production also exceeds the historic maximum 

levels outlined in Section VIII of this report. While the level of exports and cracking are 

above historic maximum rates, these levels could be possible under market conditions 

which sufficiently depress the cost of butanes and pentanes to ethylene producers. 

The 15 - 75 MB/CD of surplus NGLs shown as stockpiled would be consumed 

during the winter primarily as ethylene cracker feedstock. This would require up to 14 

million barrels of underground salt dome storage and associated rail car unloading 

facilities. It is unlikely that this quantity of storage capacity would already be available, 

as it represents roughly 20% of the typical seasonal U.S. NGL inventory increase. 

Therefore, new salt dome storage and associated rail car unloading facilities would 
- 47 - 

likely be required. These facilities would be installed outside of the refinery and would 

likely be owned and operated by third parties. Their cost is not included this study. 

The scenario also includes a substantial quantity of NGLs being consumed in the 

Study Case and Sensitivity Case 1 as fuel, as feedstock for hydrogen, or other use. 

The proportion of NGLs consumed in each of these outlets would depend on individual 

refiner circumstances, economics, and preferences. 

While a portion of surplus NGLs in the Study and Sensitivity Cases may be 

transported by pipeline, the majority would likely be transported to the USGC by rail. It 

is estimated that an incremental 16,000 high-pressure rail cars would be required to 

transport NGLs to the USGC, corresponding to roughly 900 rail car loadings per day. 

The number of rail cars required represents roughly 30% of the U.S. high-pressure rail 

car fleet,31 while the number of daily rail car loadings represents approximately 1% of 

total U.S. rail car loadings. 

The U.S. rail car construction industry appears to have the ability to produce 

20,000 tank cars per year, with less than 10,000 per year forecasted to be constructed 

in the near term.32 However, the lead time for delivery may depend on the backlog at 

construction facilities. 

The disposition of nearly 600 to 1,000 MB/CD of additional NGLs in the Study 

Case and Sensitivity Cases 1 and 2 would be very challenging, would require new 

transportation infrastructure, and would impact essentially all major U.S. hydrocarbon 

processing industries. The 300 MB/CD of additional NGLs in Sensitivity Case 3 would 

be less challenging, but some investment in storage and transportation infrastructure 

would still be required. While it may be feasible, sufficient time must be allowed for the 

design, permitting, and construction of the required facilities, or significant disruptions 

 

31 Baker & O’Brien estimate. 

32 Trinity Rail Presentation at NGFA Ag Transportation Symposium, May 12, 2009. Reference to Global 

Insight May 2009 forecast. 
- 48 - 

could occur across the refining, petrochemical, NGL, and transportation industries. If 

refiners are unable to dispose of the projected volumes, it may be difficult to achieve the 

gasoline production rates shown in the Study and Sensitivity Cases, and the gasoline 

shortfall would be worse than what is shown. 

GREENHOUSE GAS EMISSIONS 

The additional hydrotreating and fractionation required in the Study and 

Sensitivity Cases would result in an increase in CO2 emission from refineries that 

continue to operate as shown below. 

Incremental CO2 Emissions 

Tonnes/CD 

CO2 Emissions 

TOTAL 

U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

 Base Case* 717,811 48,248 137,968 375,030 24,241 132,323 

Study Case 727,748 48,667 140,932 380,321 24,892 132,935 

Delta 9,936 419 2,964 5,292 650 612 

 

 Base Case* 708,840 48,248 135,811 368,215 24,241 132,323 

Sensitivity Case 1 724,976 49,245 139,793 376,141 25,276 134,521 

Delta 16,136 997 3,982 7,926 1,035 2,197 

 Base Case* 717,811 48,248 137,968 375,030 24,241 132,323 

Sensitivity Case 2 725,411 48,502 139,524 379,316 24,583 133,486 

Delta 7,599 253 1,555 4,286 342 1,163 

 Base Case* 717,811 48,248 137,968 375,030 24,241 132,323 

Sensitivity Case 3 724,951 48,502 139,429 379,135 24,506 133,379 

Delta 7,140 253 1,461 4,105 264 1,056 

*The CO2 values are based on the same refineries operating in the Base Case as the 

Study Case and the Sensitivity Cases, respectively. 

Assuming foreign refineries experience a proportional increase, the combined 

increase in CO2 emissions would be 2.9 to 7.4 million tonnes per year. As a result of 

shifting emissions overseas, incurring additional emissions associated with fuel 
- 49 - 

transport (not included here), and increasing emissions for operating refineries in the 

U.S., aggregate global CO2 emissions increase. 

TOTAL COMPLIANCE COSTS 

The downgrade in NGLs value is by far the largest compliance cost. Capital 

investment costs are second. Refinery investment costs for the compliance responses 

discussed above are $11.5 billion in the Study Case and $9.5 to $17.3 billion in the 

Sensitivity Cases. As mentioned, there are additional investments that would be 

required outside the refineries that are not included in these totals. 

The total compliance costs that would be borne by refiners for the Study and 

Sensitivity Cases are shown below: 

Total Annual Compliance Cost 

2009 $MM per Year 

 Study Case Sensitivity 

Case 1 

Sensitivity 

Case 2 

Sensitivity 

Case 3 

Purchased Hydrogen 305 546 354 354 

Other Variable Operating 

Expenses 498 749 342 303 

Fixed Operating Expenses 269 404 37 35 

Capital Recovery 1,953 2,949 1,693 1,628 

Light Hydrocarbon 

Downgrading 7,368 8,572 4,363 2,528 

Total Cost 10,393 13,220 6,789 4,848 

Relative to the Study Case, additional NGLs were blended into gasoline in 

Sensitivity Cases 2 and 3. Because some of this material need to be hydrotreated, 

purchased hydrogen costs were slightly higher in Sensitivity Cases 2 and 3. 
- 50 - 

In the graphs that follow, the annualized and summer individual refinery 

compliance costs are plotted in cents per gallon (¢/Gal.) of gasoline for the Study and 

Sensitivity Cases vs. cumulative barrels of gasoline supplied by U.S. refiners. 

2016 Domestic Gasoline Production (excluding Ethanol) 

Study Case

Cost vs. Volume

(10)

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline Production

¢/Gal.

Annualized Costs

Summer Costs

2016 Domestic Gasoline Production (excluding Ethanol) 

Sensitivity Case 1

Cost vs. Volume

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline Production

¢/Gal.

Annualized Costs

Summer Costs

 
- 51 - 

2016 Domestic Gasoline Production (excluding Ethanol) 

Sensitivity Case 2

Cost vs. Volume

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline Production

¢/Gal.

Annualized Costs

Summer Costs

 

2016 Domestic Gasoline Production (excluding Ethanol) 

Sensitivity Case 3

Cost vs. Volume

(10)

0

10

20

30

40

50

60

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Cumulative U.S. Gasoline Production (excluding Ethanol)

MMB/D

Increase in Cost of Gasoline 

Production

¢/Gal.

Annualized Costs

Summer Costs

COMPARISON TO AAM REPORT 

The results of this study are significantly different than those in the AAM Report. 

While a detailed reconciliation was not performed, there are several obvious differences 
- 52 - 

in approach. The refining section of the AAM Report only considered refineries in 

PADDs 1, 2, and 3. According to the AAM Report, modeling was done using three 

aggregate refinery models, one for each of these PADDs.33 Our analysis was done with 

individual models of 112 refineries, including refineries in PADDs 4 and 5. As noted in 

the AAM Report, the aggregate modeling approach may lead to “over-optimization” and 

an understatement of compliance costs.34

The AAM Report does not appear to consider the lost value of NGLs that would 

be removed from the gasoline pool, and their estimate of the volumes that would be 

removed seem to be much smaller than those reported herein. The AAM Report 

assumes that many refineries already have the capability to produce 5 ppm sulfur 

gasoline.35 Our analysis indicates that most will require capital investments to produce 

5 or 10 ppm sulfur gasoline. The AAM Report also uses a capital cost estimate for new 

FCC gasoline hydrotreater capacity that is approximately 25% of the figure used in this 

report.36 The AAM analysis does not appear to include FCC feed hydrodesulfurization 

revamps, expansions, or new units. These items were included in our analysis. 

 

33 Alliance of Automobile Manufacturers, “National Clean Gasoline: An Investigation of Costs and 

Benefits,” June 2009, p.1-2. 34 Ibid, p. 1-23. 35 Ibid, p.1-19. 36 Ibid, p.1-19. 
- 53 - 

X. CONCLUSIONS

The results of our study are significantly different than those in the AAM Report. 

We found that implementation of standards considered in the Study and Sensitivity 

Cases would have a significant negative impact on gasoline production cost and supply. 

Four to seven refineries could shut down rather than make the investments required to 

meet the standards. Supplies of domestically-produced hydrocarbon gasoline are 

projected to decline by 8 to 19% in the summer, as a result of refinery shutdowns and 

the removal of NGLs from the gasoline pools. Additional hydrotreating and fractionation 

in the Study and Sensitivity Cases result in increased CO2 emissions at the refineries 

that continue to operate. 

If gasoline consumption remains at Base Case levels, gasoline imports would 

have to double, increasing U.S. vulnerability to supply disruptions. Distillate and NGL 

production at domestic refineries would increase as gasoline production declines. 

Additional exports of both would likely result to balance those markets. 

Required compliance investments by refiners are estimated at $9 to 17 billion. 

On an ongoing annual basis, compliance costs are estimated at $5 to $13 billion. 

Allocating these costs to gasoline produced yields marginal costs of 12¢ to 25¢/Gal. on 

an annualized basis. 
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

2005/2006 Summer4

Conventional 6,107 2,019 2,169 1,087 331 501

Reformulated 2,019 1,248 360 323 - 88

CARB 1,059 1,059

TOTAL 9,185 3,267 2,529 1,410 331 1,648

2005/2006 Winter5

Conventional 5,815 1,951 2,045 1,061 300 458

Reformulated 1,978 1,207 359 313 - 99

CARB 1,023 1,023

TOTAL 8,816 3,158 2,404 1,374 300 1,580

2005/2006 Annual

Conventional 5,966 1,984 2,106 1,076 316 484

Reformulated 1,995 1,228 360 316 - 91

CARB 1,039 1,039

TOTAL 9,000 3,212 2,466 1,392 316 1,614

2016 Summer

E85 65.4 0.4 64.7 0.1 0.0 0.2

Conventional 6,270 2,132 2,080 1,172 369 517

Reformulated 2,101 1,307 358 345 - 91

CARB 1,118 1,118

TOTAL 9,555 3,440 2,503 1,517 369 1,726

2016 Winter

E85 62.7 0.4 62.0 0.1 0.0 0.2

Conventional 8,027 3,298 2,338 1,455 354 583

CARB 1,072 - - - 1,072 - 

TOTAL 9,162 3,299 2,400 1,455 354 1,655

2016 Annual

E85 64.1 0.4 63.4 0.1 0.0 0.2

Conventional 7,149 2,715 2,209 1,313 361 550

Reformulated 1,051 654 179 172 - 46

CARB 1,095 - - - 1,095 -

TOTAL 9,358 3,369 2,451 1,486 361 1,690

NOTES:

(1)

(2)

(3) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

(4)

(5)

TABLE 1

U.S. Gasoline Consumption1,2,3

(Thousands of Barrels Per Day - Including Ethanol)

"Winter" is defined as October through March. 2005/2006 data represent average consumption during the winter months of 2005 and 2006. Annual average 

consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted using actual 2005/2006 consumption as reported by EIA in 

Petroleum Marketing Monthly.

Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted using actual 2005/2006 consumption as 

reported by EIA in Petroleum Marketing Monthly.

2005/2006 represents average consumption during 2005 and 2006 as reported in the EIA Petroleum Marketing Monthly.

"Summer" is defined as April through September. 2005/2006 data represent average consumption during the summer periods of 2005 and 2006. Annual 

average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted using actual 2005/2006 consumption as reported by 

EIA in Petroleum Marketing Monthly.
AEO Capacity 2 TOTAL U.S. PADD 1 PADD 2 PADD 3 

June 2009 Capacities3

Crude 17,616 17,676 1,715 3,723 8,499 

 

FCC 5,757 710 1,187 2,854 

 

Hydrocracker 1,685 56 249 835 

 

Coker 2,372 92 387 1,283 

 

Reformer 3,523 297 838 1,715 

 

Isom 509 16 168 169 

 

2016 Capacities

Crude 17,616 17,603 1,279 3,713 8,933 

 

FCC 5,644 585 1,200 2,854 

 

Hydrocracker 1,767 26 249 948 

 

Coker 2,638 44 490 1,472 

 

Reformer 3,605 230 840 1,861 

 

Isom 559 11 158 219 

 

NOTES:

(1)(2)(3)

Table 11 - Annual Energy Outlook 2010 Early Release, December 14, 2009.

TABLE 2

Based on PRISM TM 2nd Quarter 2009 estimated capacity.

U.S. Refining Capacities1

(Thousands of Barrels Per Day)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Conventional 547.1 4,924 5,471 318 1,570 2,842 

Reformulated 180.6 1,626 1,806 358 345 1,068 

CARB 96.4 868 964 - - - 

TOTAL 873 7,435 8,307 677 1,980 3,910 

Gasoline Consumption5

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Conventional 627.0 5,643 6,270 2,132 2,080 1,172 

Reformulated 210.1 1,891 2,101 1,307 358 345 

CARB 111.8 1,006 1,118 - - - 

TOTAL 997 8,558 9,555 3,440 2,503 1,517 

E85 - - - - - 

Conventional (719) (799) (1,814) (510) 1,670 

Reformulated (265) (295) (949) (12) 723 

CARB (139) (154) - - - 

TOTAL (1,123) (1,248) (2,763) (523) 2,393 

NOTES:

(1)(3)

TABLE 3

 Base Case 2016 Summer Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added 

Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendst

(6)(5)

Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations amiles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported in the P

Domestic Refinery Over/(Under) Supply6

"Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted as reported by the EIA in Petroleum Marketing Monthly.

(4)
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 46.4 16.3 62.7 0.4 62.0 0.1 

Conventional 701.3 6,312 7,013 657 1,827 3,787 

CARB 92.2 830 922 - - - 

TOTAL 840 7,158 7,998 657 1,889 3,787 

Gasoline Consumption5

E85 46.4 16.3 62.7 0.4 62.0 0.1 

Conventional 802.7 7,225 8,027 3,298 2,338 1,455 CARB 107.2 965 1,072 - - - 

TOTAL 956 8,206 9,162 3,299 2,400 1,455 

E85 - - - - - Conventional (913) (1,015) (2,641) (511) 2,332 CARB (135) (150) - - - 

TOTAL (1,048) (1,164) (2,641) (511) 2,332 

NOTES:

(1)(2)(3)

TABLE 4

Base Case 2016 Winter Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

Domestic Refinery Over/(Under) Supply6

"Winter" is defined as October through March. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted as reported by the EIA in Petroleum Marketing Monthly.

(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blen

(4) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol adde

Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 

(5) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations 

vehicle miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as report
Ethanol 2 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production3

E85 47.4 16.6 64.0 0.4 63.4 0.1 

Conventional 624.2 5,618 6,242 488 1,698 3,315 

Reformulated 90.3 813 903 179 173 534 

CARB 94.3 849 943 - - - 

TOTAL 856 7,296 8,152 667 1,934 3,849 

Gasoline Consumption4

E85 47.4 16.7 64.1 0.4 63.4 0.1 

Conventional 714.9 6,434 7,149 2,715 2,209 1,313 

Reformulated 105.1 946 1,051 654 179 172 

CARB 109.5 986 1,095 - - - 

TOTAL 977 8,382 9,358 3,369 2,451 1,486 

E85 (0.0) (0.0) - - - 

Conventional (816) (907) (2,228) (511) 2,001 

Reformulated (133) (147) (475) (6) 362 

CARB (137) (152) - - - 

TOTAL (1,085) (1,206) (2,702) (517) 2,363 

NOTES:

(1)(2)(4) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations a

vehicle miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reporte

(5) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

Domestic Refinery Over/(Under) Supply5

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blends

(3)

TABLE 5

Base Case 2016 Annual Supply Balance1

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 
AEO 

Utilization 2 TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

2009 Utilization3

Crude 80% 83% 76% 85% 83% 87% FCC 86% 81% 85% 89% 88% Hydrocracker 80% 84% 87% 74% 89% Coker 83% 71% 83% 84% 68% Reformer 86% 84% 91% 83% 94% Isom 84% 58% 89% 80% 66% 

2016 Utilization4

Crude 83% 82% 85% 86% 80% 93% FCC 87% 82% 87% 86% 94% Hydrocracker 91% 97% 95% 91% 85% Coker 86% 90% 88% 86% 81% Reformer 83% 82% 82% 81% 93% Isom 89% 82% 95% 87% 93% 

NOTES:

(1)(2)(3)(4)

Based on PRISM 2nd Quarter 2009 estimated capacity and unit rates for 4th Quarter 2008 - 3rd Quarter 2009.

TABLE 6

U.S. Refining Utilization (Based on Calendar Day Capacity)1

Based on PRISM simulations.

Table 11 - Annual Energy Outlook 2010 Early Release, December 14, 2009. Defined as Total Crude Supply divided by Domestic Refinery DisAs described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 7.4 7.0 8.2 7.3 8.5 6.6

Olefins, Vol.% 9.9% 12.6% 10.2% 10.6% 10.6% 6.1%

Aromatics, Vol.% 29.3% 28.4% 30.6% 29.5% 27.8% 27.7%

Benzene, Vol.% 0.58% 0.60% 0.64% 0.52% 0.95% 0.57%

Sulfur, wppm 24.7 29.8 29.9 26.9 28.9 7.8

CBOB

RVP, psi 8.4 8.9 8.7 8.0 8.5 9.0

Olefins, Vol.% 11.6% 19.1% 10.5% 11.6% 10.6% 11.4%

Aromatics, Vol.% 33.4% 35.7% 33.8% 33.6% 27.8% 32.6%

Benzene, Vol.% 0.59% 0.60% 0.70% 0.49% 0.95% 0.57%

Sulfur, wppm 26.8 30.3 31.0 25.2 28.9 17.0

RBOB

RVP, psi 5.4 5.3 5.6 5.3 - 5.4

Olefins, Vol.% 7.8% 6.9% 8.9% 7.8% - 4.5%

Aromatics, Vol.% 18.6% 21.9% 16.1% 18.6% - 8.1%

Benzene, Vol.% 0.56% 0.61% 0.35% 0.61% - 0.63%

Sulfur, wppm 29.6 29.3 24.6 31.8 - 12.6

CARBOB

RVP, psi 5.7 - - - - 5.7

Olefins, Vol.% 4.0% - - - - 4.0%

Aromatics, Vol.% 26.5% - - - - 26.5%

Benzene, Vol.% 0.56% - - - - 0.56%

Sulfur, wppm 3.8 - - - - 3.8

NOTES:

(1)

(2)

(3)

"Summer" is defined as April through September. 

TABLE 7A

Base Case 2016 Summer Regional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)

PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 8.6 8.2 9.2 8.5 9.5 7.9

Olefins, Vol.% 8.9% 11.3% 9.2% 9.5% 9.5% 5.5%

Aromatics, Vol.% 26.4% 25.6% 27.5% 26.6% 25.0% 25.0%

Benzene, Vol.% 0.53% 0.55% 0.58% 0.48% 0.86% 0.52%

Sulfur, wppm 23.2 27.7 27.8 25.2 26.9 8.0

Conventional

RVP, psi 9.4 9.9 9.7 9.1 9.5 9.9

Olefins, Vol.% 10.5% 17.2% 9.4% 10.5% 9.5% 10.2%

Aromatics, Vol.% 30.0% 32.1% 30.4% 30.3% 25.0% 29.3%

Benzene, Vol.% 0.54% 0.55% 0.64% 0.45% 0.86% 0.52%

Sulfur, wppm 25.0 28.2 28.8 23.6 26.9 16.3

Reformulated

RVP, psi 6.8 6.8 7.0 6.8 - 6.9

Olefins, Vol.% 7.0% 6.2% 8.0% 7.0% - 4.0%

Aromatics, Vol.% 16.7% 19.7% 14.5% 16.8% - 7.2%

Benzene, Vol.% 0.51% 0.55% 0.32% 0.55% - 0.57%

Sulfur, wppm 27.5 27.3 23.1 29.5 - 12.3

CARB

RVP, psi 7.1 - - - - 7.1

Olefins, Vol.% 3.6% - - - - 3.6%

Aromatics, Vol.% 23.8% - - - - 23.8%

Benzene, Vol.% 0.51% - - - - 0.51%

Sulfur, wppm 4.5 - - - - 4.5

NOTES:

(1)

(2)

(3)

"Summer" is defined as April through September. 

TABLE 7B

Base Case 2016 Summer Regional Finished Gasoline Qualities1,2

(includes Ethanol)

PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 12.2 13.9 13.5 12.5 12.8 8.7

Olefins, Vol.% 9.7% 11.4% 10.1% 10.4% 10.3% 6.1%

Aromatics, Vol.% 25.5% 24.3% 25.9% 25.4% 24.8% 25.7%

Benzene, Vol.% 0.56% 0.56% 0.63% 0.50% 0.92% 0.52%

Sulfur, wppm 23.7 28.7 28.9 25.7 28.7 7.1

CBOB

RVP, psi 12.9 13.9 13.5 12.5 12.8 12.3

Olefins, Vol.% 10.4% 11.4% 10.1% 10.4% 10.3% 10.4%

Aromatics, Vol.% 25.6% 24.3% 25.9% 25.4% 24.8% 28.8%

Benzene, Vol.% 0.56% 0.56% 0.63% 0.50% 0.92% 0.60%

Sulfur, wppm 26.4 28.7 28.9 25.7 28.7 15.0

CARBOB

RVP, psi 7.1 - - - - 7.1

Olefins, Vol.% 4.2% - - - - 4.2%

Aromatics, Vol.% 24.3% - - - - 24.3%

Benzene, Vol.% 0.49% - - - - 0.49%

Sulfur, wppm 3.6 - - - - 3.6

NOTES:

(1)

(2)

(3)

"Winter" is defined as October through March. 

TABLE 7C

Base Case 2016 Winter Regional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)

PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 12.8 14.3 13.9 13.1 13.3 9.7

Olefins, Vol.% 8.7% 10.3% 9.1% 9.4% 9.3% 5.5%

Aromatics, Vol.% 22.9% 21.8% 23.3% 22.9% 22.3% 23.1%

Benzene, Vol.% 0.51% 0.51% 0.57% 0.46% 0.83% 0.48%

Sulfur, wppm 22.2 26.7 26.9 24.0 26.7 7.4

Conventional

RVP, psi 13.4 14.3 13.9 13.1 13.3 12.9

Olefins, Vol.% 9.4% 10.3% 9.1% 9.4% 9.3% 9.4%

Aromatics, Vol.% 23.0% 21.8% 23.3% 22.9% 22.3% 25.9%

Benzene, Vol.% 0.51% 0.51% 0.57% 0.46% 0.83% 0.54%

Sulfur, wppm 24.6 26.7 26.9 24.0 26.7 14.4

CARB

RVP, psi 8.3 - - - - 8.3

Olefins, Vol.% 3.8% - - - - 3.8%

Aromatics, Vol.% 21.9% - - - - 21.9%

Benzene, Vol.% 0.45% - - - - 0.45%

Sulfur, wppm 4.3 - - - - 4.3

NOTES:

(1)

(2)

(3)

"Winter" is defined as October through March. 

TABLE 7D

Base Case 2016 Winter Regional Finished Gasoline Qualities1,2

(includes Ethanol)

PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 65.4 0.4 64.7 0.1 0.0 Conventional Gasoline 5,471 318 1,570 2,842 344 Reformulated Gasoline 1,806 358 345 1,068 - 

CARB Gasoline 964 - - - - 

Jet Fuel 1,488 79 263 666 41 

Distillates 4,245 331 893 2,345 170 

Pentanes 92 2 - 30 - Other4 306 4,126 722 2,184 128 

TOTAL 18,258 1,395 3,858 9,136 683 

NOTES:

(1)(4) Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleu

miscellaneous petroleum products.

(3)

TABLE 8

Base Case 2016 Summer Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% 

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. "Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seaadjusted using actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 62.7 0.4 62.0 0.1 0.0 

Conventional Gasoline 7,013 657 1,827 3,787 332 

CARB Gasoline 922 - - - - 

Jet Fuel 1,488 96 279 668 39 

Distillates 4,383 334 967 2,421 173 

Pentanes 18 - - 6 - 

Other4 258 3,284 572 1,711 114 

TOTAL 17,170 1,345 3,708 8,594 657 

NOTES:

(4)

"Winter" is defined as October through March. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seaso

using actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petrolmiscellaneous petroleum products.

(3) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 

TABLE 9

Base Case 2016 Winter Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

(1)
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline 609.4 5,484 6,094 581 1,477 3,350 

CARB 86.2 776 862 - - - 

TOTAL 744 6,278 7,022 581 1,541 3,350 

Gasoline Consumption5

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline 837.2 7,534 8,372 3,440 2,438 1,517 

CARB 111.8 1,006 1,118 - - - 

TOTAL 997 8,558 9,555 3,440 2,503 1,517 

E85 - - - - - 

Lower Sulfur, Lower RVP Gasoline (2,050) (2,278) (2,859) (961) 1,833 

CARB (230) (256) - - - 

TOTAL (2,280) (2,533) (2,859) (961) 1,833 

NOTES:

(1)(2)(3)(5) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are b

miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported in the Petr

(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendstock

(4)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

TABLE 10

Study Case 2016 Summer Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

Domestic Refinery Over/(Under) Supply6

"Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted usi

as reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added to d

Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 46.4 16.3 62.7 0.4 62.0 0.1 

Lower Sulfur, Lower RVP Gasoline 687.1 6,184 6,871 657 1,733 3,787 

CARB 92.2 830 922 - - - 

TOTAL 826 7,030 7,856 657 1,795 3,787 

Gasoline Consumption5

E85 46.4 16.3 62.7 0.4 62.0 0.1 

Lower Sulfur, Lower RVP Gasoline 802.7 7,225 8,027 3,298 2,338 1,455 

CARB 107.2 965 1,072 - - - 

TOTAL 956 8,206 9,162 3,299 2,400 1,455 

E85 - - - - - 

Lower Sulfur, Lower RVP Gasoline (1,041) (1,156) (2,641) (605) 2,332 

CARB (135) (150) - - - 

TOTAL (1,176) (1,306) (2,641) (605) 2,332 

NOTES:

(1)

(3) The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendst(4) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added 

Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 

(5) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations a

miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported in the P

(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

TABLE 11

Study Case 2016 Winter Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

Domestic Refinery Over/(Under) Supply6

"Winter" is defined as October through March. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted usireported by the EIA in Petroleum Marketing Monthly.
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 5.5 5.4 5.4 5.4 5.4 5.5

Olefins, Vol.% 7.2% 8.3% 7.6% 7.6% 8.8% 4.6%

Aromatics, Vol.% 32.4% 31.7% 33.7% 33.5% 31.4% 28.4%

Benzene, Vol.% 0.64% 0.73% 0.77% 0.57% 0.82% 0.59%

Sulfur, wppm 10.7 11.7 12.0 12.2 12.6 4.6

Lower Sulfur, Lower RVP Gasoline

RVP, psi 5.4 5.4 5.4 5.4 5.4 5.4

Olefins, Vol.% 7.6% 8.3% 7.6% 7.6% 8.8% 5.8%

Aromatics, Vol.% 33.1% 31.7% 33.7% 33.5% 31.4% 31.0%

Benzene, Vol.% 0.65% 0.73% 0.77% 0.57% 0.82% 0.70%

Sulfur, wppm 11.7 11.7 12.0 12.2 12.6 6.8

CARBOB

RVP, psi 5.6 - - - - 5.6

Olefins, Vol.% 4.0% - - - - 4.0%

Aromatics, Vol.% 27.2% - - - - 27.2%

Benzene, Vol.% 0.53% - - - - 0.53%

Sulfur, wppm 3.5 - - - - 3.5

NOTES:

(1)

(2)

(3) PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

"Summer" is defined as April through September. 

TABLE 12A

Study Case 2016 Summer Regional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 6.9 6.9 6.9 6.9 6.9 7.0

Olefins, Vol.% 6.5% 7.4% 6.9% 6.9% 7.9% 4.1%

Aromatics, Vol.% 29.1% 28.5% 30.3% 30.1% 28.3% 25.6%

Benzene, Vol.% 0.58% 0.67% 0.70% 0.52% 0.75% 0.54%

Sulfur, wppm 10.7 11.5 11.8 11.9 12.3 5.1

Lower Sulfur, Lower RVP Gasoline

RVP, psi 6.9 6.9 6.9 6.9 6.9 6.9

Olefins, Vol.% 6.9% 7.4% 6.9% 6.9% 7.9% 5.2%

Aromatics, Vol.% 29.8% 28.5% 30.3% 30.1% 28.3% 27.9%

Benzene, Vol.% 0.60% 0.67% 0.70% 0.52% 0.75% 0.64%

Sulfur, wppm 11.6 11.5 11.8 11.9 12.3 7.1

CARBOB

RVP, psi 7.0 - - - - 7.0

Olefins, Vol.% 3.6% - - - - 3.6%

Aromatics, Vol.% 24.5% - - - - 24.5%

Benzene, Vol.% 0.49% - - - - 0.49%

Sulfur, wppm 4.2 - - - - 4.2

NOTES:

(1)

(2)

(3) PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

"Summer" is defined as April through September. 

TABLE 12B

Study Case 2016 Summer Regional Finished Gasoline Qualities1,2

(includes Ethanol)
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 12.2 13.9 13.5 12.5 12.8 8.5

Olefins, Vol.% 9.7% 11.4% 10.1% 10.4% 10.3% 6.0%

Aromatics, Vol.% 25.4% 24.3% 25.5% 25.4% 24.8% 25.7%

Benzene, Vol.% 0.56% 0.56% 0.65% 0.50% 0.92% 0.53%

Sulfur, wppm 5.9 6.3 6.3 6.3 6.3 4.2

Lower Sulfur, Lower RVP Gasoline

RVP, psi 12.9 13.9 13.5 12.5 12.8 12.0

Olefins, Vol.% 10.4% 11.4% 10.1% 10.4% 10.3% 10.6%

Aromatics, Vol.% 25.5% 24.3% 25.5% 25.4% 24.8% 29.0%

Benzene, Vol.% 0.57% 0.56% 0.65% 0.50% 0.92% 0.61%

Sulfur, wppm 6.3 6.3 6.3 6.3 6.3 5.7

CARBOB

RVP, psi 7.1 - - - - 7.1

Olefins, Vol.% 4.2% - - - - 4.2%

Aromatics, Vol.% 24.3% - - - - 24.3%

Benzene, Vol.% 0.49% - - - - 0.49%

Sulfur, wppm 3.6 - - - - 3.6

NOTES:

(1)

(2)

(3) PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

"Winter" is defined as October through March. 

TABLE 12C

Study Case 2016 Winter Regional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 12.8 14.3 14.0 13.1 13.3 9.5

Olefins, Vol.% 8.7% 10.3% 9.1% 9.3% 9.3% 5.4%

Aromatics, Vol.% 22.8% 21.8% 23.0% 22.9% 22.3% 23.1%

Benzene, Vol.% 0.51% 0.51% 0.59% 0.46% 0.83% 0.48%

Sulfur, wppm 6.4 6.7 6.7 6.7 6.7 4.8

Lower Sulfur, Lower RVP Gasoline

RVP, psi 13.4 14.3 14.0 13.1 13.3 12.6

Olefins, Vol.% 9.4% 10.3% 9.1% 9.3% 9.3% 9.5%

Aromatics, Vol.% 22.9% 21.8% 23.0% 22.9% 22.3% 26.1%

Benzene, Vol.% 0.52% 0.51% 0.59% 0.46% 0.83% 0.56%

Sulfur, wppm 6.7 6.7 6.7 6.7 6.7 6.1

CARBOB

RVP, psi 8.3 - - - - 8.3

Olefins, Vol.% 3.8% - - - - 3.8%

Aromatics, Vol.% 21.9% - - - - 21.9%

Benzene, Vol.% 0.45% - - - - 0.45%

Sulfur, wppm 4.3 - - - - 4.3

NOTES:

(1)

(2)

(3) PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

"Winter" is defined as October through March. 

TABLE 12D

Study Case 2016 Winter Regional Finished Gasoline Qualities1,2

(includes Ethanol)
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 65.4 0.4 64.7 0.1 0.0 Lower Sulfur, Lower RVP Gasoline 6,094 581 1,477 3,350 287 

CARB Gasoline 862 - - - - 

Jet Fuel 1,494 79 273 672 41 

Distillates 4,418 353 958 2,434 179 

Pentanes 746 62 172 369 24 

Other4 312 4,070 683 2,200 134 

TOTAL 17,750 1,387 3,626 9,026 665 

NOTES:

(1)(2)(4) Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleu

miscellaneous petroleum products.As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

(3)

TABLE 13

Study Case 2016 Summer Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% 

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. "Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seaadjusted using actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 62.7 0.4 62.0 0.1 0.0 Lower Sulfur, Lower RVP Gasoline 6,871 657 1,733 3,787 332 

CARB Gasoline 922 - - - - 

Jet Fuel 1,474 96 265 668 39 

Distillates 4,362 334 947 2,421 173 

Pentanes 18 - - 6 - 

Other4 258 3,196 534 1,711 114 

TOTAL 16,906 1,345 3,542 8,594 657 

NOTES:

(2)(4) Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleu

miscellaneous petroleum products.

(3)

TABLE 14

Study Case 2016 Winter Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% 

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. "Winter" is defined as October through March. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonusing actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.

(1)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline 586.3 5,276 5,863 568 1,434 3,183 

CARB 84.9 765 849 - - - 

TOTAL 720 6,058 6,777 568 1,499 3,183 

Gasoline Consumption5

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline 837.2 7,534 8,372 3,440 2,438 1,517 

CARB 111.8 1,006 1,118 - - - 

TOTAL 997 8,558 9,555 3,440 2,503 1,517 

E85 - - - - - 

Lower Sulfur, Lower RVP Gasoline (2,258) (2,509) (2,872) (1,004) 1,666 

CARB (242) (269) - - - 

TOTAL (2,500) (2,778) (2,872) (1,004) 1,666 

NOTES:

(1)(2)(3)(5) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are ba

miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported in the Petrol

(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendstocks

(4)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

TABLE 15

Sensitivity Case 1 2016 Summer Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

Domestic Refinery Over/(Under) Supply6

"Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted using as reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added to doGasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 46.4 16.3 62.7 0.4 62.0 0.1 

Lower Sulfur, Lower RVP Gasoline 674.5 6,071 6,745 657 1,701 3,694 

CARB 92.2 830 922 - - - 

TOTAL 813 6,917 7,730 657 1,763 3,694 

Gasoline Consumption5

E85 46.4 16.3 62.7 0.4 62.0 0.1 

Lower Sulfur, Lower RVP Gasoline 802.7 7,225 8,027 3,298 2,338 1,455 

CARB 107.2 965 1,072 - - - 

TOTAL 956 8,206 9,162 3,299 2,400 1,455 

E85 - - - - - 

Lower Sulfur, Lower RVP Gasoline (1,154) (1,282) (2,641) (637) 2,239 

CARB (135) (150) - - - 

TOTAL (1,289) (1,432) (2,641) (637) 2,239 

NOTES:

(1)(2)(3)(4) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added to 

Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 

(5) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are 

vehicle miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported i

TABLE 16

Sensitivity Case 1 2016 Winter Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

Domestic Refinery Over/(Under) Supply6

"Winter" is defined as October through March. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted usinas reported by the EIA in Petroleum Marketing Monthly.

(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendsto
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 5.5 5.4 5.4 5.4 5.4 5.5

Olefins, Vol.% 7.1% 8.0% 7.4% 7.8% 7.8% 4.3%

Aromatics, Vol.% 32.8% 31.8% 33.8% 34.0% 31.6% 29.1%

Benzene, Vol.% 0.65% 0.74% 0.77% 0.59% 0.85% 0.58%

Sulfur, wppm 4.9 5.1 5.1 5.3 5.2 3.7

Lower Sulfur, Lower RVP Gasoline

RVP, psi 5.4 5.4 5.4 5.4 5.4 5.4

Olefins, Vol.% 7.5% 8.0% 7.4% 7.8% 7.8% 5.3%

Aromatics, Vol.% 33.8% 31.8% 33.8% 34.0% 31.6% 36.7%

Benzene, Vol.% 0.66% 0.74% 0.77% 0.59% 0.85% 0.68%

Sulfur, wppm 5.2 5.1 5.1 5.3 5.2 4.4

CARBOB

RVP, psi 5.6 - - - - 5.6

Olefins, Vol.% 3.8% - - - - 3.8%

Aromatics, Vol.% 25.6% - - - - 25.6%

Benzene, Vol.% 0.53% - - - - 0.53%

Sulfur, wppm 3.4 - - - - 3.4

NOTES:

(1)

(2)

(3) PRISM simulation results.

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

"Summer" is defined as April through September. 

TABLE 17A

Sensitivity Case 1 2016 SummerRegional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 6.9 6.9 6.9 6.9 6.9 7.0

Olefins, Vol.% 6.4% 7.2% 6.6% 7.0% 7.0% 3.9%

Aromatics, Vol.% 29.5% 28.6% 30.5% 30.6% 28.4% 26.2%

Benzene, Vol.% 0.59% 0.68% 0.70% 0.53% 0.77% 0.52%

Sulfur, wppm 5.5 5.6 5.6 5.8 5.7 4.4

Lower Sulfur, Lower RVP Gasoline

RVP, psi 6.9 6.9 6.9 6.9 6.9 6.9

Olefins, Vol.% 6.8% 7.2% 6.6% 7.0% 7.0% 4.8%

Aromatics, Vol.% 30.4% 28.6% 30.5% 30.6% 28.4% 33.0%

Benzene, Vol.% 0.60% 0.68% 0.70% 0.53% 0.77% 0.62%

Sulfur, wppm 5.6 5.6 5.6 5.8 5.7 4.9

CARBOB

RVP, psi 7.0 - - - - 7.0

Olefins, Vol.% 3.4% - - - - 3.4%

Aromatics, Vol.% 23.0% - - - - 23.0%

Benzene, Vol.% 0.48% - - - - 0.48%

Sulfur, wppm 4.1 - - - - 4.1

NOTES:

(1)

(2)

(3)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

PRISM simulation results.

"Summer" is defined as April through September. 

TABLE 17B

Sensitivity Case 1 2016 SummerRegional Finished Gasoline Qualities1,2

(includes Ethanol)
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 12.2 13.9 13.5 12.5 12.8 8.5

Olefins, Vol.% 9.7% 11.4% 10.1% 10.4% 10.3% 6.0%

Aromatics, Vol.% 25.3% 24.3% 25.5% 25.3% 24.8% 25.7%

Benzene, Vol.% 0.56% 0.56% 0.64% 0.50% 0.92% 0.53%

Sulfur, wppm 3.4 3.3 3.4 3.3 3.3 3.5

Lower Sulfur, Lower RVP Gasoline

RVP, psi 12.9 13.9 13.5 12.5 12.8 12.0

Olefins, Vol.% 10.4% 11.4% 10.1% 10.4% 10.3% 10.6%

Aromatics, Vol.% 25.5% 24.3% 25.5% 25.3% 24.8% 29.0%

Benzene, Vol.% 0.57% 0.56% 0.64% 0.50% 0.92% 0.61%

Sulfur, wppm 3.3 3.3 3.4 3.3 3.3 3.2

CARBOB

RVP, psi 7.1 - - - - 7.1

Olefins, Vol.% 4.2% - - - - 4.2%

Aromatics, Vol.% 24.3% - - - - 24.3%

Benzene, Vol.% 0.49% - - - - 0.49%

Sulfur, wppm 3.6 - - - - 3.6

NOTES:

(1)

(2)

(3) PRISM simulation results.

"Winter" is defined as October through March. 

TABLE 17C

Sensitivity Case 1 2016 WinterRegional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 12.8 14.3 13.9 13.1 13.3 9.5

Olefins, Vol.% 8.7% 10.3% 9.1% 9.4% 9.3% 5.4%

Aromatics, Vol.% 22.8% 21.8% 23.0% 22.8% 22.3% 23.1%

Benzene, Vol.% 0.51% 0.51% 0.59% 0.46% 0.83% 0.48%

Sulfur, wppm 4.1 4.1 4.0 4.0 4.1 4.2

Lower Sulfur, Lower RVP Gasoline

RVP, psi 13.4 14.3 13.9 13.1 13.3 12.6

Olefins, Vol.% 9.4% 10.3% 9.1% 9.4% 9.3% 9.5%

Aromatics, Vol.% 22.9% 21.8% 23.0% 22.8% 22.3% 26.1%

Benzene, Vol.% 0.52% 0.51% 0.59% 0.46% 0.83% 0.56%

Sulfur, wppm 4.0 4.1 4.0 4.0 4.1 3.9

CARBOB

RVP, psi 8.3 - - - - 8.3

Olefins, Vol.% 3.8% - - - - 3.8%

Aromatics, Vol.% 21.9% - - - - 21.9%

Benzene, Vol.% 0.45% - - - - 0.45%

Sulfur, wppm 4.3 - - - - 4.3

NOTES:

(1)

(2)

(3) PRISM simulation results.

"Winter" is defined as October through March. 

TABLE 17D

Sensitivity Case 1 2016 WinterRegional Finished Gasoline Qualities1,2

(includes Ethanol)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 65.4 0.4 64.7 0.1 0.0 Lower Sulfur, Lower RVP Gasoline 5,863 568 1,434 3,183 284 

CARB Gasoline 849 - - - - 

Jet Fuel 1,480 79 273 673 41 

Distillates 4,365 354 949 2,390 184 

Pentanes 751 64 170 374 25 

Other4 326 4,170 671 2,224 133 

TOTAL 17,543 1,391 3,562 8,844 668 

NOTES:

(1)(2)(4) Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleu

miscellaneous petroleum products.As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

(3)

TABLE 18

Sensitivity Case 1 2016 Summer Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% 

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. "Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seaadjusted using actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 62.7 0.4 62.0 0.1 0.0 Lower Sulfur, Lower RVP Gasoline 6,745 657 1,701 3,694 332 

CARB Gasoline 922 - - - - 

Jet Fuel 1,448 96 256 662 39 

Distillates 4,275 334 931 2,364 173 

Pentanes 18 - - 6 - 

Other4 258 3,184 521 1,686 114 

TOTAL 16,654 1,345 3,470 8,412 657 

NOTES:

(2)(4)

TABLE 19

Sensitivity Case 1 2016 Winter Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

(1)

Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleumiscellaneous petroleum products.

(3) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% 

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. "Winter" is defined as October through March. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonusing actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline - C 475.1 4,276 4,751 319 1,153 2,589 

Lower Sulfur, Lower RVP Gasoline - R 165.3 1,487 1,653 284 421 909 

CARB 86.9 782 869 - - - 

TOTAL 776 6,562 7,338 603 1,639 3,498 

Gasoline Consumption5

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline - C 627.0 5,643 6,270 2,132 2,080 1,172 

Lower Sulfur, Lower RVP Gasoline - R 210.1 1,891 2,101 1,307 358 345 

CARB 111.8 1,006 1,118 - - - 

TOTAL 997 8,558 9,555 3,440 2,503 1,517 

E85 - - - - - 

Lower Sulfur, Lower RVP Gasoline - C (1,368) (1,520) (1,814) (927) 1,416 

Lower Sulfur, Lower RVP Gasoline - R (404) (449) (1,024) 63 564 CARB (224) (249) - - - 

TOTAL (1,996) (2,217) (2,837) (864) 1,980 

NOTES:

(1)(2)(3)(5) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are ba

miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported in the Petrol

(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendstocks

(4)

TABLE 20

Sensitivity Case 2 2016 Summer Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

Domestic Refinery Over/(Under) Supply6

"Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted using as reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added to doGasoline blender production, based on blendstock sources other than from domestic refiners, is not included. As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 6.0 5.9 6.0 6.0 6.4 5.9

Olefins, Vol.% 8.9% 10.4% 10.0% 9.3% 10.5% 5.4%

Aromatics, Vol.% 30.9% 30.6% 31.6% 31.9% 29.1% 27.9%

Benzene, Vol.% 0.61% 0.71% 0.72% 0.55% 0.75% 0.57%

Sulfur, wppm 10.9 12.0 12.1 12.4 12.6 4.5

Lower Sulfur, Lower RVP Gasoline - C

RVP, psi 6.3 6.4 6.2 6.2 6.4 6.3

Olefins, Vol.% 10.2% 10.1% 10.6% 10.2% 10.5% 8.5%

Aromatics, Vol.% 33.2% 37.5% 32.5% 33.4% 29.1% 33.2%

Benzene, Vol.% 0.67% 0.71% 0.83% 0.58% 0.75% 0.75%

Sulfur, wppm 11.8 10.8 12.2 12.5 12.6 6.7

Lower Sulfur, Lower RVP Gasoline - R

RVP, psi 5.4 5.4 5.4 5.4 - 5.4

Olefins, Vol.% 7.9% 10.7% 8.3% 7.0% - 4.6%

Aromatics, Vol.% 27.3% 22.8% 28.9% 27.8% - 30.2%

Benzene, Vol.% 0.52% 0.70% 0.44% 0.48% - 0.70%

Sulfur, wppm 12.2 13.4 12.0 12.3 - 7.6

CARBOB

RVP, psi 5.8 - - - - 5.8

Olefins, Vol.% 4.0% - - - - 4.0%

Aromatics, Vol.% 25.5% - - - - 25.5%

Benzene, Vol.% 0.49% - - - - 0.49%

Sulfur, wppm 3.4 - - - - 3.4

NOTES:

(1)

(2)

(3) PRISM simulation results.

"Summer" is defined as April through September. 

TABLE 21A

Sensitivity Case 2 2016 SummerRegional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 7.4 7.3 7.4 7.4 7.7 7.3

Olefins, Vol.% 8.0% 9.3% 9.0% 8.4% 9.5% 4.8%

Aromatics, Vol.% 27.8% 27.5% 28.4% 28.8% 26.2% 25.1%

Benzene, Vol.% 0.56% 0.64% 0.66% 0.50% 0.68% 0.52%

Sulfur, wppm 10.8 11.8 11.9 12.2 12.3 5.1

Lower Sulfur, Lower RVP Gasoline - C

RVP, psi 7.6 7.7 7.6 7.6 7.7 7.7

Olefins, Vol.% 9.1% 9.1% 9.5% 9.1% 9.5% 7.6%

Aromatics, Vol.% 29.9% 33.7% 29.3% 30.1% 26.2% 29.9%

Benzene, Vol.% 0.61% 0.65% 0.75% 0.52% 0.68% 0.68%

Sulfur, wppm 11.7 10.8 11.9 12.2 12.3 7.0

Lower Sulfur, Lower RVP Gasoline - R

RVP, psi 6.9 6.9 6.9 6.9 - 6.9

Olefins, Vol.% 7.1% 9.6% 7.5% 6.3% - 4.1%

Aromatics, Vol.% 24.5% 20.5% 26.0% 25.0% - 27.1%

Benzene, Vol.% 0.47% 0.64% 0.41% 0.44% - 0.64%

Sulfur, wppm 12.0 13.0 11.8 12.0 - 7.9

CARBOB

RVP, psi 7.2 - - - - 7.2

Olefins, Vol.% 3.6% - - - - 3.6%

Aromatics, Vol.% 23.0% - - - - 23.0%

Benzene, Vol.% 0.45% - - - - 0.45%

Sulfur, wppm 4.1 - - - - 4.1

NOTES:

(1)

(2)

(3) PRISM simulation results.

"Summer" is defined as April through September. 

TABLE 21B

Sensitivity Case 2 2016 SummerRegional Finished Gasoline Qualities1,2

(includes Ethanol)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 65.4 0.4 64.7 0.1 0.0 Lower Sulfur, Lower RVP Gasoline - C 4,751 319 1,153 2,589 310 

Lower Sulfur, Lower RVP Gasoline - R 1,653 284 421 909 - 

CARB Gasoline 869 - - - - 

Jet Fuel 1,666 109 273 796 41 

Distillates 4,251 285 960 2,311 177 

Pentanes 437 40 78 225 6 

Other4 434 4,135 756 2,153 41 

TOTAL 17,826 1,471 3,705 8,982 574 

NOTES:

(1)(2)(4) Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleu

miscellaneous petroleum products.

(3)

TABLE 22

Sensitivity Case 2 2016 Summer Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% 

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. "Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seaadjusted using actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
Ethanol 3 Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 

Domestic Refinery Gasoline Production4

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline - C 501.2 4,510 5,012 331 1,232 2,730 

Lower Sulfur, Lower RVP Gasoline - R 166.3 1,496 1,663 284 409 931 

CARB 87.7 790 877 - - - 

TOTAL 804 6,813 7,617 615 1,706 3,662 

Gasoline Consumption5

E85 48.4 17.0 65.4 0.4 64.7 0.1 

Lower Sulfur, Lower RVP Gasoline - C 627.0 5,643 6,270 2,132 2,080 1,172 

Lower Sulfur, Lower RVP Gasoline - R 210.1 1,891 2,101 1,307 358 345 

CARB 111.8 1,006 1,118 - - - 

TOTAL 997 8,558 9,555 3,440 2,503 1,517 

E85 - - - - - 

Lower Sulfur, Lower RVP Gasoline - C (1,133) (1,259) (1,801) (848) 1,558 

Lower Sulfur, Lower RVP Gasoline - R (395) (439) (1,024) 51 586 

CARB (216) (241) - - - 

TOTAL (1,744) (1,938) (2,825) (797) 2,144 

NOTES:

(1)(3)(5) Total U.S. gasoline consumption is based on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are b

miles traveled as reported by the U.S. Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported in the Petr

(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply. 

The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendstock

(4)

TABLE 23

Sensitivity Case 3 2016 Summer Supply Balance1,2

(Thousands of Barrels Per Day - Including Ethanol)

Domestic Refinery Over/(Under) Supply6

"Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seasonally adjusted usi

as reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% ethanol added to d

Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. 

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 6.6 6.3 6.7 6.7 7.5 6.2

Olefins, Vol.% 9.6% 11.2% 9.8% 10.5% 10.1% 5.7%

Aromatics, Vol.% 29.7% 29.6% 30.1% 30.5% 27.9% 27.5%

Benzene, Vol.% 0.59% 0.69% 0.70% 0.53% 0.73% 0.56%

Sulfur, wppm 10.8 11.8 12.0 12.2 12.1 4.5

Lower Sulfur, Lower RVP Gasoline - C

RVP, psi 7.1 7.1 7.1 7.1 7.5 7.4

Olefins, Vol.% 11.2% 11.5% 10.5% 11.8% 10.1% 10.1%

Aromatics, Vol.% 32.2% 36.9% 30.8% 33.1% 27.9% 30.2%

Benzene, Vol.% 0.63% 0.63% 0.80% 0.54% 0.73% 0.66%

Sulfur, wppm 11.8 10.2 12.5 12.4 12.1 6.8

Lower Sulfur, Lower RVP Gasoline - R

RVP, psi 5.4 5.4 5.4 5.4 - 5.4

Olefins, Vol.% 7.6% 10.8% 7.8% 6.7% - 4.6%

Aromatics, Vol.% 24.0% 21.1% 28.0% 22.9% - 30.2%

Benzene, Vol.% 0.51% 0.77% 0.39% 0.48% - 0.70%

Sulfur, wppm 11.6 13.8 10.4 11.7 - 7.6

CARBOB

RVP, psi 5.8 - - - - 5.8

Olefins, Vol.% 3.8% - - - - 3.8%

Aromatics, Vol.% 26.1% - - - - 26.1%

Benzene, Vol.% 0.51% - - - - 0.51%

Sulfur, wppm 3.4 - - - - 3.4

NOTES:

(1)

(3) PRISM simulation results.

"Summer" is defined as April through September. 

TABLE 24A

Sensitivity Case 3 2016 SummerRegional Finished Gasoline Qualities1,2

At Refinery Gate (Before Ethanol is Added)

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners3

Total Pool

RVP, psi 7.9 7.7 8.0 7.9 8.7 7.6

Olefins, Vol.% 8.6% 10.1% 8.8% 9.5% 9.1% 5.1%

Aromatics, Vol.% 26.7% 26.6% 27.1% 27.4% 25.1% 24.7%

Benzene, Vol.% 0.54% 0.63% 0.63% 0.48% 0.66% 0.51%

Sulfur, wppm 10.7 11.6 11.8 12.0 11.9 5.1

Lower Sulfur, Lower RVP Gasoline - C

RVP, psi 8.3 8.3 8.3 8.3 8.7 8.5

Olefins, Vol.% 10.1% 10.4% 9.4% 10.6% 9.1% 9.1%

Aromatics, Vol.% 29.0% 33.2% 27.7% 29.8% 25.1% 27.2%

Benzene, Vol.% 0.57% 0.57% 0.72% 0.49% 0.66% 0.60%

Sulfur, wppm 11.6 10.2 12.3 12.1 11.9 7.1

Lower Sulfur, Lower RVP Gasoline - R

RVP, psi 6.9 6.9 6.9 6.9 - 6.9

Olefins, Vol.% 6.8% 9.7% 7.0% 6.0% - 4.1%

Aromatics, Vol.% 21.6% 19.0% 25.2% 20.6% - 27.1%

Benzene, Vol.% 0.47% 0.70% 0.36% 0.44% - 0.64%

Sulfur, wppm 11.5 13.4 10.4 11.5 - 7.9

CARBOB

RVP, psi 7.2 - - - - 7.2

Olefins, Vol.% 3.4% - - - - 3.4%

Aromatics, Vol.% 23.5% - - - - 23.5%

Benzene, Vol.% 0.46% - - - - 0.46%

Sulfur, wppm 4.1 - - - - 4.1

NOTES:

(1)

(3) PRISM simulation results.

"Summer" is defined as April through September. 

TABLE 24B

Sensitivity Case 3 2016 SummerRegional Finished Gasoline Qualities1,2

(includes Ethanol)

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 

Domestic Production by Crude Oil Refiners3

E85 Gasoline 65.4 0.4 64.7 0.1 0.0 Lower Sulfur, Lower RVP Gasoline - C 5,012 331 1,232 2,730 324 

Lower Sulfur, Lower RVP Gasoline - R 1,663 284 409 931 - 

CARB Gasoline 877 - - - - 

Jet Fuel 1,667 109 273 796 41 

Distillates 4,250 285 960 2,310 177 

Pentanes 269 28 41 130 0 

Other4 432 4,323 750 2,240 134 

TOTAL 18,125 1,469 3,729 9,138 676 

NOTES:

(1)(4) Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleu

miscellaneous petroleum products.

(3)

TABLE 25

Sensitivity Case 3 2016 Summer Production1,2

(Thousands of Barrels Per Day - Including Ethanol)

Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined by PRISM simulations and include 10 Vol.% 

added to refinery production. Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included. "Summer" is defined as April through September. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Release was seaadjusted using actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.

(2) As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Crude Inputs

Base Case 14,941 1,118 3,256 7,400 596 2,571 

Study Case 14,511 1,118 3,111 7,293 596 2,393 

Delta (430) - (145) (107) - (178) 

Delta, % -3% 0% -4% -1% 0% -7%

Total Refinery Inputs

Base Case 1,261 16,402 3,434 8,250 623 2,835 

Study Case 15,864 1,262 3,257 8,077 610 2,657 

Delta (538) 1 (177) (172) (13) (177) 

Delta, % -3% 0% -5% -2% -2% -6%

LSRBOB (excl. EtOH)3

Base Case 6,567 609 1,741 3,519 310 389

Study Case 5,501 523 1,346 3,015 258 359

Delta (1,066) (86) (395) (504) (51) (29)

Delta, % -16% -14% -23% -14% -17% -8%

CARBOB (excl. EtOH)

Base Case 868 - - - - 868

Study Case 776 - - - - 776

Delta (91) - - - - (91)

Delta, % -11% -11%

Distillates

Base Case 5,733 410 1,156 3,012 211 944

Study Case 5,911 432 1,231 3,106 220 922

Delta 178 22 75 95 9 (22)

Delta, % 3% 5% 6% 3% 4% -2%

Base Case (MMSCFD) 1,629.7 20.1 36.5 1,326.7 0.8 245.5

Study Case (MMSCFD) 1,793.6 28.4 64.8 1,424.5 1.5 274.5

Delta (MMSCFD)5 8.2 163.9 28.3 97.7 0.6 29.0 

Delta, % 10% 41% 77% 7% 72% 12%

NOTES:

(1) "Summer" is defined as April through September.

(2)

(3)

(4)

(5)

SOURCE: Baker & O'Brien PRISM simulations

Difference in reported delta values are due to rounding.

LSRBOB is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes E85 hydrocarbon, CBOB and RBOB and the 

Study Case includes E85 hydrocarbon and LSRBOB.

Refinery Hydrogen Purchases is the total hydrogen purchased by domestic refineries to produce fuels.

TABLE 26

Study Case vs. Base Case Summer 20161,2

(Thousands of Barrels Per Day Unless Otherwise Stated)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

Refinery Hydrogen Purchases4
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Crude Inputs

Base Case 14,941 1,118 3,256 7,400 596 2,571 

Sensitivity Case 1 14,328 1,118 3,046 7,140 596 2,428 

Delta (613) - (210) (260) - (143) 

Delta, % -4% 0% -6% -4% 0% -6%

Total Refinery Inputs

Base Case 1,261 16,402 3,434 8,250 623 2,835 

Sensitivity Case 1 15,679 1,266 3,191 7,918 612 2,693 

Delta (723) 5 (243) (332) (11) (142) 

Delta, % -4% 0% -7% -4% -2% -5%

LSRBOB (excl. EtOH)3

Base Case 6,567 609 1,741 3,519 310 389

Sensitivity Case 1 5,293 511 1,308 2,865 255 355

Delta (1,274) (98) (433) (654) (54) (34)

Delta, % -19% -16% -25% -19% -18% -9%

CARBOB (excl. EtOH)

Base Case 868 - - - - 868

Sensitivity Case 1 765 - - - - 765

Delta (103) - - - - (103)

Delta, % -12% -12%

Distillates

Base Case 5,733 410 1,156 3,012 211 944

Sensitivity Case 1 5,844 434 1,222 3,063 225 900

Delta 111 23 66 51 14 (43)

Delta, % 2% 6% 6% 2% 7% -5%

Base Case (MMSCFD) 1,618.4 20.1 36.5 1,315.4 0.8 245.5

Sensitivity Case 1 (MMSCFD) 1,911.2 46.3 93.5 1,469.3 1.5 300.5

Delta (MMSCFD)5 26.2 292.8 57.0 153.9 0.6 55.0 

Delta, % 18% 130% 156% 12% 74% 22%

NOTES:

(1) "Summer" is defined as April through September.

(2)

(3)

(4)

(5)

SOURCE: Baker & O'Brien PRISM simulations

Difference in reported delta values are due to rounding.

LSRBOB is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes E85 hydrocarbon, CBOB and RBOB and the 

Sensitivity Case 1 includes E85 hydrocarbon and LSRBOB.

Refinery Hydrogen Purchases is the total hydrogen purchased by domestic refineries to produce fuels.

TABLE 27

Sensitivity Case 1 vs. Base Case Summer 20161,2

(Thousands of Barrels Per Day Unless Otherwise Stated)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

Refinery Hydrogen Purchases4
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Crude Inputs

Base Case 14,941 1,118 3,256 7,400 596 2,571 

Sensitivity Case 2 14,511 1,118 3,111 7,293 596 2,393 

Delta (430) - (145) (107) - (178) 

Delta, % -3% 0% -4% -1% 0% -7%

Total Refinery Inputs

Base Case 16,402 1,261 3,434 8,250 623 2,835 

Sensitivity Case 2 15,860 1,260 3,255 8,075 612 2,658 

Delta (543) (1) (178) (175) (11) (177) 

Delta, % -3% 0% -5% -2% -2% -6%

LSRBOB - C (excl. EtOH)3

Base Case 286 4,941 1,430 2,558 310 357 

Sensitivity Case 2 4,293 287 1,054 2,330 279 343

Delta (649) 1 (375) (229) (31) (14)

Delta, % -13% 0% -26% -9% -10% -4%

LSRBOB - R (excl. EtOH)4

Base Case 322 1,626 311 961 32 

Sensitivity Case 2 1,487 255 379 818 - 35

Delta (138) (67) 68 (143) - 3

Delta, % -9% -21% 22% -15% - 11%

CARBOB (excl. EtOH)

Base Case 868 - - - - 868

Sensitivity Case 2 782 - - - - 782

Delta (86) - - - - (86)

Delta, % -10% -10%

Distillates

Base Case 5,733 410 1,156 3,012 211 944

Sensitivity Case 2 5,917 394 1,233 3,107 218 966

Delta 184 (17) 77 95 7 22

Delta, % 3% -4% 7% 3% 3% 2%

Base Case (MMSCFD) 1,629.7 20.1 36.5 1,326.7 0.8 245.5

Sensitivity Case 2 (MMSCFD) 1,814.4 28.3 64.5 1,416.6 0.8 304.1

Delta (MMSCFD)6 8.2 184.7 28.0 89.9 - 58.6 

Delta, % 11% 41% 77% 7% 0% 24%

NOTES:

(1) "Summer" is defined as April through September.

(2)

(3)

(4)

(5)

(6)

SOURCE: Baker & O'Brien PRISM simulations

Difference in reported delta values are due to rounding.

LSRBOB - C is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes E85 hydrocarbon, CBOB and the Sensitivity 

Case 2 includes E85 hydrocarbon and LSRBOB - C.

Refinery Hydrogen Purchases is the total hydrogen purchased by domestic refineries to produce fuels.

TABLE 28

Sensitivity Case 2 vs. Base Case Summer 20161,2

(Thousands of Barrels Per Day Unless Otherwise Stated)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

Refinery Hydrogen Purchases5

LSRBOB - R is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes RBOB and the Sensitivity Case 2 includes 
TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Crude Inputs

Base Case 14,941 1,118 3,256 7,400 596 2,571 

Sensitivity Case 3 14,511 1,118 3,111 7,293 596 2,393 

Delta (430) - (145) (107) - (178) 

Delta, % -3% 0% -4% -1% 0% -7%

Total Refinery Inputs

Base Case 16,402 1,261 3,434 8,250 623 2,835 

Sensitivity Case 3 15,923 1,258 3,271 8,119 617 2,658 

Delta (479) (3) (163) (131) (5) (177) 

Delta, % -3% 0% -5% -2% -1% -6%

LSRBOB - C (excl. EtOH)3

Base Case 286 4,941 1,430 2,558 310 357 

Sensitivity Case 3 4,527 298 1,126 2,457 291 355

Delta (414) 12 (304) (101) (18) (2)

Delta, % -8% 4% -21% -4% -6% -1%

LSRBOB - R (excl. EtOH)4

Base Case 322 1,626 311 961 32 

Sensitivity Case 3 1,496 255 368 838 35

Delta (129) (67) 57 (123) - 3

Delta, % -8% -21% 18% -13% - 11%

CARBOB (excl. EtOH)

Base Case 868 - - - - 868

Sensitivity Case 3 790 - - - - 790

Delta (78) - - - - (78)

Delta, % -9% -9%

Distillates

Base Case 5,733 410 1,156 3,012 211 944

Sensitivity Case 3 5,916 394 1,233 3,106 218 966

Delta 183 (17) 77 95 7 23

Delta, % 3% -4% 7% 3% 3% 2%

Base Case (MMSCFD) 1,629.7 20.1 36.5 1,326.7 0.8 245.5

Sensitivity Case 3 (MMSCFD) 1,814.6 28.3 64.5 1,416.5 0.8 304.4

Delta (MMSCFD)6 8.2 184.9 28.0 89.8 - 58.9 

Delta, % 11% 41% 77% 7% 0% 24%

NOTES:

(1) "Summer" is defined as April through September.

(2)

(3)

(4)

(5)

(6)

SOURCE: Baker & O'Brien PRISM simulations

Difference in reported delta values are due to rounding.

LSRBOB - C is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes E85 hydrocarbon, CBOB and the Sensitivity 

Case 3 includes E85 hydrocarbon and LSRBOB - C.

Refinery Hydrogen Purchases is the total hydrogen purchased by domestic refineries to produce fuels.

TABLE 29

Sensitivity Case 3 vs. Base Case Summer 20161,2

(Thousands of Barrels Per Day Unless Otherwise Stated)

As described in the main body of the report entitled "Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline"

Refinery Hydrogen Purchases5

LSRBOB - R is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes RBOB and the Sensitivity Case 3 includes