# 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 - 

# T ABLE OF 

# C ONTENTS

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

II. INTRODUCT ION ............................................................................................ 3

III. EXECUTIVE SU MMARY ................................................................................ 5

REGULATORY ASS UMPTION S .................................................................... 8 TECHNOLOGY AND INVESTMENT COSTS ................................................. 9 ANALYTICAL BASIS .................................................................................... 10 STUDY RESU LTS ........................................................................................ 11

IV. REGULATORY ASS UMPTION S .................................................................. 17

GREENHOUSE GAS EMISSIONS ............................................................... 20 OTHER REGULA TIONS .............................................................................. 20

V. GASOLINE CONSUMPT ION FOREC AST ................................................... 21

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

FRACTIONAT ION ........................................................................................ 22 FCC FEED AND GASOLINE DESULFURIZA TION ..................................... 22 CAPITAL COSTS FOR GR ASSROOTS UNI TS ........................................... 23 REVAMP/EXPANSI ON COSTS ................................................................... 24 NATURAL GAS LIQUID (NGL) ST ORAGE AND LOAD ING COSTS ........... 24 OTHER OFF-SITE C APITAL CO STS .......................................................... 25 CONTINGENCY ALLOWANCE .................................................................... 25 CAPITAL INVESTME NT CHARG E .............................................................. 25

VII. INPUT CO STS ............................................................................................. 26

NATURAL GAS COST ................................................................................. 26 HYDROGEN CO STS ................................................................................... 26

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

REFINERY MO DELING ............................................................................... 27 REFINERY CAPACITY AND UTILIZ ATION ................................................. 28 CRUDE SL ATE ............................................................................................ 29 SEASONALITY ............................................................................................. 29 CALIFORNIA RE FINERIES.......................................................................... 30 DISPOSITION OF EXCESS NG LS .............................................................. 30

### - ii - 

# REDUCE NGL IMPORT S .................................................................. 30 DISPLACE OTHER ETHYLENE CRACKER FEEDSTOCKS ............ 30 EXPORT MAR KETS .......................................................................... 32 CONSUME OR SELL AS FUEL OR HYDROGEN FEEDSTOCK ...... 33
ALKYLATI ON ..................................................................................... 33 STOCKPILE FOR WINTER CONSUMPT ION ................................... 33 NGLS TRANSPO RTATION ............................................................... 34 VALUATION OF EXCESS NGLS ................................................................. 35 COMPLIANCE R ESPONSE ......................................................................... 36 OTHER GASOLINE SUPPLY ....................................................................... 38 IMPORT S ..................................................................................................... 38 ETHANOL QU ALITY .................................................................................... 38

IX. STUDY RESU LTS ........................................................................................ 39

BASE CASE GASOLINE SUPPLY BALAN CE AND REFINERY OPERATIO NS .............................................................................................. 39 COMPLIANCE R ESPONSE ......................................................................... 40 STUDY AND SENSITIVITY CAS ES GASOLINE SUPPLY BALANCE
AND REFINERY OPERATION S .................................................................. 42 DISPOSITION OF S URPLUS NG LS ............................................................ 44 GREENHOUSE GAS EMISSIONS ............................................................... 48 TOTAL COMPLIANCE COST S .................................................................... 49 COMPARISON TO AAM REPO RT .............................................................. 51

X. CONCLUSION S ........................................................................................... 53

### - 1 - 

# I. A BSTRACT

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

single national (excluding California) summe rtime gasoline specif ication that they

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

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

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

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

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

nationwide (excluding California) to 7 pounds per square inch absolut e (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 allo w the waiver for conventional

gasoline. Reformulated gasoline (RFG) mainta ins 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 s how that four to seven re fineries are likely to shut

down rather than make the necessary invest ments to produce gasolin e with lower sulfur

and lower RVP specifications. A substantia l volume of domesti cally-produced light

hydrocarbon currently blended into gasoline would be re moved from gasoline and would

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

estimated to decrease by 0.6 to 1.3 milli on 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 hydrotreat ing and fractionation required to comply would result in an

### - 2 - 

# increase in carbon dioxide (CO 2 

# ) emission from refineries that continue to operate. On

an annual average basis, the total increase in CO 2 

# emissions at domestic and foreign

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

### - 3 - 

# II. I NTRODUCTION

In 2009, the Alliance of Automob ile Manufacturers published a report 1 

# (the AAM

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

gasoline quality that w ould apply to all states except Ca lifornia. The AAM Report calls

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

Institute (API) engaged Baker and O’Brien, In c. (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 gasoli ne. 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 infl uence potential responses to regulatory

requirements. Therefore, Ba ker & O’Brien undertook a refi nery-by-refinery approach in

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

gasoline. Compliance options were eval uated and production estimates calculated for

each refinery using Baker & O’Brien’s PRISM TM 

# 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 analysi s 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 t he extent that additiona l 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 analys is is based change, our opinions could be

subsequently affected.

### - 5 - 

# III. E XECUTIVE 

# S UMMARY

In 2009, the Alliance of Automob ile Manufacturers published a report 2 

# (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 In stitute (API) engaged Baker and O’Brien, Inc. (Baker

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

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

accounting for technical, strategic, mark et, 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 modeli ng, given the likely variation in refinery response to

regulation, based on each refi nery’s unique position.

Implementing a nationwide (except Ca lifornia) summer season 7 pounds per

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

gallon cap and 10 ppm company annual aver age (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 ga s that are separated from the gas as liquids. NGLs

include ethane, propane, butane, isobutane, and “Pentane s 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 pr oduced 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 t he 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 in creased 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 r ange 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 investm ents. There are additional investments that would be

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

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

Additional hydrotreating and fractionation required to comply would result in an

increase in carbon dioxide (CO 2 

# ) emissions from refineries that continue to operate. On

4 

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

through September inclusively. “Wi nter” 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 consum ption remain constant at Base Case levels.

6 

## All costs in this report are expr essed in constant 2009 U.S. Dollars.

### - 7 - 

# an annual average basis, the total increase in CO 2 

# 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, t here 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 hav e the capability to produce 5 ppm sulfur

gasoline. 9 

# Our analysis indicates that most will r equire capital investments to produce 5

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

fluid catalytic cracker (FCC) gasoline hydrotr eater 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 t hat all existing fuel regulations based

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

lower RVP standard with a nati onwide (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 Sensitiv ity 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 specificati ons 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 sulf ur, 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 ot her areas currently requiri ng 7.0 psia. RVP limited

to 7.8 psia in all other regions except California. *** No units apply, but in this context, temper atures are measured in degrees Fahrenheit (°F).

### - 9 - 

# Most of the analysis described in th is report was completed before the

Environmental Protection Agency (EPA) approv al 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 lo wer sulfur and lower RVP

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



# TECHNOLOGY AND IN VESTMENT COSTS

There are significant differences in gasoline sulfur and summer RVP

specifications between the Ba se, Study, and Sensitivity Case s. 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 refi neries. New fractionation

towers would be required at many refineries to accomplish this.

To reduce sulfur in finished gasoline, fu rther reductions in FCC gasoline sulfur

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

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

FCC feed. Additional reductions would be r equired 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 un loading facilities (stora ge tanks, piping, vapor

recovery systems, pumps, ra il car loading spots, etc.) woul d be required at refineries to

handle the volume of NGLs t hat 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/unl oading 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 specia l-purpose rail cars. Additional rail cars,

storage, and handling facilitie s would be required.



# ANALYTICAL BASIS

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

Therefore, a refinery-by-refi nery 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 th is information. It is believed this

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

refinery response to regulation, bas ed 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 simulato r and models of virtually every refinery in

North America.

The Study Case summer RVP requirement would cause many refineries to

produce additional NGLs that ca nnot 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 pent ane exports to foreign markets;

 Consumption or sales of butane and/or pentane as f uel 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 Se nsitivity Cases is quite large. This would have a

significant impact on the value of these hy drocarbons. 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 c onsistent 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 re finers, in addition to the investment and

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

Cases.

A stepwise refinery-by-ref inery 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 fu ture annual net cash flow), then it was

assumed that the refinery would st op 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 hel d constant in all Cases. Imports in

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

availability of imports to m eet the requirements of the ot her Cases was not assessed.



# STUDY RESULTS

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

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

domestic gasoline production is estima ted 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 we re producing non-California gasoline

(including some California refineries). In t he Study Case and Sensit ivity 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 lo wer 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 Ca se 1 if they did make the investment.

The estimated compliance investments for t he 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 remo ved from the gaso line 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 gasoli ne 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 displace d 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 si gnificant impact on the U.S. refining, chemicals, and NGL

markets. Investments required by refiner s 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 out side 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 in vestment costs range fr om $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 Ca ses 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/DIncrease 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/DIncrease 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/DIncrease 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/DIncrease in Cost of GasolineProduction¢/Gal. Annualized Costs

Summer Costs

### - 17 - 

# IV. R EGULATORY 

# A SSUMPTIONS

Historically, ASTM Internat ional (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 st andards 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 qualit y requirements in an effort to reduce

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

vary seasonally and geographically. Additio nally, the federal government has required

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

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

standards that create uni que gasoline specification requ irements for small geographical

regions.

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

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

gasoline quality that w ould apply to all states except Ca lifornia. The AAM Report calls

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

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

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

(i.e., the reduced Reid vapor pr essure [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 analysi s assumes that the existi ng Tier-2 gasoline sulfur

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

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

gasoline) are fully implemented. The impacts of potential c hanges in fuel specifications

### - 18 - 

# that could result from “p roposed” regulations, such as more stringent ground level

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

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

Environmental Protection Agency (EPA) approv al 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 lo wer sulfur and lower RVP

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

In the Study Case and Sensitivity Case s 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 act ually produce gasoline

with sulfur levels slightly bel ow 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 Sept ember) 7 pounds per square inch absolute

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

Areas, 14 

# and in Conventional Gasoline (CG) area t hat currently require this RVP during

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

complex model volatile organic compounds limit s. 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 Ca se 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 thes e 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 Ba se 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 sulf ur, 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 ot her areas currently requiri ng 7.0 psia. RVP limited

to 7.8 psia in all other regions except California. *** No units apply, but in this context, temper atures are measured in degrees Fahrenheit (°F).

### - 20 - 

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

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

remain unchanged.



# GREENHOUSE GAS EMISSIONS

Carbon dioxide (CO 2 

# ) emissions from refi neries were calculated for all cases, but

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

CO 2 

# 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 CO 2 

# 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. G ASOLINE 

# C ONSUMPTION 

# F ORECAST

In December 2009, the Energy Informa tion 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 a ssumed to be constant in all cases and

consistent with the AEO 2010 Reference Case 15 

# , 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 su mmer and winter sub-cases on the basis of

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

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

economic conditions in 2008 and 2009.

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

and “E85”. Each of these categories in cludes 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 signific antly 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 report ed 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. T ECHNOLOGY AND 

# C APITAL 

# I NVESTMENT 

# C OSTS

All costs in this report are expres sed 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 th e first to be rejected, followed by pentanes

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

gasoline. It is expected t hat new depentanizers would be re quired at many refineries.

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

of the remaining pool. Theref ore, refineries that must in stall depentanizers to meet the

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

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

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

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

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

refineries.



# FCC FEED AND GASOLI NE 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 refiner s responded to Tier 2 requirements by reducing

FCC gasoline sulfur though FCC feed hy drodesulfurization, FCC gasoline

desulfurization, or a combinati on of the two. Further reducti on 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 t he addition of catalyst volume to lower the

space velocity and increase desulfurization without adding additiona l 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 al so modifications to the feed preheat and

product fractionation sections.

To meet Tier 2 sulfur limits, some refi ners installed FCC gasol ine fractionators in

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

hydrotreat light FCC gasoline. Many of t hese refiners would need to hydrotreat light

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

addition of a light FCC gaso line 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 co sts for the technologies used in this

study were estimated using the formula:

ISBL Cost = Base Cost * (A ctual 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 estimat ed 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 Hydrodesulfurization 1 

### FCC Feed Hydrodesulfurization 2 

### Depentanizer 3


### 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 a ssumed 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 invest ment cost was assumed to be 150% of the

difference in ISBL replacement cost betw een the Base Case and the alternate Case.



# NATURAL GAS LIQUID (NGL) STORAGE AND LOADING COSTS

New or expanded loading and un loading facilities (stora ge tanks, piping, vapor

recovery systems, pumps, ra il car loading spots, etc.) woul d be required at refineries to

handle the volume of NGLs that would be sold if the summe r 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/unl oading infrastructure and capability. A

### - 25 - 

# capital investment cost of $140 per barrel (Bbl.) of storage capacity 18 

# 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 invest ment for off-sites would be required

unless new units or new equipment were inst alled (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 asso ciated with actual capi tal costs, it is

prudent to apply some reasonabl e "contingency" allowance to capture unidentified costs

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

combined ISBL and outside battery limits costs was assumed.



# CAPITAL INVESTMENT CHARGE

Estimated capital costs were converted in to 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 ant icipate a rate of return commensurate with

the opportunity cost of capital. It was assumed that refi ners would require a 10% aftertax rate of return based on a 15-year operati ng 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 midpoi nt 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. I NPUT 

# C OSTS

NATURAL GAS COST

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

this study are above current levels, but withi n 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 gas oline desulfurization, it was assumed incremental

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

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

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

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

companies to build hydrogen production capa city using steam methane reforming

technology and supply hydrogen to refiner s under term-sales contracts.

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

hydrogen production by making changes to refo rmer 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. A NALYTICAL 

# B ASIS

Even without new gasoline sulfur and R VP rules, compliance with existing

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

federal and state regulat ions are adding to the cost of me rely 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 chal lenged in court. Depending upon the

outcome, there could be an increase in the co st 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-refi nery analysis was performed that considered each refinery’s

compliance options accounting for technical, strategic, market, an d economic factors,

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

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

refinery response to regulation, bas ed 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 yi eld 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 refi nery 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 pric es for products, and pipeline ta riffs. It includes fixed

### - 28 - 

# and variable operating cost and capital replac ement cost estimates for each refinery,

and provides a systematic method of evaluat ing and comparing refinery operating and

financial performance over time a nd 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 i ndependent assessment of process unit

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

EIA annual survey of refinery c apacity 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 un it can produce or consume material during a

continuous 24-hour period.

CD capacity represents the maximum su stainable capacity to produce or

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

that is lost during plan ned 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 proc ess units to sustain operations at 100% of

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

utilization of SD capacity.

The Base Case refinery capacity es timate 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 capac ity associated with announced permanent

refinery closures would not be availabl e in 2016. These closures include:

 Sunoco – Eagle Point;

 Western – Bloomfield; and

 Valero – Delaware City. 19



# Modifications required to comply with existi ng regulations listed in Section IV of

this report were assumed to be completed bef ore 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 provi ded for comparison.

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

2010 Reference Case crude throughputs and utiliz ation rates as closely as possible.



# CRUDE SLATE

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

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

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

was assumed that foreign crudes with equi valent 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 t he 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 Califo rnia 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 fo r other ethylene cracker feedstocks;

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

 Consumption or sales of butane and/or pentane as f uel 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 aver age 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 refiner y produced NGLs would tr igger a significant

curtailment or elimination of these imports.



# DISPLACE OTHER ETHYLENE CRACKER FEEDSTOCKS

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

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

20 

## FCC Pentanes refers to the mix of 5-carbon mole cules produced from an FCC unit and includes C5

olefins and di-olefins.

### - 31 - 

# liquids. 21 

# Feedstock consumption for U.S. et hylene 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 cons umed 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. Appr oximately 50% of U.S. ethyl ene is produced from crackers,

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



# If the surplus refinery-produced NGLs are s ubstituted for other ethylene cracker

feedstocks, the displaced ethylene feedstocks would need to be accommodated

elsewhere. While there are options av ailable 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, t he 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 woul d likely cause a reduction in U.S. waterborne imports. The U.S. impor ted an average of 165 MB/CD of propane and 150 MB/CD of “heavy liquids” (gr eater 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, pet chem players must face problems of increased

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

23 

## Ibid.

### - 32 - 

# through 2008. While propane competes wit h heating oil in the home heating market, it is unlikely that fuel swit ching 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 lo wer quantities of arom atics. 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 deta iled 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 roughl y 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 hi gher 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 trans port 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 pr obably 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 t heir 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. Traditiona lly, 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 becaus e 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 alkylat ion capacity. The Study and Sensitivity Cases assume that

refiners only make investments required for co mpliance. Since investment in additional

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

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

Refiners would make these incremental inve stments 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 t he 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 woul d be considered by

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

surplus of Pentanes Plus.



# NGLS TRANSPORTATION

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

very limited logistics infrastr ucture dedicated to Pentanes Pl us 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 netwo rk to a large number of

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

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

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

expected to require any significant infrastruc ture modifications to enable the disposition

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

be able to utilize pressurized barges to tran sport 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 specia l-purpose rail cars, referred to as highpressure tank cars. It is estimated that high-pressure ta nk 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 r equired 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 t he 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 gas oline during the summer in the Study

and Sensitivity Cases is very large and w ould impact the domestic and international

markets for NGLs. This would have a si gnificant 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 CO 2 

# per British thermal unit when burned than iso-octane).

Because the incremental or lowest val ue 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 t hese 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 t he NGLs’ value as gasol ine 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 increment al 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 val ues for volumes used as fuel or sold into

export markets. All other light hydrocarbon sales have been va lued 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 nec essary to comply with the new gasoline

standards at each individual refinery. Sinc e summer compliance wi th both sulfur and

RVP reductions would be more difficult t han winter, investment decisions would be

based on meeting the summer spec ifications. Any capital improvements installed to

meet the summer requirements w ould 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 adde d 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 gaso line end points were reduced, but no
lower than 360°F.

3. If reducing the FCC hea vy 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 revam ped to the extent possible to meet the lower gas oline sulfur limit.

5. Existing FCC gasoline desulfurizati on units were revamped or expanded as needed to meet the lower gasolin e sulfur specification.

6. If expansions and revamps of existing des ulfurization units were insufficient to meet the sulfur limits, then new FCC gasoline hy drotreaters 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 t hat 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 maki ng 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 inve stments met the value as an ongoing

concern, criteria summer variable cash margins 27 

# were reviewed. If a refinery met the

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

margin during the summer, it was assumed t hat 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 refi neries with relatively low compliance costs were assumed to

make the necessary compliance investments.

27 

## Variable cash margin is defined as the sum of a ll product revenue less the cost of feedstocks and only

expenses that vary with operating rates. For ex ample, fuel and power consumption will vary with operating rates, but property taxes and insurance do no t. Expenses that do not vary with operating rate are defined as fixed costs.

### - 38 - 

# OTHER GASOLINE SUPPLY

The AEO 2010 Reference Case includes 30 0 MB/CD of “other” supply to the

transportation fuels market in 2016. EIA staff 28 

# indicated that one-third to one-half of

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

components, other hydrocarbons, and renewabl e 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 component s would be supplied to the domestic

market from sources other t han domestic refineries and impor ts. It is reasonable to

assume that the reduction in RVP in the Study and Sensitivity Ca ses 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 Sensit ivity Cases. Gasoline cons umption was held constant

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

Case and history. The availability of impor ts to meet the require ments of the Study and

Sensitivity Cases has not been analyzed.



# ETHANOL QUALITY

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

default ethanol properties values specifi ed by California Air Resources Board. 29

28 

## Conversation with an EIA AEO Forecast Analyst, December 15, 2009.

29 

## Procedures for Using the California Model fo r California Reformulated Gasoline Blendstocks for

Oxygenate Blending (CARBOB), August 7, 2008.

### - 39 - 

# IX. S TUDY 

# R ESULTS

BASE CASE GASOLINE SUPPLY BALANCE AND REFINERY OPERATIONS

Using the PRISM refining industry model, adju sted 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 prov ided in Table 3, Table 4, and Table 5,

respectively. On an annual bas is, U.S. refiners are projec ted 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 th is magnitude of gasoline in rec ent years, but an analysis

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

Refinery annual average utilization rates fo r 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 ut ilization 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 fo recast for 2016 of 83%. Average Base Case

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

of October 2008 through Septem ber 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 consum ption 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 o perating 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 we re producing non-California gasoline

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

the Study and Sensitivity Cases additional de pentanizers 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 depentanizer s is 103, 38, and 27

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

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

endpoints to meet summer DI specifications.

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

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

feed hydrotreater, nine would need to install new FCC gaso line hydrotreat ers, and 32

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

Sensitivity Case 1, the requi red investment s are greater.

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

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

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

investments required to comply with the lower sulfur and lowe r 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 lowe r sulfur and lower RVP in

the Study Case, 170 MB/CD in Sensitivity Ca ses 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 GA SOLINE SUPPLY BALANCE AND REFINERY OPERATIONS

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

the removal of a large quantit y of domestically-produced hy drocarbon from the gasoline

blend pool. In the Study Case, the resu lting 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 c onsumption. 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 re finery operating rates to offset the

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

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

U.S. currently exports diesel fuel and additi onal exports may be po ssible. However,

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

in the Study and Sensitivity Ca ses, 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 cont inued to operate in the Study and Sensitivity

Cases.

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

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

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

least proportionally to the s upply 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 subs titute 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 refi nery production rates co mpared to the Base

Case. The desulfurization facilities requir ed 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 becaus e of an increase in hydrogen consumption

related to additional FCC feed an d 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 asso ciated with undercutting naphtha. The

combination of the decline in reforme r hydrogen production and an increase in

consumption for desulfurization result s in an annualized incr ease 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 refiner ies operating in

Sensitivity Cases 1, 2, and 3, respective ly. 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 re fineries 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 gasol ine RVP would result in 850 MB/CD of

NGLs being removed from the domestic gas oline 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 t he winter gasoline pool. Other

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

significant impact on the U.S. refining, chemical s, 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 reas ons discussed below, existing transportation and

handling infrastructure outside the refi nery gate likely cannot accommodate the

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

battery limits investments has not been es timated as part of this study.

### - 46 - 

# The following table presents a potential sce nario 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 exc eeding 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 but anes and pentanes to ethylene producers.

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

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

million barrels of underground salt dome st orage 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 bei ng 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 lik ely 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 requi red represents roughly 30% of the U.S. high-pressure rail

car fleet, 31 

# while the number of daily rail car loadings represents appr oximately 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, wit h 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 addi tional 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 feasib le, sufficient time must be allowed for the

design, permitting, and construction of the requi red facilities, or significant disruptions

31 

## Baker & O’Brien estimate.

32 

## Trinity Rail Presentation at NGFA Ag Transportati on Symposium, May 12, 2009. Reference to Global

Insight May 2009 forecast.

### - 48 - 

# could occur across the refining, petrochemic al, 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 hydrotr eating and fractionation r equired in the Study and

Sensitivity Cases would result in an increase in CO 2 

# emission from refineries that

continue to operate as shown below.

Incremental CO 2 

# Emissions Tonnes/CD

CO 2 

## 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 CO 2 

## 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 CO 2 

# emissions would be 2.9 to 7.4 million tonnes per year. As a result of

shifting emissions overseas, incurring addi tional emissions associated with fuel

### - 49 - 

# transport (not included here), and increasing emissions for operating refineries in the

U.S., aggregate global CO 2 

# emissions increase.



# TOTAL COMPLIANCE COSTS

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

investment costs are second. Refinery inve stment 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 ar e additional investments that would be

required outside the refineries that are not included in these totals.

The total compliance costs that woul d 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 Expe nses 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 hi gher in Sensitivit y Cases 2 and 3.

### - 50 - 

# In the graphs that fo llow, the annualized and summe r individual refinery

compliance costs are plotted in cents per ga llon (¢/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/DIncrease 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/DIncrease 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/DIncrease 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/DIncrease in Cost of GasolineProduction¢/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, t here 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 th ose reported herein. The AAM Report

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

gasoline. 35 

# Our analysis indicates that most will r equire 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. T hese 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. C ONCLUSIONS

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 impa ct on gasoline production cost and supply.

Four to seven refineries could shut down ra ther than make the in vestments required to

meet the standards. Supplies of domesti cally-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 CO 2 

# 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 increa se as gasoline production declines.

Additional exports of bot h would likely result to balance those markets.

Required compliance investments by refiner s are estimated at $9 to 17 billion.

On an ongoing annual basis, compliance costs ar e estimated at $5 to $13 billion.

Allocating these costs to gasoline produced yi elds 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 Summer 4

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 Winter 5

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 A nnual
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 Consumption 1,2,3

(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 an d 2006. A nnual aver age consumption from the EIA 2010 A nnual Energy Outlook Early Release was seasonally adjusted using actual 2005/2006 consumption as reported by EIA in Petroleum Marketing Monthly. Annual aver age consumption from the EIA 2010 A nnual 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. A nnual average consumption from the EIA 2010 A nnual Energy Outlook Early Release was seasonally adjusted using actual 2005/2006 consumption as reported by EIA in Petroleum Marketing Monthly.AEO Capacity2TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5June 2009 Capacities3Crude17,67617,6161,7153,7238,4996243,055FCC 5,7577101,1872,854181824Hydrocracker 1,6855624983517528Coker 2,372923871,28384526Reformer 3,5232978381,715121553Isom 5091616816961512016 CapacitiesCrude 17,616 17,6031,2793,7138,9336243,055FCC 5,6445851,2002,854181824Hydrocracker 1,7672624994817526Coker 2,638444901,47284550Reformer 3,6052308401,861121553Isom 5591115821920151NOTES:(1)(2)(3)Table 11 - Annual Energy Outlook 2010 Early Release, December 14, 2009.TABLE 2Based onPRISMTM2nd 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"Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8548.417.065.40.464.70.10.00.2Conventional547.14,9245,4713181,5702,842344397Reformulated180.61,6261,8063583451,068-35CARB96.4868964----964TOTAL8737,4358,3076771,9803,9103441,396Gasoline Consumption5E8548.417.065.40.464.70.10.00.2Conventional627.05,6436,2702,1322,0801,172369517Reformulated210.11,8912,1011,307358345-91CARB111.81,0061,118----1,118TOTAL9978,5589,5553,4402,5031,5173691,726E85-------Conventional(719)(799)(1,814)(510)1,670(25)(120)Reformulated(265)(295)(949)(12)723-(56)CARB(139)(154)----(154)TOTAL(1,123)(1,248)(2,763)(523)2,393(25)(330)NOTES:(1)(3)TABLE 3Base 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 byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.Gasoline 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"(2)The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendstocks.(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 are based on annual 2005/2006 vehiclemiles 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 Petroleum Marketing Annual.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 actual 2005/2006 consumptionas reported by the EIA in Petroleum Marketing Monthly.(4)Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8546.416.362.70.462.00.10.00.2Conventional701.36,3127,0136571,8273,787332411CARB92.2830922----922TOTAL8407,1587,9986571,8893,7873321,333Gasoline Consumption5E8546.416.362.70.462.00.10.00.2Conventional802.77,2258,0273,2982,3381,455354583CARB107.29651,072----1,072TOTAL9568,2069,1623,2992,4001,4553541,655E85-------Conventional(913)(1,015)(2,641)(511)2,332(22)(172)CARB(135)(150)----(150)TOTAL(1,048)(1,164)(2,641)(511)2,332(22)(322)NOTES:(1)(2)(3)TABLE 4Base 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 using actual 2005/2006 consumptionas 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 blendstocks.(4) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.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 based on annual 2005/2006vehicle 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 Petroleum MarketingEthanol2Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production3E8547.416.664.00.463.40.1-0.2Conventional624.25,6186,2424881,6983,315338404Reformulated90.3813903179173534-18CARB94.3849943----943TOTAL8567,2968,1526671,9343,8493381,364Gasoline Consumption4E8547.416.764.10.463.40.10.00.2Conventional714.96,4347,1492,7152,2091,313361550Reformulated105.19461,051654179172-46CARB109.59861,095----1,095TOTAL9778,3829,3583,3692,4511,4863611,690E85(0.0)(0.0)---(0.0)-Conventional(816)(907)(2,228)(511)2,001(23)(146)Reformulated(133)(147)(475)(6)362-(28)CARB(137)(152)----(152)TOTAL(1,085)(1,206)(2,702)(517)2,363(23)(326)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 are based on annual 2005/2006vehicle 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 Petroleum Marketing Annual.(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) Supply5As 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 blendstocks.(3)TABLE 5Base 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 byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included.AEOUtilization2TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 52009 Utilization3Crude80% 83% 76% 85% 83% 87% 82%FCC86% 81% 85% 89% 88% 82%Hydrocracker80% 84% 87% 74% 89% 86%Coker 83% 71% 83% 84% 68% 85%Reformer 86% 84% 91% 83% 94% 87%Isom 84% 58% 89% 80% 66% 87%2016 Utilization4Crude83% 82% 85% 86% 80% 93% 79%FCC87% 82% 87% 86% 94% 89%Hydrocracker91% 97% 95% 91% 85% 89%Coker 86% 90% 88% 86% 81% 86%Reformer 83% 82% 82% 81% 93% 90%Isom 89% 82% 95% 87% 93% 87%NOTES:(1)(2)(3)(4)Based onPRISM2nd Quarter 2009 estimated capacity and unit rates for 4th Quarter 2008 - 3rd Quarter 2009.TABLE 6U.S. Refining Utilization (Based on Calendar Day Capacity)1Based onPRISMsimulations.Table 11 - Annual Energy Outlook 2010 Early Release, December 14, 2009. Defined as Total Crude Supply divided by Domestic Refinery Distillation Capacity.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 Refiners 3

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 Qualities 1,2


### 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 Refiners 3

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 Qualities 1,2


### (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 Refiners 3

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 Qualities 1,2


### 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 Refiners 3

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 Qualities 1,2


### (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 5Domestic Production by Crude Oil Refiners3E85 Gasoline65.40.464.70.10.00.2Conventional Gasoline5,4713181,5702,842344397Reformulated Gasoline1,8063583451,068-35CARB Gasoline964----964Jet Fuel1,4887926366641439Distillates4,2453318932,345170505Pentanes922-30-60Other44,1263067222,184128786TOTAL18,2581,3953,8589,1366833,186NOTES:(1)(4)Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleum coke, andmiscellaneous petroleum products.(3)TABLE 8Base 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 byPRISMsimulations and include 10 Vol.% ethanoladded 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 seasonallyadjusted 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 5Domestic Production by Crude Oil Refiners3E85 Gasoline62.70.462.00.10.00.2Conventional Gasoline7,0136571,8273,787332411CARB Gasoline922----922Jet Fuel1,4889627966839405Distillates4,3833349672,421173488Pentanes18--6-12Other43,2842585721,711114628TOTAL17,1701,3453,7088,5946572,866NOTES:(4)"Winter" is defined as October through March. Annual average consumption from the EIA 2010 Annual Energy Outlook Early Releasewas seasonally adjustedusing actual 2005/2006 consumptionas 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, petroleum coke, andmiscellaneous petroleum products.(3) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanoladded to refinery production. Gasoline blenderproduction, based on blendstock sources other than from domestic refiners, is not included.TABLE 9Base 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)Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline609.45,4846,0945811,4773,350287399CARB86.2776862----862TOTAL7446,2787,0225811,5413,3502871,262Gasoline Consumption5E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline837.27,5348,3723,4402,4381,517369608CARB111.81,0061,118----1,118TOTAL9978,5589,5553,4402,5031,5173691,726E85-------Lower Sulfur, Lower RVP Gasoline(2,050)(2,278)(2,859)(961)1,833(82)(209)CARB(230)(256)----(256)TOTAL(2,280)(2,533)(2,859)(961)1,833(82)(464)NOTES:(1)(2)(3)(5) Total U.S. gasoline consumption isbased on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are based on annual 2005/2006 vehiclemiles traveled as reported by the U.S.Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported inthe Petroleum Marketing Annual.(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 10Study 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 using actual 2005/2006 consumptionas reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.Gasoline blender production, based on blendstock sources otherthan from domestic refiners, is not included.Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8546.416.362.70.462.00.10.00.2Lower Sulfur, Lower RVP Gasoline687.16,1846,8716571,7333,787332363CARB92.2830922----922TOTAL8267,0307,8566571,7953,7873321,285Gasoline Consumption5E8546.416.362.70.462.00.10.00.2Lower Sulfur, Lower RVP Gasoline802.77,2258,0273,2982,3381,455354583CARB107.29651,072----1,072TOTAL9568,2069,1623,2992,4001,4553541,655E85-------Lower Sulfur, Lower RVP Gasoline(1,041)(1,156)(2,641)(605)2,332(22)(220)CARB(135)(150)----(150)TOTAL(1,176)(1,306)(2,641)(605)2,332(22)(370)NOTES:(1)(3) The difference between the ethanol in Domestic Refinery Gasoline Production and Gasoline Consumption is the ethanol blended into the imported gasoline blendstocks.(4) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.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 based on annual 2005/2006 vehiclemiles 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 Petroleum Marketing Annual.(6) Net supply requirements are from finished gasoline and gasoline blendstocks, excluding oxygenates, either from foreign imports or non-refinery supply.TABLE 11Study 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 using actual 2005/2006 consumption asreported 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 Refiners 3

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 Qualities 1,2


### 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 Refiners 3

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 Qualities 1,2


### (includes Ethanol)TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners 3

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 Qualities 1,2


### 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 Refiners 3

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 Qualities 1,2


### (includes Ethanol)TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Production by Crude Oil Refiners3E85 Gasoline65.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline6,0945811,4773,350287399CARB Gasoline862----862Jet Fuel1,4947927367241428Distillates4,4183539582,434179494Pentanes7466217236924120Other44,0703126832,200134742TOTAL17,7501,3873,6269,0266653,046NOTES:(1)(2)(4)Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleum coke, andmiscellaneous 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 13Study 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 byPRISMsimulations and include 10 Vol.% ethanoladded 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 seasonallyadjusted 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 PADD 5Domestic Production by Crude Oil Refiners3E85 Gasoline62.70.462.00.10.00.2Lower Sulfur, Lower RVP Gasoline6,8716571,7333,787332363CARB Gasoline922----922Jet Fuel1,4749626566839405Distillates4,3623349472,421173488Pentanes18--6-12Other43,1962585341,711114579TOTAL16,9061,3453,5428,5946572,768NOTES:(2)(4)Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleum coke, andmiscellaneous petroleum products.(3)TABLE 14Study 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 byPRISMsimulations and include 10 Vol.% ethanoladded 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 seasonally adjustedusing 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"Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline586.35,2765,8635681,4343,183284394CARB84.9765849----849TOTAL7206,0586,7775681,4993,1832841,244Gasoline Consumption5E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline837.27,5348,3723,4402,4381,517369608CARB111.81,0061,118----1,118TOTAL9978,5589,5553,4402,5031,5173691,726E85-------Lower Sulfur, Lower RVP Gasoline(2,258)(2,509)(2,872)(1,004)1,666(85)(214)CARB(242)(269)----(269)TOTAL(2,500)(2,778)(2,872)(1,004)1,666(85)(482)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 based on annual 2005/2006 vehiclemiles 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 Petroleum Marketing Annual.(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 15Sensitivity 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 actual 2005/2006 consumptionas reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.Gasoline blender production, based on blendstock sources other than from domestic refiners, is not included.Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8546.416.362.70.462.00.10.00.2Lower Sulfur, Lower RVP Gasoline674.56,0716,7456571,7013,694332363CARB92.2830922----922TOTAL8136,9177,7306571,7633,6943321,285Gasoline Consumption5E8546.416.362.70.462.00.10.00.2Lower Sulfur, Lower RVP Gasoline802.77,2258,0273,2982,3381,455354583CARB107.29651,072----1,072TOTAL9568,2069,1623,2992,4001,4553541,655E85-------Lower Sulfur, Lower RVP Gasoline(1,154)(1,282)(2,641)(637)2,239(22)(220)CARB(135)(150)----(150)TOTAL(1,289)(1,432)(2,641)(637)2,239(22)(370)NOTES:(1)(2)(3)(4) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.Gasoline blender production, based on blendstock sources otherthan from domestic refiners, is not included.(5) Total U.S. gasoline consumption isbased on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are based on annual 2005/2006vehicle miles traveled as reported bythe U.S. Department of Transportation.Grade allocations are based on 2005/2006 average annual share of sales as reported in the Petroleum MarketingTABLE 16Sensitivity 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 Releasewas seasonally adjusted using actual 2005/2006 consumptionas 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 blendstocks.TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners 3

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 Summer Regional Finished Gasoline Qualities 1,2


### 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 Refiners 3

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 Summer Regional Finished Gasoline Qualities 1,2


### (includes Ethanol)TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5

Domestic Production by Crude Oil Refiners 3

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 Winter Regional Finished Gasoline Qualities 1,2


### 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 Refiners 3

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 Winter Regional Finished Gasoline Qualities 1,2


### (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 PADD 5Domestic Production by Crude Oil Refiners3E85 Gasoline65.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline5,8635681,4343,183284394CARB Gasoline849----849Jet Fuel1,4807927367341414Distillates4,3653549492,390184487Pentanes7516417037425118Other44,1703266712,224133816TOTAL17,5431,3913,5628,8446683,078NOTES:(1)(2)(4)Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleum coke, andmiscellaneous 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 18Sensitivity 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 byPRISMsimulations and include 10 Vol.% ethanoladded 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 seasonallyadjusted 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 PADD 5Domestic Production by Crude Oil Refiners3E85 Gasoline62.70.462.00.10.00.2Lower Sulfur, Lower RVP Gasoline6,7456571,7013,694332363CARB Gasoline922----922Jet Fuel1,4489625666239395Distillates4,2753349312,364173473Pentanes18--6-12Other43,1842585211,686114605TOTAL16,6541,3453,4708,4126572,769NOTES:(2)(4)TABLE 19Sensitivity 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, petroleum coke, andmiscellaneous petroleum products.(3) Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanoladded 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 seasonally adjustedusing actual 2005/2006 consumption as reported by the EIA in Petroleum Marketing Monthly.Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline - C475.14,2764,7513191,1532,589310381Lower Sulfur, Lower RVP Gasoline - R165.31,4871,653284421909-39CARB86.9782869----869TOTAL7766,5627,3386031,6393,4983101,289Gasoline Consumption5E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline - C627.05,6436,2702,1322,0801,172369517Lower Sulfur, Lower RVP Gasoline - R210.11,8912,1011,307358345-91CARB111.81,0061,118----1,118TOTAL9978,5589,5553,4402,5031,5173691,726E85-------Lower Sulfur, Lower RVP Gasoline - C(1,368)(1,520)(1,814)(927)1,416(59)(136)Lower Sulfur, Lower RVP Gasoline - R(404)(449)(1,024)63564-(53)CARB(224)(249)----(249)TOTAL(1,996)(2,217)(2,837)(864)1,980(59)(437)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 based on annual 2005/2006 vehiclemiles 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 Petroleum Marketing Annual.(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 20Sensitivity 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 actual 2005/2006 consumptionas reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.Gasoline 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 Refiners 3

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 Summer Regional Finished Gasoline Qualities 1,2


### 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 Refiners 3

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 Summer Regional Finished Gasoline Qualities 1,2


### (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 PADD 5Domestic Production by Crude Oil Refiners3E85 Gasoline65.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline - C4,7513191,1532,589310381Lower Sulfur, Lower RVP Gasoline - R1,653284421909-39CARB Gasoline869----869Jet Fuel1,66610927379641447Distillates4,2512859602,311177518Pentanes4374078225688Other44,1354347562,15341751TOTAL17,8261,4713,7058,9825743,094NOTES:(1)(2)(4)Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleum coke, andmiscellaneous petroleum products.(3)TABLE 22Sensitivity 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 byPRISMsimulations and include 10 Vol.% ethanoladded 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 seasonallyadjusted 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"Ethanol3Hydrocarbon TOTAL U.S. PADD 1 PADD 2 PADD 3 PADD 4 PADD 5Domestic Refinery Gasoline Production4E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline - C501.24,5105,0123311,2322,730324394Lower Sulfur, Lower RVP Gasoline - R166.31,4961,663284409931-39CARB87.7790877----877TOTAL8046,8137,6176151,7063,6623241,311Gasoline Consumption5E8548.417.065.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline - C627.05,6436,2702,1322,0801,172369517Lower Sulfur, Lower RVP Gasoline - R210.11,8912,1011,307358345-91CARB111.81,0061,118----1,118TOTAL9978,5589,5553,4402,5031,5173691,726E85-------Lower Sulfur, Lower RVP Gasoline - C(1,133)(1,259)(1,801)(848)1,558(45)(122)Lower Sulfur, Lower RVP Gasoline - R(395)(439)(1,024)51586-(53)CARB(216)(241)----(241)TOTAL(1,744)(1,938)(2,825)(797)2,144(45)(415)NOTES:(1)(3)(5) Total U.S. gasoline consumption isbased on the full year 2016 forecast contained in the EIA 2010 Annual Energy Outlook Early Release. PADD level allocations are based on annual 2005/2006 vehiclemiles traveled as reported by the U.S.Department of Transportation. Grade allocations are based on 2005/2006 average annual share of sales as reported inthe Petroleum Marketing Annual.(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 23Sensitivity 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 using actual 2005/2006 consumptionas reported by the EIA in Petroleum Marketing Monthly.Totals represent finished gasoline produced from refinery CBOB, RBOB, and CARBOB as determined byPRISMsimulations and include 10 Vol.% ethanol added to domestic refinery production.Gasoline blender production, based on blendstock sources otherthan 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 Refiners 3

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 Summer Regional Finished Gasoline Qualities 1,2


### 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 Refiners 3

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 Summer Regional Finished Gasoline Qualities 1,2


### (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 PADD 5Domestic Production by Crude Oil Refiners3E85 Gasoline65.40.464.70.10.00.2Lower Sulfur, Lower RVP Gasoline - C5,0123311,2322,730324394Lower Sulfur, Lower RVP Gasoline - R1,663284409931-39CARB Gasoline877----877Jet Fuel1,66710927379641448Distillates4,2502859602,310177518Pentanes2692841130070Other44,3234327502,240134766TOTAL18,1251,4693,7299,1386763,114NOTES:(1)(4)Includes LPG, residual fuel oil, aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas, petroleum coke, andmiscellaneous petroleum products.(3)TABLE 25Sensitivity 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 byPRISMsimulations and include 10 Vol.% ethanoladded 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 seasonallyadjusted 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 16,402 1,261 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 

### 163.9 8.2 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 2016 1,2

(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 Purchases 4

### 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 16,402 1,261 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 

### 292.8 26.2 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 2016 1,2

(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 Purchases 4TOTAL 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 4,941 286 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 1,626 322 311 961 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) 6 184.7 8.2 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 2016 1,2

(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 Purchases 5

LSRBOB - R is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes RBOB and the Sensitivity Case 2 includesTOTAL 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 4,941 286 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 1,626 322 311 961 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) 6 184.9 8.2 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 2016 1,2

(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 Purchases 5

LSRBOB - R is Lower Sulfur, Lower RVP Gasoline Blend for Oxygenate Blending. Base Case includes RBOB and the Sensitivity Case 3 includes