DraftDDNational Clean Gasoline

Alliance of Automobile Manufacturers June 2009

National Clean Gasoline

An Investigation of Costs and Benefits

June 2009

Alliance of Automobile Manufacturers 

Published at Uwww.autoalliance.org

For more information, contact

Ellen Shapiro

Director of Automotive Fuels

Alliance of Automobile Manufacturers

1401 Eye Street, N.W.

Washington, DC 20005

202-326-5533

eshapiro@autoalliance.org
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Alliance of Automobile Manufacturers June 2009
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Executive Summary

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EXECUTIVE SUMMARY

Introduction

The Alliance of Automobile Manufacturers (Alliance)F

1

F recently commissioned two studies

examining the costs and benefits of introducing a cleaner national gasoline, defined as a Clean 

Air Act regulatory standard, into the U.S. market. The first study, conducted by MathPro, Inc.,

investigated the refining costs of producing the proposed fuel standard, and the second study, 

conducted by Air Improvement Resources, Inc., investigated the standard’s impacts on emissions

from on-road gasoline-powered vehicles (excluding motorcycles). The Alliance designed the 

gasoline standard to reduce vehicle emissions and, importantly, to enable lean burn gasoline 

engines, which are a new, fuel efficient vehicle technology. The Alliance also sought to create a 

standard that could be used as a single national gasoline, eventually replacing the so-called 

boutique gasolines being sold in parts of the U.S. to reduce emissions. For study purposes, the 

Alliance named its proposed fuel ―National Clean Gasoline‖ (NCG). 

Fuel quality plays a critical role in vehicle operation and emissions because it affects the 

combustion process and can interact with vehicle components, including, but not limited to, 

emission control systems. Certain gasoline compounds—especially those containing sulfur—

reduce the effectiveness of emission control systems, thereby causing vehicle emissions to 

increase.F

2

F As another example, gasoline’s distillation characteristics affect combustion 

efficiency and smoothness, and its vapor pressure affects evaporative emissions. Depending on 

the property or contaminant, effects may occur immediately, build up gradually over time or be 

irreversible. Most importantly for policymakers, fuel quality may affect a vehicle’s ability to 

comply with emission standards, deliver planned fuel economy, use certain technologies or 

satisfy customers. This is why vehicles and fuels must be viewed as a system. 

Quality of National Clean Gasoline 

In specifying NCG, the Alliance capped sulfur at 10 parts per million (ppm), which is 

significantly lower than current federal limits.F

3

F As noted, sulfur reduces the effectiveness of 

catalytic converters used to meet stringent U.S. and California vehicle emission standards. 

Manufacturers have been able to build compliant vehicles despite the sulfur levels found in 

federal gasoline, but vehicle emissions would be much lower if the sulfur levels were lower. As 

 

1 The Alliance is a trade association of eleven car and light truck manufacturers—BMW Group, Chrysler, Ford 

Motor Company, General Motors, Jaguar Land Rover, Mazda, Mercedes-Benz, Mitsubishi Motors, Porsche, Toyota 

and Volkswagen. 

2 Metallic additives also reduce the effectiveness of emission controls, but the federal government and California 

prohibit their use in federal and California reformulated gasolines, respectively, and virtually all U.S. refiners refrain 

from using such additives in conventional gasolines. 

3 EPA regulations require gasoline produced for sale outside of California to have an annual average of no more than 

30 ppm sulfur at retail with a per gallon cap of 80 ppm, but the EPA test tolerance limit allows an individual 

gasoline sample sold at retail to contain as much as 95 ppm sulfur. California rules require sulfur to be no more than 

30 ppm, and the average today is about 9 ppm, which is better than the federal limit but still not as clean as gasoline 

standards in Europe and Japan, which allow a maximum of 10 ppm sulfur. Under its ―Phase 3‖ gasoline regulation, 

California is scheduled to reduce its maximum per gallon sulfur limit to 20 ppm on December 31, 2011, and the 

average is expected to decline further. 
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EPA seeks to reduce smog-forming emissions further, reducing gasoline sulfur levels would be a

helpful control strategy. It would also help reduce emissions in California where sulfur levels 

are relatively low, even if the state did not adopt NCG, because vehicles coming into the state 

would be cleaner than they are now.

Sulfur is also important because certain new technologies require different emission control 

systems that are more sensitive to sulfur. Like diesel engines, lean-burn gasoline engines are 

very efficient at burning hydrocarbons, which improves the vehicle’s fuel economy compared 

with similar vehicles using conventional spark ignition engines. Lean burn gasoline engines, 

however, are optimized for fuel economy, which can lead to higher engine-out NOx emissions, 

also like diesel. The higher NOx emissions require new, advanced emission control systems 

similar to those used in diesel vehicles to enable compliance with stringent U.S. and California 

emission standards, but the systems are quickly poisoned by sulfur. Lean burn gasoline 

technology can work acceptably only with gasoline containing less than 10 ppm sulfur (also 

called ultra-low sulfur gasoline or ULSG).

The Alliance constrained additional gasoline properties either to match existing federal or 

voluntary ASTM standards (e.g., benzene, driveability index), the lowest level acceptable for 

vehicle operation across the U.S. (e.g., vapor pressure) or to comply with EPA’s Complex Model

constraints (e.g., aromatics, olefins). Ethanol content was set at 10% by volume (the limit under 

existing federal regulations) to reflect the national ethanol mandate volumes required under the 

Renewable Fuel Standard in the Energy Independence and Security Act of 2007. 
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Table 1: Proposed National Clean Gasoline Specifications 

Property Units Limit Comments

Sulfur ppm 10 max

Reduces emissions from the existing 

fleet and enables fuel efficient lean 

burn technologies. Regulated by EPA 

and California.

RVP psi 7 max

Selected to match the lowest emitting 

value while maintaining acceptable 

vehicle operation. Regulated by EPA 

and some states.

Benzene % v/v 0.62 avg New EPA national toxics standard

(―MSAT2‖).

Ethanol % v/v 10 max Current federal maximum.

Octane

Regular

Premium

(R+M)/2 87 min

93 min

Based on industry practice. Limits 

apply at all altitudes.4F

ASTM Driveability 

IndexF

5 * 1250 max

The ASTM voluntary standard, which 

is enforceable in some states. DI is 

important for engine calibration, 

engine performance and emissions.

Alliance Distillation 

Index5 * 1200 max For sensitivity analysis (preferred Alliance DI limit).

Aromatics, Olefins, 

E200, E300

*

Unconstrained for NCG but indirectly 

regulated through EPA’s Complex 

Model, which is used to certify 

gasoline compliance.

*No units apply but, in this context, temperatures are measured in degrees Fahrenheit.

Approach

The studies targeted 2010 as the earliest possible year for implementing the NCG specifications. 

The refining economics study was completed first, to provide baseline data for the emissions 

analysis. The study modeled NCG costs to reflect a phased rollout: first, it introduced NCG in 

current federal RFG areas; second, it replaced all low RVP gasolines with NCG; and third, it 

replaced all conventional gasoline with NCG. This sequence begins with the least-cost fuel 

replacement and moves on to progressively more costly fuel replacements. The study area 

 

4

In general, refiners select octane levels to meet consumer demand. The Alliance believes it is acceptable for 

Premium gasoline to be defined as having a minimum 91 octane ((R+M)/2).

5 The Alliance used the ASTM Driveability Index limit, which applies at the refinery gate, as the basis for the study 

instead of its preferred Distillation Index, which applies at the retail pump, because recent changes have brought the 

ASTM limit much closer to the Alliance recommendation and because refiners are using the ASTM limit in the 

market. To determine the impact of imposing the Alliance Distillation Index with a tighter limit, a sensitivity 

analysis was conducted.
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covered most of the U.S. (PADDsF

6

F 1-3) and its gasoline pool but excluded the Rockies and West 

Coast states (PADDs 4 and 5) for reasons explained in the study. 

The refining economics study estimated the refining costs of producing the specified new fuel in 

volumes consistent with the three implementation phases. This analysis was limited to 

examining refining costs; it did not include analyzing NCG’s possible impacts on fuel 

distribution, price (which is determined by market forces) or other non-refinery factors. The 

primary analysis assumed a crude oil price of $51.20/barrel, which was the reference case 

projection derived by the Energy Information Administration for its 2007 Annual Energy 

Outlook (AOE2007).F

7

F The unprecedented rise in crude oil prices during 2008, however, led the 

Alliance to conduct a sensitivity analysis using a crude oil price of $125/barrel. 

The emissions study used fuel quality estimates from the refining economics study as inputs to 

well-accepted and publicly available emissions modeling tools. For public policy purposes, it is 

insufficient to know how emissions change for one vehicle; models must be used to estimate the 

fleet-wide emission impacts, to accommodate variations in vehicle type, age, usage and other 

factors, including fuel quality. Emissions also change year to year; this study looked at the 

emission changes between 2010 and 2020 for the same geographic area covered by the cost 

study. Recent results from an EPA study of toxic emissions from Tier 2 vehicles were included 

as part of a sensitivity analysis.

Findings

Refining Economics. The estimated average cost of producing the full volume of NCG, using the 

AEO2007 crude oil reference price estimate, is 2.75¢/gallon; the estimates are slightly lower for 

PADDs 1 and 2. The estimated marginal cost of introducing the last increment of NCG is about 

3.9¢/gallon and slightly higher in PADDs 1 and 3. Improving the distillation index by using the 

Alliance’s preferred Distillation Index equation and limit of 1200—i.e., tightening the distillation 

constraints further—would increase average refining cost by about 1¢/gallon in PADD 1 only; 

other regions would see no impact on average refining costs because their gasoline already meets 

this limit. The estimated marginal cost for the last increment of NCG is about 5¢/gallon, also 

only in PADD 1. These estimates pertain to average refining costs, and as such, they do not 

indicate costs that would be incurred by any individual refineries. 

The sensitivity analysis using a higher crude oil price indicates that large increases in crude oil 

prices lead to moderately higher refining costs for producing NCG. With crude oil at 

$125/barrel, the estimated average cost of producing the full volume of NCG is about 

4.5¢/gallon, an increase of 1.75¢/gallon compared with the estimates based on crude oil priced at 

$51/barrel. The corresponding estimated marginal cost of producing the last increment of NCG 

is about 6.5¢/gallon, which is an increase of about 2.5¢/gallon. Assuming no change in 

electricity and natural gas prices, each $10 change in the price of crude oil would lead to a 

change of about 0.24¢/gallon in the average cost of producing NCG.

 

6

―PADD‖ means Petroleum Administration Defense District; see www.eia.doe.gov for a map. Roughly, PADD 1 

corresponds to the east coast, PADD 2 corresponds to the Midwest and PADD 3 corresponds to the gulf coast states.

7 Energy Information Administration, ―Annual Energy Outlook 2007 with Projections to 2030,‖ Report #:DOE/EIA0383(2007), February 2007, available at http://www.eia.doe.gov/oiaf/archive/aeo07/index.html (May 21, 2009). 
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Table 2. Estimated Refining Cost Changes

Estimated Average Refining Cost, 

at Two Crude Oil Prices

Cost Impact of 

Higher Crude 

Refining Cost of NCG units $51/bbl $125/bbl Price

Average cost ¢/gal 2.75 4.5 1.75

Average cost 

(Alliance DI sensitivity case)

¢/gal 3.75

(PADD 1 only)

* *

Incremental cost ¢/gal 4 6.5 2.5

Incremental cost 

(Alliance DI sensitivity case)

¢/gal 8.75

(PADD 1 only)

* *

*Not estimated. 

Emissions. The emissions investigation found that NCG would have significant impacts on 

evaporative hydrocarbon (HC) and exhaust nitrogen oxides (NOx) emissions. Between the study 

years of 2010 and 2020 and on a per-PADD basis, evaporative HC reductions ranged from 12% 

to 19%, and exhaust NOx reductions ranged from 10% to 14%. Exhaust HC emissions also 

declined, ranging from 1% to almost 4% from their already very low baseline. The sensitivity 

analysis using newer Tier 2 emission impacts suggests these vehicles are more sensitive to fuel 

sulfur effects than the existing models indicate. Compared to the national on-road HC and NOx 

emissions inventory, these reductions are significant, especially if the estimates are conservative 

as the sensitivity analysis suggests. This finding could be very important to states trying to meet 

more stringent ozone ambient air quality standards. 

Table 3. Summary of Emission Reductions due to NCG

2010 2015 2020

Exhaust HC 1 – 3% 1.5 – 3.5% 1.75 – 3.75%

Evaporative HC 12 – 19.5% 11.5 – 18.5% 11 – 18.5%

NOx 10 – 11% 12 – 13% 13 – 14%
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Conclusion

These studies highlight the potential benefits and costs of improving national gasoline quality. 

The estimated costs are reasonable, even when crude oil prices are high. The emission benefits 

would be substantial. Additional benefits to gasoline supply accrue simply by eliminating the 

many boutique gasolines introduced over the years for air pollution control purposes. 

Introducing an ultra-low sulfur gasoline nationwide would enable automakers to introduce a new 

fuel efficient vehicle technology—lean burn gasoline engines—increasing the options for 

improving fuel economy for both automakers and consumers. All of these factors support 

improving fuel quality on a national basis as a feasible emissions control strategy that will also 

help the country meet other important national objectives.
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TABLE OF CONTENTS

EXECUTIVE SUMMARY ............................................................................. I

Introduction ................................................................................................................................ i

Quality of National Clean Gasoline .......................................................................................... i

Approach...................................................................................................................................iii

Findings..................................................................................................................................... iv

Conclusion................................................................................................................................. vi

CHAPTER 1: REFINING ECONOMICS OF A NATIONAL CLEAN GASOLINE......... 1—I

CHAPTER 2: EMISSION BENEFITS OF A NATIONAL CLEAN GASOLINE............ 2—I

APPENDIX A. MATHPRO INC.

APPENDIX B. AIR IMPROVEMENT RESOURCE, INC.
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Chapter 1 0BRefining Economics of a National Clean Gasoline
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FINAL REPORT

REFINING ECONOMICS OF 

A NATIONAL CLEAN GASOLINE STANDARD

FOR PADDS 1-3

A study performed for 

The Alliance of Automobile Manufacturers 

by

MathPro Inc.

P.O. Box 34404

West Bethesda, Maryland 20827-0404

June 27, 2008
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1BCONTENTS

1. INTRODUCTION.................................................................................. 1—1

1.1 Background ............................................................................................................. 1—1

1.2 Proposed NCG Standard........................................................................................ 1—1

1.3 Technical Approach................................................................................................ 1—2

1.4 Summary of Results................................................................................................ 1—4

1.5 Organization of the Report .................................................................................... 1—4

2. BOUNDARY CONDITIONS FOR REFINERY MODELING.............................. 1—6

3. PROJECTED BASELINE REFINERY OPERATIONS FOR 2010.................... 1—8

4. ESTIMATED AVERAGE PROPERTIES OF THE U.S. GASOLINE POOL......... 1—9

5. RESULTS OF THE CALIBRATION, REFERENCE, AND STUDY CASES........ 1—11

6. RESULTS OF THE DI SENSITIVITY CASES ........................................... 1—15

7. RESULTS OF THE CRUDE PRICE SENSITIVITY ANALYSIS ...................... 1—17

8. ANALYTICAL ISSUES........................................................................ 1—19

9. COMMENTS ON STUDY RESULTS AND FINDINGS ................................. 1—21

9.1 Magnitude of the Estimated Average and Incremental Costs.......................... 1—21

9.2 NCG Costs Depend on Phase-In Sequence......................................................... 1—21

9.3 Capabilities of Foreign Refiners to Produce NCG Were Not Considered ...... 1—21

9.4 Other Factors Could Affect Refining Costs of NCG ......................................... 1—22

9.5 Logistics System Effects Were Not Considered ................................................. 1—22

9.6 Aggregate Refinery Modeling and Possible Over-Optimization...................... 1—23

APPENDIX............................................................................................. 1—24
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Refining Economics

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1. INTRODUCTION 

The Alliance of Automobile Manufacturers (the Alliance) retained MathPro Inc. to analyze the 

technical and economic effects of a contemplated new federal standard for a national ―clean 

gasoline‖ (NCG) for use throughout the United States (ex California). The NCG standard would 

augment the federal standard for reformulated gasoline, and NCG would replace special 

gasolines (―boutique fuels‖) and conventional gasoline. This report deals with the technical 

approach and the results of the analysis. 

1.1 Background

We understand that the Alliance advocates an NCG program because it would reduce emissions 

by gasoline-powered vehicles in the U.S. in three ways. 

 In the existing vehicle fleet, NCG would offer better emissions performance than the 

boutique fuels and conventional gasoline (CG) that it would replace; the NCG standards also 

would improve the emissions performance of federal reformulated gasoline (RFG).

 In future vehicles, general availability of NCG would allow automobile manufacturers to 

tailor engine designs to a narrow and predictable range of gasoline properties, thereby 

enabling more economical and effective compliance with new emissions standards. 

 In future vehicles, NCG would enable use of improved emission control technology that is 

sensitive to the sulfur content of gasoline.

The contemplated NCG program would phase in over time. Initially, for example, the NCG 

standards might be superimposed on the RFG program – gasoline sold in RFG areas would have 

to meet both sets of standards. Next, NCG could become the gasoline of choice in areas 

choosing to use a cleaner gasoline for meeting the 8-hour ozone standard. Ultimately, the NCG 

program could result in the U.S. gasoline pool (ex California) comprising no more than two 

gasoline types: NCG and federal RFG/NCG.

NCG would be a cleaner burning gasoline than either CG or low-RVP gasoline; but it would 

have higher refining costs, with the magnitude of the cost increase depending on the NCG 

standard and its phase-in sequence. The refining cost and investment requirements for NCG 

production would tend to increase with NCG’s volume share of the U.S. gasoline pool. 

1.2 Proposed NCG Standard

For purposes of this study, NCG is defined in terms of a set of gasoline properties, shown in 

Table 1 on the next page. 
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The Driveability Index (DI) standard in Table 1 applies to the Driveability Index definition 

recently adopted by ASTMF

1

F: 

DI (oF) = 1.5*T10 + 3.0*T50 + 1.0*T90 + 2.403*(Vol% EtOH). 

The last term in the equation adjusts the DI upwards by about 24 numbers when ethanol is 

blended at 10%, to reflect ethanol’s observed adverse effects on driveability.

The study considered a phased introduction of NCG into the U.S. gasoline pool, with the 

following assumed sequence of NCG volume additions: (1) augmentation of the RFG standards 

with the NCG standard (that is, introduction of NCG in current RFG areas); (2) replacement of 

all low-RVP (7.0 and 7.8 RVP gasoline); and (3) replacement of all CG. This sequence begins 

with the least-cost replacement and moves on to progressively more costly ones. 

1.3 Technical Approach

We analyzed the refining economics of the proposed NCG standard at each step in the phase-in 

sequence by means of regional refinery LP modeling, using our proprietary refinery modeling 

system. In particular, we applied three models, representing aggregate refining operations in 

PADD 1, PADD 2, and PADD 3, respectively.F

2

F The target time period for the analysis was the 

2010 summer season, as specified by the Alliance. 

 

1 ASTM Subcommittee D02.A Section 3 adopted the new standard, ASTM D4814-06a, in November 2006. 

2 We did not consider PADDs 4 and 5 in the analysis, because (i) the total gasoline volume produced and consumed 

in PADDs 4 and 5 ex California is small and (ii) the NCG standard would not apply in California. 

Table 1: Proposed Standards for National Clean Gasoline (NCG) 

Property Units Spec. Type

Octane ((R+M)/2)

 Regular 87 Min.

 Premium 93 Min.

Complex Model 

 RVP psi 7 Max. Set at 6.8 psi in the refinery models 

 Sulfur ppm 10 Max. Set at 5 ppm in the refinery models 

 Benzene vol.% 0.62 Avg. EPA's new benzene standard

 Aromatics vol.% ---- No Aromatics limit for NCG

 Olefins vol.% ---- No Olefins limit for NCG

 E200 vol.% ---- No E200 requirement for NCG

 E300 vol.% ---- No E300 requirement for NCG

 Oxygen wt.% ---- No oxygen required in NCG, but the entire U.S. gasoline pool (including NCG)

is assumed to be E10

Driveability Index 1250 Max. Set at 1220 in the refinery models 

Comments
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The refinery modeling reflected the following assumptions regarding national and state policies 

affecting gasoline quality.

 All gasoline is ethanol-blended at 10 vol% in 2010 (―National E10”), resulting in national 

ethanol use of about 141⁄2 bgy. (By contrast, the Department of Energy’s Annual Energy 

Outlook 2007 (AEO 2007) projected ethanol use of about 10.8 bgy in 2010);

 No use of MTBE in gasoline;

 Implementation of the 8-hour ozone standard; 

 Continuation of the 1 psi RVP waiver for ethanol blended CG and for low-RVP gasoline in 

those states (mostly in the Midwest) now granting the waiver (which does not apply for lowRVP gasoline during the peak ozone months, July and August);

 Continuation of the RVP waiver for NCG that replaces CG, but not for NCG that replaces 

low-RVP gasoline, even in the Midwest; and 

 No increase in the number of distinct gasoline types, per Title 15 Subtitle C of EPAct2005.

We developed regional (i.e., PADD-level) projections based on price and national volume 

projections from AEO 2007 (Reference Case) and on prior MathPro studies of 

 Demand for and refinery production of gasoline;

 Additional volumes of special gasolines – 7 RVP, 7.8 RVP, and RFG – that would be called 

out (i.e., specified in SIPs) in response to the 8-hour ozone standard; and

 Ethanol use consistent with national E10. 

The refinery modeling encompassed a 2002 Calibration Case, a 2010 Reference Case, three 2010 

Study Cases and three DI Sensitivity Cases. The three Study Cases represented the staged 

introduction of NCG in the aforementioned sequence. The three DI Sensitivity Cases 

represented the introduction of NCG in the same sequence, but with a maximum Driveability 

Index of 1200, rather than 1250 as in the Study Cases. Each case encompassed separate 

modeling runs for PADD 1, PADD 2, and PADD 3. 

All of these cases incorporated a crude oil price of $51.2/Bbl ($2006), the AEO 2007 Reference 

case projection for 2010. Because the recent run-up in crude oil prices calls that projection into 

question, we conducted a brief sensitivity analysis in which we estimated the effects of a much 

higher crude oil price for 2010 – $125/Bbl ($2006) – on the refining economics of NCG 

production (with DI capped at 1250).F

3

F

This sensitivity analysis did not involve additional refinery modeling. Rather, we estimated a set 

of prices for other refinery inputs and refined products consistent with a crude oil price of 

$125/Bbl and then applied these prices to the refinery input and output volumes returned by the 

various Study Cases. 

 

3

 We used projections from AEO 2007 in the refining analysis because we conducted the analysis in the third 

quarter of 2007, prior to the publication of AEO 2008. By way of comparison, the AEO 2008 Reference Case 

projects a crude price of $78/Bbl in 2010. 
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1.4 Summary of Results

Table D-1a (Appendix D) summarizes the primary economic results of the original Study Cases 

in the refining analysis (with AEO 2007’s projected crude oil price). The table shows the 

estimated average refining cost of the proposed NCG standard, by PADD, in ¢/gal of NCG and 

billions of dollars of refinery investment, at each of the various NCG phase-in stages. 

Averaged over PADDs 1, 2, and 3, the estimated average cost of producing NCG at the assumed 

maximum market coverage – with NCG augmenting all RFG and replacing all low-RVP 

gasoline and CG in the three PADDs – is about 23⁄4¢/gal. The corresponding estimated average 

incremental cost for the last increment of NCG introduced (to replace CG) is about 4¢/gal. 

The results of the DI Sensitivity Cases in the refining analysis (not shown in Table D-1a) 

indicate that lowering the DI standard to 1200 in the NCG program would (i) increase the 

average refining cost of NCG in PADD 1 (only) by about 1¢/gal and the incremental cost (for 

displacing CG) by about 5¢/gal (given AEO 2007’s projected crude oil price) and (ii) have no 

effect on average refining costs in the other PADDs. However, as discussed later in this report, 

the DI 1200 standard would likely impose additional costs on some individual refineries, costs 

not captured in our aggregate refinery modeling.

Table D-1b (Appendix D) summarizes the estimated effects of increasing crude price on the 

primary economic results of the refining analysis. At a projected crude oil price of $125/Bbl 

($2006), the estimated average cost of producing NCG (averaged over PADDs 1, 2, and 3) at the 

assumed maximum market coverage – with NCG augmenting all RFG and replacing all lowRVP gasoline and CG in the three PADDs – is about 41⁄2¢/gal. That is, we estimate that the 

increase in crude oil price from $50/Bbl to $125/Bbl increases the average refining cost of the 

NCG program by about 13⁄4¢/gal and the corresponding average incremental cost for the last 

increment of NCG introduced (to replace CG) by about 23⁄4¢/gal (relative to the results of the 

original Study Cases.)

Table D-1b also indicates that, for crude prices in the vicinity of $125/Bbl, a $10/Bbl change in 

crude price would lead to a change of about 1⁄4¢/gal in the average cost of producing NCG 

(assuming no change in electricity and natural gas prices). 

1.5 Organization of the Report

The following sections of the report describe the development of the regional refining models for 

analyzing prospective effects of the NCG program, present the results of the analysis, and 

discuss analytical issues that emerged in the refinery modeling. 

 Section 2 shows the boundary conditions (refining capacity, refining inputs & outputs, etc.) 

developed for calibrating our refinery models.

 Section 3 discusses the projections of refinery inputs and refined product out-turns developed 

to establish the baseline (Reference case) for 2010, the target year for the analysis.

 Section 4 provides information on average properties of the U.S. gasoline pool, developed 

from data provided by the Alliance and EPA.
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 Section 5 presents results of the refinery modeling analysis for the Calibration, Reference, 

and Study Cases. 

 Section 6 presents results of the refinery modeling analysis for the DI Sensitivity Cases, in 

which the DI standard is lowered from 1250 to 1200. 

 Section 7 discusses the sensitivity analysis to estimate the effect of higher crude oil prices on 

the economics of NCG production. 

 Section 8 discusses analytic issues that arose in the refinery modeling and that influence the 

study results.

 Section 9 discusses the results and findings of the analysis. 
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2. BOUNDARY CONDITIONS FOR REFINERY MODELING

Boundary conditions are the constraints in a refinery model that represent actual or forecast 

market and technical conditions to which refinery operations must conform. They are used in the 

development and calibration of refinery models representing the operations of a specific refinery 

or group of refineries – for this study the aggregate operations of refineries in PADDs 1, 2, and 

3. Boundary conditions include refining capacity; refinery inputs of crude oil, unfinished oils, 

and blendstocks; refinery out-turns of finished products, such as gasoline and diesel fuel; 

specifications for the properties of refined products (e.g., octane, RVP, and sulfur for gasoline); 

and certain regulatory standards that constrain refining operations (e.g., RFG standards 

implemented through the Complex Model and MSAT standards).

Calibration of a refinery model involves adjusting technical data elements in the model such that 

the model yields solution values that match with sufficient precision certain key measures of 

refinery operations in the calibration period, in this case Summer 2002. In this study, matching 

the properties of the gasoline pool ―produced‖ by the refinery models to the actual PADD-level 

pool properties estimated from Alliance or EPA data is of particular importance. This 

requirement is discussed in Section 4.

Tables A-1 through A-5 show the boundary conditions developed for this study for the 

calibration period, Summer 2002.

 Table A-1 shows petroleum refining capacity by PADD for 2002 and 2006. We used 

refining capacity reported for 2002 to calibrate the PADD 3 refining model to operations in 

the summer of 2002. We used refining capacity reported for 2006 to develop the models 

representing refinery operations in Summer 2010.

 Tables A-2a and A-2b show refinery inputs, volumes of feed going to specific refinery 

processes, crude oil properties, and net production of refined products, by PADD.

 Tables A-3a, A-3b, A-3c, and A-3d show PADD-level estimates of refinery production of 

gasoline, by type (conventional, low-RVP, and RFG), and gasoline blendstock use.

 Table A-4 shows average prices for refining inputs of crude oil, electricity, and natural gas 

for 2002, and projected prices for 2010.

 Table A-5 shows the supply of major refined products by PADD. 

Information on refined product supply from this table, in combination with EIA projections 

of aggregate energy supply and regional energy use, was used to develop projections of 

PADD-level energy supply, as discussed in Section 3.

Not shown in this set of tables are other boundary conditions – including various constraints on 

the average properties of refined products, Complex Model constraints, and MSAT standards –

used in configuring and calibrating the 2002 regional models. Constraints on the average 

properties of refined products bear on the RVP of gasoline, the benzene and sulfur content of 

gasoline (based on gasoline properties discussed in Section 3), and the sulfur content of on-road 
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and off-road diesel fuel (based on previous MathPro studies). The Complex Model and MSAT 

constraints are based on analyses in previous MathPro studies.
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3. PROJECTED BASELINE REFINERY OPERATIONS FOR 2010

Tables B-1 through B-7 show our projections of refinery inputs and outputs for the target 

period, Summer 2010. We developed the projections primarily using data from the Department 

of Energy’s Petroleum Supply Annual 2004 in combination with aggregate energy forecasts and 

regional energy demand forecasts from AEO 2007.

 Tables B-1 to B-3 show projections for 2010 of total U.S. petroleum supply and disposition, 

imports and exports of petroleum products, and regional growth in energy consumption. We 

used these projections in developing the PADD-level projections shown in subsequent tables.

 Table B-4 shows projected supply of major refined products, by PADD. 

 Table B-5 shows refinery inputs and refined product out-turns, by PADD. 

 Tables B-6a, B-6b, B-6c, and B-6d show projections of gasoline out-turns, by PADD and by 

type of gasoline, and the corresponding projected pattern of use of gasoline blendstocks. 

These projections assume implementation of the 8-hour ozone standard by 2010, and 

consequent increases in the shares of low-RVP and reformulated gasoline in the gasoline 

pool. Our estimates of the effects of the 8-hour ozone standard on gasoline markets come 

from MathPro Inc.’s earlier published work for the American Petroleum Institute (API). F

4

F 

 Table B-7 shows projected national ethanol use of about 141⁄2 bgy, allocated by PADD, 

consistent with blending ethanol at 10 vol%. 

Tables A-1 (2006 data), A-4 (2010 projection), B-5, B-6c, B-6d, and B7 establish the primary 

boundary conditions for the 2010 Baseline (Reference) case. 

The 2010 Reference and Study cases reflect an increase in refined product out-turns (net of 

purchased gasoline blendstocks), relative to the 2002 Calibration cases, of about 8% for PADD 

1, 10% for PADD 2, and 20% for PADD 3 (which includes projected increases in shipments of 

refined products to the other PADDs). The 2010 regional refined product out-turns reflect about 

a 16% projected aggregate increase in U.S. refinery out-turns (including ethanol) over those in 

2004. 

 

4

―Potential Effects of 8-Hour Ozone Standard on Gasoline Supply, Demand, and Production Costs‖; Prepared for 

the American Petroleum Institute by MathPro Inc.; March 2005
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4. ESTIMATED AVERAGE PROPERTIES OF THE U.S. GASOLINE POOL

Tables C-1 and C-2 show estimated average gasoline properties, by gasoline type, for the years 

2000 through 2004. We derived these property sets from gasoline sampling data from the 

Alliance’s North American Fuel Surveys and from data in EPA refinery and importer reports and 

federal RFG Area Surveys. The Alliance surveys are taken at the retail level F

5

F; the EPA reports 

are at the refinery and blender level. 

Table C-1 shows the average properties of RFG and CG for the U.S. (ex California) derived from 

the Alliance surveys and reported by EPA. The average gasoline properties derived from the two 

sources are in good agreement, except for the pool averages for aromatics and olefins content. 

The Alliance-derived estimate for pool aromatics for 2003 is 28.8 vol%, whereas the EPA 

survey data indicate pool aromatics at 25.7 vol%, about 3 percent points lower. The 

Alliance-derived estimates of aromatics in both RFG and CG are higher than the 

corresponding estimate in the EPA reports. Likewise, the Alliance-derived estimate for 

aromatics in RFG is higher than the estimate derived from the EPA RFG Area Surveys.

The Alliance-derived estimates for the olefins content of RFG are generally within a percent 

point of the values in the EPA reports and the estimates derived from the EPA RFG Area 

Surveys. However, the Alliance-derived estimates of olefins for CG are about 2 percent 

points lower than the values in the EPA reports.

Table C-2 shows estimated average properties for RFG and CG by PADD of origin, not 

consumption. We estimated average properties for both the Alliance surveys and the EPA 

federal RFG Area Surveys by assigning the surveyed cities to specific PADDs, according to the 

sourcing of their gasoline supplies. For example, cities assigned to PADD 3 included all of those 

located in PADD 3, along with the Washington metropolitan area and all cities in the southeast. 

Cities assigned to PADD 1 included Pittsburgh and all cities in the northeast, except those in 

New England (e.g., Boston), because the latter areas are supplied largely by imports. All cities in 

PADD 2 were assigned to PADD 2.

Because the EPA data sources encompass more of the national gasoline pool than the Alliance 

fuel surveys, we chose to rely more heavily on the EPA sources than on the Alliance surveys 

with respect to the target aromatics and olefin contents in the Calibration Case. In particular, we 

used average gasoline properties derived from the 2003 EPA reports (reflecting refinery-level 

reporting) as the gasoline property targets for the 2002 Calibration model run. (The average 

gasoline properties reported in the Alliance surveys are stable between 2002 and 2003, 

suggesting that average gasoline properties in 2002 were similar to those we have available for 

2003 from EPA data.) 

For each PADD, we adjusted E130 for most blendstocks, E200 and E300 for FCC naphtha and 

reformate, and olefin content for FCC naphtha. In addition, for PADDs 1 and 2, we adjusted the 

 

5

 Excluding California and Nevada (areas supplied exclusively by California refineries) and Fairbanks, AK, the 

Alliance Survey reports the properties of retail gasoline samples taken in twenty-one cities: eight RFG cities, eight 

low-RVP cities, two ethanol-blended CG cities, and three CG cities. The Surveys provide nearly complete coverage 

for RFG areas, broad coverage of low-RVP areas, and thin coverage of CG areas. 
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olefins and sulfur content of FCC naphtha. Table D-7 (discussed below) compares the average 

gasoline pool properties returned by models in the Calibration Case, which reflect these 

adjustments in blendstock properties, with the average gasoline pool properties estimated from 

the 2003 EPA data. For PADD 3, the average aromatic contents are about 2 percent points 

higher than indicated by the 2003 EPA data. 

We elected not to adjust the aromatics contents of the primary aromatics-containing blendstocks 

in the refining models (reformate and FCC naphtha), because these aromatics contents are 

consistent with information from various industry sources on the aromatics content of PADD 3 

gasoline blendstocks. The divergence in aromatics content may arise from the way we handled 

gasoline blendstock production in this study, versus how refiners report such production. We 

include in the finished gasoline volume all gasoline blendstock volumes produced, rather than 

treating these volumes as a separate category. The other average gasoline properties from the 

Calibration case for PADD 3, along with those for PADDs 1 and 2, are close to the reported 

average gasoline properties.
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5. RESULTS OF THE CALIBRATION, REFERENCE, AND STUDY CASESF

6

As described in Section 1.3, we developed and analyzed a series of refinery modeling cases to 

assess the effects of the contemplated NCG program. Each case encompassed separate modeling 

runs for each PADD of interest. 

 The 2002 Calibration Case serves to calibrate the model to historical data for Summer 2002. 

 The 2010 Reference Case establishes the Summer 2010 baseline case to which the Study 

Cases are compared. 

The Reference Case incorporates refining capacity sufficient to produce projected refined 

product out-turns, meet the Tier 2 sulfur standards for gasoline, and supply the volumes of 

low-RVP gasoline and RFG to meet the (projected implementation of the) 8-Hour Ozone 

Standard. The Reference Case assumes that all gasoline is E10.

 Study Cases 1 through 3 assess the effects of progressively increasing the share of the 

gasoline pool meeting a NGC standard. 

 In Study Case 1: RFG, the federal RFG standards are augmented by the NCG standard -

- specifically, the NCG standards for 7.0 RVP, 5 ppm sulfur content, and DI 1250 are 

overlaid on the RFG standards.

 In Study Case 2: Low-RVP, all 7.0 and 7.8 RVP gasoline is replaced by NCG (with all 

RFG also conforming to the NCG standard). 

In Study Case 3: CG, all CG (except for a small export volume in PADD 3) is replaced by 

NCG (in addition to all RFG and low-RVP gasoline).

Tables D-1 through D-7 show the results of the Calibration, Reference, and Study cases, for 

each PADD. 

 Table D-1 summarizes the economic results of our analysis. The table shows the estimated 

refining costs of the NCG standard in ¢/gal of NCG and in billions of dollars of refinery 

investment, at the various phase-in stages. 

Average per-gallon costs increase progressively as the NCG standard covers first RFG, then 

low-RVP gasoline, and finally CG. The estimated average per-gallon cost of NCG for the 

aggregate of PADDs 1-3 increases from about 11⁄2¢/gal in Study Case 1 to about 3¢/gal in 

Study Case 3. 

Incremental per-gallon cost of NCG (the cost of the last increment of NCG volume) likewise 

increases to about 4¢/gal in Study Case 3. 

Aggregate refinery investments in new process capacity increase progressively with 

increasing NCG share to about $2 billion in Study Case 3. Capital charges and fixed costs 

 

6

Results of the Sensitivity cases are discussed in Section 6. 
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associated with this investment represent slightly less than 20% of total per-gallon costs in 

Study Case 3.

Finally, the proposed NCG program would induce small improvements in the energy density 

of the gasoline pool in Study Cases 2 and 3. This would reduce the national cost of NCG, by 

about 1⁄2¢/gal, but not the refining industry’s costs.

 Table D-2 shows refining operations and, for the Study cases, new capacity additions. 

The 2010 Reference case is configured such that Existing Capacity in Table D-1 includes any 

capacity added by the refinery model (beyond that reported in 2006) to produce the projected 

refinery out-turns and to meet regulatory standards.F

7

F Results returned by the refinery models 

show progressively more (but still relatively small amounts of) new capacity as the NCG 

share of the gasoline pool increases. 

Additional capacity in the Study cases is needed mostly for RVP control (debutanization and 

depentanization). Some minor additions of crude distillation and fractionation capacity also 

are made in Study Cases 2 and 3. Overall, DI control called for no investment in new 

capacity, because of the effects of blending ethanol at 10 vol% on the distillation curves of 

gasoline, notwithstanding the ethanol adjustment factor in the DI equation.

 Tables D-3a and D-3b show estimated refinery inputs and outputs. 

The refinery models are constrained to respond to requirements for progressively increasing 

volumes of NCG by adjusting refinery inputs, capacity, and operations, not by adjusting 

outputs of gasoline and other finished refined products. That is, output volumes of all 

refinery products are fixed, except for certain light gases (propane, butane, and mixed 

C4/C5s). 

The volumes of certain refinery inputs, such as pyrolysis gasoline (an ethylene plant byproduct), ethanol, naphtha, kerosene, heavy gas oil, and residual oil, are held constant across 

the Reference and Study cases. Other inputs, such as crude oil, iso-butane, and normal 

butane, are priced and their volumes are allowed to vary across cases. 

 Tables D-4a, 4b, and 4c shows the estimated average properties of each gasoline type, by 

PADD, in each case, as well as the Complex Model emission reductions for RFG (as 

calculated by the reduced-form of the Complex Model embedded in the refinery model, not 

by the actual Complex Model). 

In the Calibration Case, we adjusted properties of some gasoline blendstocks such that the 

weighted average properties of the gasoline pool closely approximated those estimated from 

the EPA data, as discussed in Section 4. 

 

7 Merchant MTBE plants operating in 2002 are represented in the 2002 Calibration case. No merchant MTBE plants 

are represented in the 2010 Reference and Study cases, but retrofitting refinery-based MTBE units operating in 

PADD 3 in 2006 to alkylate production was allowed. 
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In Study Case 1, the average pool aromatics content and DI increase somewhat for PADD 2, 

but remain about the same for PADDs 2 and 3.F

8

F The (small) effect on gasoline properties 

arising in PADD 1 from augmenting the RFG standards with the NCG standard occurs for 

several reasons. A larger fraction of the gasoline pool is RFG in PADD 1 than in the other 

PADDS, and (as discussed in more detail in Section 8) the NCG sulfur standard would lead 

to reduction in the sulfur content of most of the non-NCG gasoline produced in PADD 1. 

In Study Case 2, there generally are small increases in aromatics and DI, reflecting still 

greater geographic coverage of NCG’s low sulfur and RVP standards (and the loss of the 1 

psi ethanol RVP waiver) as low-RVP gasoline is replaced by NCG. Olefins levels also 

decline due to more extensive treatment of FCC naphtha to reduce the sulfur content of NCG.

In Study Case 3, these trends to increased aromatics content and DI and reduced olefins 

content DI continue as the NCG standard expands to cover all gasoline (except for some 

exports in PADD 3). 

With respect to the 2010 Reference Case, the net effect of full imposition of the NCG 

standard a gasoline is to (1) lower pool average RVP, sulfur, and olefins and (2) raise 

somewhat average aromatics and DI. However, pool average aromatics and DI would 

remain lower than in gasoline produced in 2003/2004, as shown in Exhibit C-2. 

 Tables D-5a, 5b, and 5c show the estimated composition of the various gasoline types 

produced and of the entire gasoline pool. 

The primary changes in the estimated composition of the total gasoline pool are that the 

volume fractions of: (1) C4s decline somewhat (because of RVP control); (2) FCC naphtha 

declines slightly (due to the cost of sulfur control); and (3) medium and heavy reformate 

increases (to make up the octane lost in desulfurizing FCC naphtha to 5 ppm). These 

changes are rather small, but become more noticeable as the share of NCG in the gasoline 

pool expands.

 Table D-6 shows the shadow values (marginal costs) of Complex Model parameters, DI, and 

octane for each gasoline type. Non-zero values in this table for Complex Model parameters 

and DI indicate the limits on specific gasoline properties and on DI that constrain refinery 

operations, i.e., impose additional costs. 

The two Complex Model parameters whose shadow values progressively increase across the 

Study Cases are RVP and benzene. The shadow value of RVP increases because it is 

controlled directly by the NCG standard and the extent of RVP control increases as NCG 

expands its share of the gasoline pool. The shadow value of benzene increases because of 

the indirect effect of the NCG standards on gasoline pool octane. FCC naphtha 

desulfurization, required to achieve the sulfur standard, leads to some octane loss. The lost 

octane is replaced by an increased volume share of reformate, a high-octane blendstock that 

 

8

 In general, the properties shown in Tables 4a, 4b, and 4c and the gasoline compositions in Tables 5a, 5b, and 5c 

may change within Study Cases for individual types of gasolines without affecting the refinery model’s objective 

function, i.e., the refining models may have multiple alternate optima with respect to gasoline properties and 

compositions across different types of gasoline.
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contains benzene. The shadow value on sulfur also would have increased across the Study 

Cases, except for a special modeling procedure that we employed to directly control the 

sulfur content of FCC naphtha and other sulfur-containing blendstocks to 5 ppm or lower. 

Finally, the cost of octane progressively increases because of the octane lost via FCC naphtha 

desulfurization and the reductions in high-octane C4 blendstocks due to RVP control.

 Table D-7 compares the results of the Calibration Case with reported refinery operating data 

for Summer 2002. As discussed earlier, the gasoline pool properties closely match reported 

data, with the exception of aromatics content. With respect to process throughput volumes, 

computed crude throughput and FCC and coker feed rates are within 2% of volumes reported 

by EIA. Reported and modeled hydrocracker feed rates for PADD 3 differ considerably, 

primarily because EIA defines hydrocracking feed to includes volumes fed to lube plants and 

resid hydrocrackers, whereas we include only feed to distillate hydrocrackers. 

The marginal costs of gasoline and distillate production returned in the Calibration Case are 

lower than reported market prices in 2002. However, the marginal costs have the same 

general relationship as market prices, i.e., gasoline marginal costs are higher than distillates, 

etc. In our experience, small changes in process capacity constraints can move the marginal 

cost estimates arbitrarily close to reported prices. We did not pursue making such changes 

because this study focuses not on 2002 but on 2010, a period defined by a different set of 

process capacities and refined product out-turns.
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6. RESULTS OF THE DI SENSITIVITY CASES

As described in Section 1.3, we analyzed a set of refinery modeling cases to assess the effects of 

a more stringent DI standard on the estimated cost of the contemplated NCG program. The 

results of the DI Sensitivity Cases indicated that a DI 1200 standard, rather than DI 1250, would 

affect average refining costs only in the PADD 1 refining sector. Average refining costs in 

PADD 1 would increase by about 0.1¢/gal in Sensitivity Case 1 (relative to Study Case 1), 

1⁄2¢/gal in Sensitivity Case 2, and 1¢/gal in Sensitivity Case 3. Likewise, investments in new 

refining process capacity also increased – by about $0.3 billion and $0.4 billion in Sensitivity 

Cases 2 and 3, respectively, relative to the corresponding Study Cases. 

The lower DI standard would affect the PADD 1 refining sector because the average DI of the 

gasoline pool produced in that PADD is > 1200 in the Study Cases assessing the 1250 DI 

standard. PADD 1 refineries would have to produce a gasoline with average DI below 1200 

(around 1175) in order to insure compliance with a maximum DI of 1200 at the pump. To meet 

the lower DI standard PADD 1 refineries would have to back out heavy, high-octane gasoline 

blendstocks, such as reformate, and replace them with lighter, high-octane blendstocks, mainly 

alkylate and isomerate. The refineries would have to compensate for the resulting RVP increase 

by increasing depentanization. PADDs 2 and 3 produce gasoline pools with average DI below or 

close to the 1175 refinery-gate DI target in the Study Cases, in which NCG has a DI 1250 

standard.

However, results from aggregate refinery modeling, as conducted in this study, can significantly 

understate the effects of imposing the lower DI standard, because of the significant refinery-torefinery variation in average DI of the gasoline pool. Aggregate refinery models represent 

refinery operations in which all blendstocks produced in the region are available for blending in 

all gasoline batches, whereas individual refineries have a smaller pool of blendstocks from which 

to draw. Those refineries having high pool average DI likely would have to modify their 

refining operations, rather than simply trading high-DI blendstocks for low-DI blendstocks from 

another refinery, as is done implicitly in the aggregate refining models.

The chart on the next page shows the distribution of estimated pool average DI, separately for 

RFG and CG (including low-RVP gasoline) produced by individual refineries (ex-California) in 

2004. (The effect on DI of ethanol blending at terminals is not captured in the data underlying 

this chart.) Clearly, significant variation exists in average pool DI across refineries. The higher 

the average DI of a refinery’s current gasoline pool, the higher the likely difficulty and cost of 

the refinery’s meeting a tighter DI standard. 
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Average DI of Gasoline Pool, by Refinery -- 2004

1000

1025

1050

1075

1100

1125

1150

1175

1200

1225

1250

0% 20% 40% 60% 80% 100%

Cumulative Percentage of Gasoline Pool (%)

DI

CG

RFG
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7. RESULTS OF THE CRUDE PRICE SENSITIVITY ANALYSIS

As described in Section 1.3, we conducted a brief analysis to estimate the effects of crude oil 

price on the refining economics of NCG production (with DI capped at 1250). In particular, we 

considered a 2010 crude oil price of $125/Bbl ($2006) in place of the $51.2/Bbl value used in the 

primary analysis.

We conducted this sensitivity analysis using a simple approach that did not involve additional 

refinery modeling. On the basis of historical price series, we estimated average prices for all 

refinery inputs (other than crude oil) and refined products that would be consistent with a crude 

oil price of $125/Bbl. We applied these estimated prices to the refinery input and output 

volumes returned by the refinery model in each Reference Case and Study Case, to obtain the 

indicated cost differentials for each case, with crude oil at $125/Bbl (and commensurate prices 

for purchased electricity and natural gas). For each Study Case, the estimated refining cost of 

the NCG program with crude oil at $125/Bbl is the difference in the gross refining margin 

(GRM)F

9

F plus the difference in purchased energy costs between the Study Case and its Reference 

Case. 

Table D-1b (Appendix D) summarizes the results of this analysis. With crude oil price at 

$125/Bbl ($2006), the estimated average cost of producing NCG (averaged over PADDs 1, 2, 

and 3) at the assumed maximum market coverage – with NCG augmenting all RFG and 

replacing all low-RVP gasoline and CG in the three PADDs – is about 41⁄2¢/gal. In other words, 

increasing the crude oil price from $50/Bbl to $125/Bbl increases the estimated average

refining cost of the NCG program by about 13⁄4¢/gal. Similarly, increasing the crude price 

increases the corresponding average incremental cost for the last increment of NCG introduced 

(to replace CG) to about 61⁄2¢/gal; that is, by about 23⁄4¢/gal (relative to the original Study Cases). 

Table D-1b also indicates that each additional $10/Bbl increase in crude price would increase the 

average refining cost of the NCG program by about 0.24¢/gal (at constant natural gas and 

electricity prices). 

The refining cost of any regulatory program affecting refined product quality – in this instance, 

the contemplated NCG program – is the sum of the changes (relative to a baseline) induced by 

that program in (i) gross refining margin (as defined here), (ii) the cost of refinery energy 

purchases (mainly natural gas and electricity), and (iii) other refinery operating costs (e.g., 

catalysts and chemicals, etc.) plus the capital charges associated with investments in new 

refining capacity called out by the program. Refinery LP modeling, such as we conducted in this 

study, considers all of these factors. The crude price sensitivity analysis that we conducted 

considers only the first and second: the changes in GRM and in the cost of refinery energy 

purchases. 

Because the sensitivity analysis did not involve refinery modeling – an optimization technique 

that identifies minimum cost refining operations – the results of the analysis may embody some 

overstatement of the effect of increasing crude price. In particular, the sensitivity analysis did 

 

9

 Gross refining margin is the total revenue from refined product sales minus the total cost of crude oil and other 

refinery inputs (excluding natural gas and electricity). 
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not consider changes in refinery capital investments (which refinery modeling would have). 

Refinery modeling might have revealed some additional investment called out to partially 

counteract higher energy prices. 
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8. ANALYTICAL ISSUES

Various study assumptions and premises merit discussion and should be considered in assessing 

the results of the refinery modeling.

 The proposed NCG standard has a 10 ppm cap on sulfur content. To meet this limit, 

refineries would have to desulfurize FCC naphtha to U<U 5 ppm. FCC naphtha is usually the 

largest single constituent of a refinery’s gasoline pool (typically comprising about 35% of 

pool volume) and the primary source of sulfur in gasoline (accounting for about 95% of the 

sulfur content of untreated gasoline).

We understand that many of the FCC naphtha treating units that have been or will be 

installed to meet the Tier 2 sulfur standard are capable of producing a treated FCC naphtha 

with sulfur content < 10 ppm. However, some units (particularly retrofitted units) may not 

have this capability and may need an additional treatment stage to achieve the 10 ppm sulfur 

cap contemplated for NCG. Retrofitting an additional treatment stage would entail some 

additional investment. To estimate the potential impact of retrofitting on our cost estimates, 

we postulated that all FCC naphtha hydrotreaters would have to be retrofitted at a cost equal 

to 30% of the estimated grassroots ISBL cost of a new unit (about $1500 K/Bbl/day). This 

investment raises the estimated total investment in new process capacity by about $1.5 billion 

(to a total of about $3 billion) and the estimated cost of fully implementing the NCG standard 

by about 0.2–0.3¢/gal. 

 As noted above, NCG production would entail desulfurizing the FCC naphtha blended to 

NCG to about 5 ppm sulfur. If a refinery opted to produce NCG, it would probably 

desulfurize all of its FCC naphtha to 5 ppm (not just the portion blended to NCG), because of 

constraints on tankage and the difficulty of segregating ultra-low sulfur from low sulfur 

blendstocks. Thus, NCG production could lead to very low sulfur levels in the non-NCG 

gasoline produced by refineries opting to produce some NCG. 

We captured this effect in Study Case 1 by requiring all FCC naphtha produced by RFG 

refineries judged likely to continue producing RFG when NCG is first phased in to be 

desulfurized to 5 ppm and blended in co-produced low-RVP gasoline and CG. (The 

RFG/other gasoline splits in these refineries range from about 40/60 to 60/40). In Study 

Case 2, we assumed that non-RFG refineries producing low-RVP gasoline would produce 

CG in about the same volume (i.e., a 50/50 split), leading to FCC naphtha desulfurization of 

twice the amount necessary solely for low-RVP gasoline. (The exception is for PADD 1, 

where larger coastal RFG refineries also produce the bulk of low-RVP gasoline and where 

we assume that small inland refineries would forego producing low-RVP gasoline as the 

NCG program was phased in). 

This analytical procedure shifts part of the cost of desulfurizing low-RVP gasoline and CG to 

RFG and of desulfurizing CG to low-RVP gasoline as the NCG program is phased in; it does 

not change the cost of fully implementing the NCG standard. It also leads to improvement in 

estimated emissions performance of some low-RVP gasoline and CG during the phase-in of 

NCG by virtue of the early reductions in their sulfur levels.
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 Typically, the investment for expanding existing units is about half to two-thirds of the cost 

of adding the same capacity in grassroots units. The investment costs shown in Table D-6 

reflect grassroots investment economics. We specified grassroots investment economics in 

the Study cases and Sensitivity cases, rather than expansion economics, as a simple means of 

dealing with various investment considerations. 

On one hand, most additional capacity in crude distillation, alkylation, and isomerization 

likely would come about by expansion of existing units, rather than construction of new 

units, and would therefore incur investment costs consistent with expansion economics. On 

the other hand, we did not include any ancillary refining costs that could be incurred to 

control the sulfur content of gasoline blendstocks that need not be treated in order to meet the 

Tier 2 gasoline sulfur standard.F

10

F We assumed in the Reference Case that gasoline 

blendstocks likely to have high sulfur content relative to the Tier 2 standard, such as straight 

run naphtha, coker naphtha, natural gas liquids, and pyrolysis gasoline, would be treated to 

reduce sulfur to low levels (5 ppm or less). In the end, because estimated investment costs 

are low, modifying the procedure to use expansion, rather than grassroots, investment 

economics for some units would have only a minor effect on our cost estimates.

 We allowed DI ―quality shifting‖ to occur from NCG to co-produced low-RVP gasoline and 

CG (i.e., low-RVP gasoline and CG produced by NCG refineries), subject to an arbitrary 

refinery gate, upper limit on DI of 1220. That is, we constrained the DI for other low-RVP 

gasoline and CG to Reference Case levels. Presently, no regulatory mechanism exists to 

prevent quality shifting in response to a NCG standard. 

 As customary, our analysis does not address additional costs incurred downstream of the 

refinery – from the refinery gate to the pump – in moving, storing, and distributing NCG. 

However, we think any such costs would be low because NCG would replace existing 

gasoline types and, under EPAct2005, could not lead to an increase in the number of distinct 

gasoline types in commerce. 

 Capital charges in the refinery model and in the cost analysis reflect a rate of return on 

investment of 10%. EPA uses lower rates of return when estimating the ―social‖ (national) 

costs of regulations; refiners often use higher rates of return when evaluating refinery 

investment opportunities.

 

10 Ancillary refining costs are refining costs that are not registered in the refinery model, such as those discussed 

here that refineries may incur in meeting a 5 ppm sulfur standard. Refinery LP models do not register ancillary 

costs not because they are imaginary, but because it is hard to express them as explicit functions of refinery 

operating variables. 
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9. COMMENTS ON STUDY RESULTS AND FINDINGS

9.1 Magnitude of the Estimated Average and Incremental Costs

Averaged over PADDs 1, 2, and 3, the estimated average cost of producing NCG at the assumed 

maximum market coverage – that is, with NCG augmenting/replacing all RFG, low-RVP 

gasoline, and CG in the three PADDs – is about 3¢/gal of NCG (for a crude oil price of $51 

($2006)). The corresponding estimated incremental cost for the last increment of NCG at 

maximum market coverage (that is, replacing CG) is about 4¢/gal. (Table D-1)

To provide some perspective for these estimates, note that the estimated average and incremental

refining costs are in the same range as most corresponding estimates for federal Phase 1 RFG, 

prior to its implementation in 1995. After implementation, and prior to the institution of state 

MTBE bans, spot price differentials between CG and federal RFG usually were usually in the 

range of 2¢ to 4¢/gal, except in periods of temporary supply disruption. The estimated refining 

costs for NCG are below estimates of the cost of the California MTBE ban, prior to its 

implementation in 2004, and of the cost of a national MTBE ban. 

In summary, the results of the analysis indicate that NCG would be a relatively costly gasoline 

program, but not necessarily more costly than some other gasoline programs that U.S. consumers 

have accepted. 

This finding applies over the entire range of crude oil prices considered in this study. (Note that 

the estimated refining costs indicated by the crude price sensitivity analysis (Section 7) are not 

directly comparable to the results obtained in any prior studies of proposed regulatory standards 

affecting gasoline, because all prior studies incorporated crude prices very much lower than 

$125/Bbl.) 

9.2 NCG Costs Depend on Phase-In Sequence

Except for the average refining cost at full market coverage, the average and incremental refining 

costs of NCG would be a function of its phase-in sequence (that is, the sequence in which other 

gasoline types would be augmented/replaced by NCG). In particular, the estimated costs shown 

in Table D-7 apply only to the assumed phase-in sequence: RFG first, low-RVP gasoline second, 

and CG third, simultaneously in all PADDs. 

Other sequences, with or without regional variations, would lead to different cost progressions 

for NCG’s introduction, but the average cost of the NCG program at full market coverage would 

be unaffected by the phase-in sequence.

9.3 Capabilities of Foreign Refiners to Produce NCG Were Not Considered

We project imports of finished gasoline and blending components to constitute more than 12% of 

total U.S. gasoline supply in 2010. Most gasoline imports come into PADD 1, where imports 

constitute about 31% of total gasoline supply (including inter-regional transfers from PADD 3). 
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Imports of gasoline into PADD 1 in 2010 will be in the form of blendstocks (CBOBs, RBOBs, 

etc.) subsequently blended with ethanol at 10 volume% to make finished gasoline. A handful of 

refineries in eastern Canada, the Virgin Islands, and Venezuela are consistent suppliers, 

accounting for most of PADD 1’s gasoline imports. The rest of the imports come from 

―opportunity‖ suppliers, refineries in northern Europe, Africa, the Middle East, and Asia. 

An important assumption in the analysis was that gasoline production in each PADD of interest 

would remain unchanged with the introduction of NCG. This assumption implies that (1) the 

total volume of gasoline imports would remain unchanged with the introduction of NCG and (2) 

imported low-RVP gasoline and CG would be replaced by imported NCG in step with the shift 

in domestic gasoline production. 

We assumed that foreign refineries, collectively, would supply the indicated amounts of NCG 

imports, and do so at delivered prices consistent with the marginal production costs of the U.S. 

refining sector. In practice, that may or may not be the case. However, analysis of the 

capabilities and economics of foreign suppliers is far beyond the scope of this study. 

9.4 Other Factors Could Affect Refining Costs of NCG

As noted in Section 8, many FCC naphtha desulfurization units installed to meet the Tier 2 sulfur 

standard already have the capability of desulfurizing FCC naphtha to the extent needed to 

produce gasoline containing U<U 10 ppm sulfur. However, some units (particularly retrofitted 

units) may not have this capability. They would require some additional investment in order to 

achieve the NCG sulfur standard. 

Meeting the NCG sulfur standard could also require desulfurization of other gasoline blendstocks 

that (unlike FCC naphtha) did not require treatment to meet the Tier 2 gasoline sulfur standard 

(30 ppm average). We did not attempt to capture these investments in the Study Cases and 

Sensitivity Cases. Rather, we assumed that these desulfurization costs were embodied in the 

Reference Case, in which total refining capacity includes the process capacity installed to meet 

the Tier 2 gasoline sulfur standard. Hence, the results of the analysis do not reflect the costs that 

would be incurred if some refineries had to install new desulfurization capacity expressly to 

produce NCG in the specified volumes. 

9.5 Logistics System Effects Were Not Considered 

Consistent with the ground-rules established for the study, we did not consider the technical and 

economic effects of an NCG program on the gasoline distribution system, from the refinery to 

the pump. 

These effects would likely be minimal. As EPAct2005 dictates, NCG would have to replace 

another gasoline type at each step of the phase-in, and NCG could not lead to any increase in the 

number of distinct gasolines in commerce in the U.S.F

11

F During periods of supply shortfall or 

supply interruption, the widespread use of a standard NCG would tend to enhance the 

 

11 The assumed phase-in sequence satisfies the EPAct2005 requirements in PADDs 1, 2, and 3. For purposes of this 

study, we ignored the small volumes of low-RVP gasolines currently used in PADD 4. 
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distribution system’s flexibility in responding and mitigating the price spikes that often occur in 

such situations.

9.6 Aggregate Refinery Modeling and Possible Over-Optimization

We conducted the refinery modeling using regional aggregate refining models. Such models 

essentially pool all regional refining capacity and intermediate and final gasoline blendstocks, as 

though all refining capacity in the region were fully integration. Consequently, all aggregate 

refining models have a tendency to ―over-optimize‖ – that is, to return operating results better 

than the refining sector could achieve in practice under the conditions represented in the models. 

The results returned by the PADD-level refining models in this analysis may embody some overoptimization in representing the phase-in of NCG – most notably with respect to quality shifting. 

An aggregate model can practice quality shifting among gasoline types to a greater extent than 

can individual refineries. As noted in Section 8, quality shifting from NCG to other gasoline 

types would, directionally, reduce the cost of NCG production but impair emissions performance

of the gasoline types that were the ―quality sinks.‖ In practice, as NCG phased in, some 

refineries might produce NCG and others might not, further limiting the extent to which quality 

shifting could occur. 
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APPENDIX

Table A-1: Petroleum Refining Capacity for PADDs 1-3, 2002 & 2006

(K b/calendar day, except as noted)

Type of 2002 2006

Process Process PADD 1 PADD 2 PADD 3 1 2 3

Crude Distillation Atmospheric 1,586 3,508 7,684 1,589 3,554 8,390

Vacuum 613 1,420 3,527 638 1,503 3,815

Conversion Coking

 Delayed 44 358 1,074 44 358 1,168

 Fluid 47 14 47 16 63

 Other 38 39

Fluid Cat Cracking 685 1,175 2,818 692 1,165 2,937

Hydrocracking

 Distillate 116 406 160 575

 Resid 18 245 39 102

 Lube 38 46

 Other 20 37 73 33

Visbreaking 12

Thermal Cracking 10

Upgrading Alkylation 85 245 545 97 251 581

Pen/Hex Isomerization 17 157 229 17 172 233

Reforming 285 840 1,699 294 840 1,718

Polymerization 18 5 17 18 5 15

Dimersol 3 4 3 7

Ether Production MTBE 7 9 73 3 4 27

TAME 2 0 12 3

Hydrotreating Naphtha Feed 342 1,002 1,847 348 1,035 2,238

Naphtha/Aromatics Sat. 10 10 11

FCC Naphtha 67 22 77 324 332 1,083

Kerosene & Distillate 381 863 1,979 479 1,067 2,213

Distillate/Aromatics Sat. 171 344 581 18 26

FCC Feed/Heavy Gas Oil 89 476 1,121 44 524 1,279

Resid 224 10 316

Lube Oil 1 27 73 1 24 89

Other 14 12 127 16 3 224

Other BTX Plant 41 48 189 41 50 233

Other Aromatics 12 8 50 12 8 46

Butane Isomerization 22 26 108 38 24 109

Hydrogen (MM scf/d)1

99 425 1,508 112 795 1,653

Lube Oil 19 17 138 19 17 148

Solvent Deasphalting 19 16 200 20 16 200

Coke (K t/d) 4 18 63 5 20 70

Sulfur Recovery (K Sh t/d) 1.3 4.7 16.2 1.3 5.2 19.4

Asphalt 28 231 125 28 245 125

Complexity 8.4 9.3 10.5 9.0 9.7 10.5

1 Includes production and recovery.

Sources: Capacity derived from 2002 & 2006 "Worldwide Refinery Surveys," Oil & Gas Journal , Dec. 23,

 2002 & Dec. 18, 2006; and DOE 2002 & 2006 Refinery Capacity Surveys (DOE Website).

 Complexity: Derived using Generalized Complexity Index Scores from Oil & Gas Journal , March 18, 1996, p. 74-80.
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Table A-2a: Refinery Inputs, Process Feeds & Crude Oil

Properties, by PADD, 2002

(K b/d)

Summer 

PADDs 4&5

Inputs PADD 1 PADD 2 PADD 3 PADD 4 PADD 5 ex Calif. California U.S.

Refinery Inputs: 1,946 3,499 7,772 563 2,936 1,534 1,964 16,716

Crude Oil 1,588 3,371 7,147 530 2,665 1,406 1,790 15,301

Natural Gas Liquids 3 80 248 13 62 66 10 407

 Pentanes Plus 42 139 4 25 29 211

 Liquified Petroleum Gases 3 38 109 9 37 37 10 196

 Ethane

 Propane

 Normal Butane 0 4 34 4 24 24 4 66

 Isobutane 3 34 74 5 13 13 6 130

Other Liquids 888 346 617 16 225 76 164 1,641

 Other Hydrocarbons/H2/Oxy 73 43 127 3 138 36 105 385

 Other Hydrocarbons/H2 2 31 1 28 29 61

 Oxygenates1

73 42 97 2 110 7 105 324

 Fuel Ethanol w 38 w w w w 9 50

 Methanol w w w w w w 0

 MTBE 69 w 93 w 100 w 96 266

 Other w w w w w w 7

 Unfinished Oils -- Total 77 33 374 4 38 4 38 526

 Naphtha 1 30

 Kerosene 0 2

 Gas Oils 69 232

 Residuum 7 110

 Motor Gasoline Blend. Comp. 332 135 -129 4 24 7 22 366

 Input to Refinery/Blenders 208 -28 -125 12 32 22 22 99

 Input to Field Blending2

124 163 -5 -8 -7 -15 267

 Aviation Gasoline Blend. Comp. -3 0 0 -3

 Est. Ethanol in Field-Blnd Gas 5 46 3 4 7 11 0 66

Process Feeds

 Catalytic Cracking 586 1,169 2,743 138 768 - - 5,404

 Catalytic Hydrocracking3

39 142 599 3 483 - - 1,266

 Delayed and Fluid Coking 77 328 1,001 39 512 - - 1,958

Crude Oil Properties

 Sulfur Content (wtg avg %) 0.88 1.30 1.63 1.41 1.21 1.15 1.58 1.40

 API Gravity (degrees) 31.7 32.8 29.7 33.0 27.5 30.7 23.7 30.3

 Specific Gravity 0.867 0.861 0.878 0.860 0.890 0.872 0.912 0.875

Note: "w" indicates data have been withheld

1 Does not include ethanol not otherwise reported by refineries.

2 Negative number indicates field production.

3 Includes feed to resid and lube hydrocrackers.

Sources: Derived from Tables 16, & 22-25, Petroleum Supply Annual 2002,

 DOE/EIA; Tables 2-23 & 28, 2002 Petroleum Supply Monthlys,

 DOE/EIA; CEC Weekly Refinery Reports; and Table A-7a.
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Table A-2b: Refinery Net Production, by PADD, 2002

(K b/d)

Summer 

PADDs 4&5

Products PADD 1 PADD 2 PADD 3 PADD 4 PADD 5 ex Calif. California U.S.

Refinery Outputs: 2,081 3,729 7,889 547 2,865 1,413 1,999 17,112

Liquified Refinery Gases 115 276 864 17 150 94 72 1,423

 Ethane/Ethylene 24 24

 Ethane 17 17

 Ethylene 7 7

 Propane/Propylene 48 116 356 8 56 25 40 585

 Propane 31 82 178 8 56 25 40 355

 Propylene 17 34 178 0 229

 Normal Butane/Butylene 24 46 118 2 34 7 30 224

 Normal Butane 22 44 111 2 32 7 28 211

 Buytlene 1 3 7 0 2 0 2 13

 Isobutane/Isobutylene -4 -3 11 -2 3 -2 3 5

 Isobutane -3 -2 8 -1 2 -1 2 4

 Isobutylene -1 -1 3 -1 1 -1 1 1

Finished Petroleum Products 1,966 3,453 7,024 531 2,715 1,319 1,927 15,689

 Finished Motor gasoline 1,155 2,058 3,658 279 1,499 614 1,164 8,649

 Reformulated 610 339 662 1,086 37 1,048 2,697

 Oxygenated 11 183 1 12 6 17 0 213

 Other 404 1,327 2,996 271 408 564 115 5,406

 Field Oxygenated 53 460 33 39 72 112 657

 Field Other 77 -251 -34 -43 -72 -116 -324

 Finished Aviation Gasoline 0 5 10 0 3 1 2 18

 Jet Fuel 87 220 757 25 433 189 269 1,521

 Naphtha-Type 0 0 0

 Kerosene-Type 87 220 757 25 433 189 269 1,521

 Kerosene 11 5 25 0 4 4 44

 Distillate Fuel Oil 466 850 1,635 159 507 339 327 3,617

 CARB Diesel 210 210

 0.05 % sulfur & under 261 654 1,180 131 200 216 116 2,637

 Greater than 0.05 % sulfur 206 195 455 28 97 124 1 980

 Residual Fuel Oil 89 57 260 11 160 91 80 577

 Less than 0.31 % sulfur 40 22 1 6 4 3 70

 0.31 to 1.00 % sulfur 41 8 31 2 53 28 26 134

 Greater than 1.00 % sulfur 7 49 207 8 102 58 51 372

 Naphtha to Petrochemical 16 21 205 3 3 0 246

 Other Oils to Petrochemical 0 137 1 8 1 8 146

 Special Naphthas 2 17 29 1 0 2 50

 Lubricants 17 15 124 24 0 24 180

 Waxes 1 4 11 3 5 -2 17

 Petroleum Coke 48 138 423 17 160 31 146 786

 Marketable 18 89 305 9 121 15 116 542

 Catalyst 31 49 118 7 39 16 30 244

 Asphalt and Road Oil 121 190 132 52 64 70 46 560

 Still Gas 67 137 329 21 152 56 117 706

 Miscellaneous Products 1 12 41 2 7 1 8 63

Note: Refinery Outputs and Finished Petroleum Products exclude petroleum

 coke and still gas. 

Sources: Derived from Tables 17, Petroleum Supply Annual 2002,

 DOE/EIA; and Tables 2-23 & 29, Petroleum Supply Monthly,

 Feb. 2003, DOE/EIA; and CEC Weekly Refinery Reports.
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Table A-3a: Allocation of Annual Gasoline Use by Region, State, 

and Gasoline Type, 2002

(K b/d)

Gasoline Type

EtOH California RFG

Region Conven- Mandate Low RVP Areas Federal Federal State Arizona

& State tional (Minn.) 7.8 7.2 7.0 RFG Area Area CBG Total

PADD 1 1,346 0 446 0 170 1,184 0 0 0 3,146

Subdistrict 1A 54 0 28 0 0 330 0 0 0 413

Connecticut 98 98

Maine 19 28 47

Massachusetts 176 176

New Hampshire 13 32 45

Rhode Island 25 25

Vermont 23 23

Subdistrict 1B 361 0 72 0 0 720 0 0 0 1,153

Delaware 26 26

District of Columbia 10 10

Maryland 18 141 159

New Jersey 252 252

New York 166 201 367

Pennsylvania 177 72 88 337

Subdistrict 1C 931 0 346 0 170 134 0 0 0 1,580

Florida 269 253 522

Georgia 154 170 324

North Carolina 189 93 282

South Carolina 153 153

Virginia 112 134 246

West Virginia 54 54

PADD 2 1,653 178 269 17 58 362 0 0 0 2,536

Illinois 113 17 207 338

Indiana 176 6 26 208

Iowa 105 105

Kansas 62 18 80

Kentucky 106 35 140

Michigan 172 166 337

Minnesota 178 178

Missouri 118 40 48 206

Nebraska 58 58

North Dakota 24 24

Ohio 345 345

Oklahoma 90 27 117

South Dakota 30 30

Tennessee 131 70 202

Wisconsin 122 46 168

PADD 3 615 0 353 0 59 283 0 0 0 1,310

Alabama 139 31 170

Arkansas 95 95

Louisiana 74 78 152

Mississippi 106 106

New Mexico 62 62

Texas 140 275 28 283 726

PADDs 4 & 5 ex CA 471 0 289 0 0 0 0 0 99 859

Alaska 17 17

Arizona 71 99 170

Colorado 61 76 138

Hawaii 29 29

Idaho 38 38

Montana 29 29

Nevada1

57 12 69

Oregon 53 52 105

Utah 14 46 60

Washington 82 102 184

Wyoming 20 20

CALIFORNIA 731 267 998

UNITED STATES 4,085 178 1,357 17 287 1,829 731 267 99 8,849

1 Nevada reports a small volume of RFG sales. We assume this is spillover of CaRFG and report it as State Area CaRFG.

Note: Gasoline is classified by the area into which it is sold. Volumes reflect year-long (annual, rather than seasonal)
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Table A-3b: Estimated Annual Gasoline Use and Supply Sources,

by Region and Type of Gasoline, 2002

(K b/d)

Gasoline Type 

EtOH Low RVP California RFG

Region of Use & Conven- Mandate Areas Federal Federal State Arizona

Origin of Supply tional (Minn.) 7.8 7.01 RFG Area Area CBG Total

Use in PADD 1 1,346 446 170 1,184 3,146

PADD 1 Refineries 212 72 637 921

PADD 2 Refineries 23 23

PADD 3 Refineries 907 346 170 320 1,742

Net Imports 204 28 227 459

Use in Subdistrict 1A 54 28 330 413

PADD 1 Refineries 40 0 154 194

PADD 3 Refineries 0

Net Imports 15 28 176 219

Use in Subdistrict 1B 361 72 720 1,153

PADD 1 Refineries 152 72 474 698

PADD 2 Refineries 23 23

PADD 3 Refineries 132 198 330

Net Imports 53 48 101

Use in Subdistrict 1C 931 346 170 134 1,580

PADD 1 Refineries 20 9 29

PADD 3 Refineries 775 346 170 122 1,412

Net Imports 136 3 139

Use in PADD 2 1,653 178 269 75 362 2,536

PADD 1 Refineries 202 202

PADD 2 Refineries 1,206 178 193 46 318 1,940

PADD 3 Refineries 223 76 29 44 372

PADD 4 Refineries 19 19

Net Imports 2 2

Use in PADD 3 615 353 59 283 1,310

PADD 2 Refineries 18 17 35

PADD 3 Refineries 691 353 59 270 1,373

Net Imports -94 -4 -98

Use in PADDs 4 & 5 ex CA 471 289 99 859

PADD 2 Refineries 24 24

PADD 3 Refineries -- direct 37 29 21 86

 -- via Calif 8 8

PADD 4 & 5 (ex CA) Ref. 312 248 560

California Refineries 84 12 78 174

Net Imports 6 6

Use in California 0 731 267 998

PADD 4 & 5 (ex CA) Ref. 22 22

California Refineries 2 705 267 975

Net Imports -2 4 2

TOTAL USE 4,085 178 1,357 303 1,829 731 267 99 8,849

Refinery Production 3,969 178 1,329 303 1,606 727 267 99 8,478

PADD 1 414 72 637 1,124

PADD 2 1,272 178 193 46 334 2,023

PADD 3 1,866 804 257 634 21 3,582

PADDs 4 & 5 ex CA 331 248 22 601

California 86 12 705 267 78 1,149

Net Imports 116 28 223 4 371

1 Includes small volume (14 K b/d) of gasoline sold to an area in PADD 2 with an RVP limit of 7.2 psi.

Source: Derived from Table A-3a and Petroleum Supply Annual, 2002 .
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Table A-3c: Estimated Gasoline Production Volume, RVP, and

Octane, by Type of Gasoline, Destination, and Region

2002

Producing Region, Production Pool

Type of Gasoline, & Annual Share Summer Winter RVP Grade Splits Octane

Destination (K b/d) (%) (K b/d) (K b/d) Summer Winter Reg Prem (R+M)/2

PADD 1 Refineries 1,124 100.0% 1,129 1,117 7.6 14.1 82% 18% 87.9

Conventional 414 36.9% 407 425 8.7 14.0 84% 16% 87.8

 Subdistrict 1A 40 39 41 8.7 14.3 84% 16%

 Subdistrict 1B 152 150 156 8.7 14.2 79% 21%

 Subdistrict 1C 20 20 21 8.7 13.0 80% 20%

 PADD 2 202 198 207 8.7 13.8 87% 13%

7.8 RVP Areas 72 6.4% 71 74 7.6 14.2 79% 21% 88.0

 Subdistrict 1A 0 0 0 7.6 14.3 84% 16%

 Subdistrict 1B 72 71 74 7.6 14.2 79% 21%

 PADD 2 7.6 13.8 87% 13%

RFG 637 56.7% 651 618 6.8 14.2 80% 20% 88.0

 Subdistrict 1A 154 158 150 6.8 14.3 84% 16%

 Subdistrict 1B 474 484 459 6.8 14.2 79% 21%

 Subdistrict 1C 9 9 9 6.8 13.0 80% 20%

PADD 2 Refineries 2,023 100.0% 2,059 1,991 8.2 13.8 87% 13% 87.6

Conventional 1,449 71.7% 1,474 1,428 8.7 13.8 87% 13% 87.6

 PADD 1 23 24 23 8.7 14.2 79% 21%

 EtOH Mandate (Minnesota) 178 181 175 8.7 13.8 87% 13%

 PADD 2 other 1,206 1,227 1,189 8.7 13.8 87% 13%

 PADD 3 18 19 18 8.7 12.6 85% 15%

 PADDs 4&5 ex CA 24 25 24 8.7 13.0 83% 17%

7.8 RVP Areas 193 9.5% 196 190 7.6 13.8 87% 13% 87.6

7.0 RVP Areas1 46 2.3% 47 45 6.8 13.8 87% 13% 87.6

RFG 334 16.5% 342 328 6.8 13.7 87% 13% 87.6

 PADD 2 318 325 312 6.8 13.8 87% 13%

 PADD 3 17 17 16 6.8 12.6 85% 15%

PADD 3 Refineries 3,582 100.0% 3,649 3,525 8.0 13.0 83% 17% 87.9

Conventional 1,866 52.1% 1,901 1,836 8.7 13.0 83% 17% 87.9

 Subdistrict 1B 132 135 130 8.7 14.2 79% 21%

 Subdistrict 1C 775 789 762 8.7 13.0 80% 20%

 PADD 2 223 227 220 8.7 13.8 87% 13%

 PADD 3 597 608 587 8.7 12.6 85% 15%

 PADDs 4&5 ex CA 45 46 44 8.7 13.0 83% 17%

 Net Exports 94 96 93 8.7 12.6 85% 15%

7.8 RVPAreas 804 22.4% 819 791 7.6 12.9 83% 17% 87.9

 Subdistrict 1B

 Subdistrict 1C 346 352 340 7.6 13.0 80% 20%

 PADD 2 76 77 75 7.6 13.8 87% 13%

 PADD 3 353 360 347 7.6 12.6 85% 15%

 PADDs 4&5 ex CA 29 29 28 7.6 13.0 83% 17%

7.0 RVP Areas 257 7.2% 262 253 6.8 13.0 82% 18% 87.9

 Subdistrict 1C 170 173 167 6.8 13.0 80% 20%

 PADD 2 29 30 29 6.8 13.8 87% 13%

 PADD 3 59 60 58 6.8 12.6 85% 15%

RFG 634 17.7% 646 625 6.8 13.2 82% 18% 87.9

 Subdistrict 1B 198 202 195 6.8 14.2 79% 21%

 Subdistrict 1C 122 124 120 6.8 13.0 80% 20%

 PADD 2 44 45 44 6.8 13.8 87% 13%

 PADD 3 266 271 262 6.8 12.6 85% 15%

 Net Exports 4 4 4 6.8 13.0 85% 15%

Arizona CBG 21 0.6% 21 20 6.8 11.4 83% 17% 87.8

PADDs 4 & 5 ex CA Refineries 601 100.0% 613 592 8.2 13.0 83% 17% 87.8

Conventional 331 55.1% 329 332 8.7 13.0 83% 17% 87.4

7.8 RVP 248 41.2% 247 249 7.6 13.0 83% 17% 87.4

California RFG 22 3.7% 37 12 6.8 12.6 80% 20% 88.0

California Refineries 1,149 100.0% 1,184 1,117 7.0 12.5 81% 19% 88.0

Conventional 86 7.5% 103 72 8.7 13.0 83% 17% 87.8

 PADDs 4&5 ex CA 84 100 70 8.7 13.0 83% 17%

 Net Exports 2 2 2 8.7 12.5 80% 20%

7.8 RVP Areas 12 1.1% 14 10 7.6 13.0 83% 17% 87.8

California RFG 973 84.7% 974 969 6.8 12.5 80% 20% 88.0

Arizona CBG 78 6.8% 93 65 6.8 11.4 83% 17% 87.8

TOTAL U.S. 8,478 100.0% 8,634 8,342 7.9 13.3 83% 17% 87.8

Conventional 4,146 48.9% 4,214 4,093 8.7 13.4 84.4% 15.6% 87.7

7.8 RVPAreas 1,329 15.7% 1,347 1,314 7.6 13.1 83.4% 16.6% 87.7

7.0 RVP Areas 303 3.6% 309 299 6.8 13.1 82.7% 17.3% 87.9

RFG 1,606 18.9% 1,639 1,570 6.8 13.7 82.4% 17.4% 87.9

California RFG 995 11.7% 1,011 981 6.8 12.5 80.1% 19.9% 88.0

Arizona CBG 99 1.2% 114 85 6.8 11.4 83.3% 16.7% 87.8
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Table A-3d: Estimated Gasoline Blendstock Use, 2002

(K b/d)

Source & Annual

Area of Use Average Summer Winter

Gulf Coast to: 152 149 155

PADD 1 3 7

PADD 2 123 134 114

PADDs 4&5 ex CA 19 1 35

California 7 8 6

Puget Sound to:

California1

7 8 6

Imports to: 321 365 277

PADD 1 284 313 252

PADD 3 24 37 14

PADDs 4&5 ex CA 2 1 3

California 11 14 8

Note: Imported GTAB contains little, if any, oxygenates, based on refinery production of

 finished gasoline, oxygen content of RFG and CG, and volume of purchased oxygenates

1 Assumed volume of intra-PADD shipments, not accounted for elsewhere.

Sources: Derived from Petroleum Supply Annual, 2002 and DOE Company-Level Import Data.
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Table A-4a: Crude Oil, Electricity, and Natural Gas

Prices, 2002 and Projected 2010

($ 2004)

2002 20105 6

Crude Oil ($/b)1

25.21 50.41

PADD 1 26.08 51.28

PADD 2 26.42 51.62

PADD 3 24.93 50.13

Electricity (¢/Kwh)3

5.1 6.0

PADD 1 6.9 7.8

PADD 2 4.5 5.4

PADD 3 4.7 5.6

Natural Gas ($/mcf)3

4.18 6.64

PADD 1 5.89 8.35

PADD 2 5.31 7.77

PADD 3 3.76 6.22

Natural Gas ($/foeb)3 4 26.33 41.81

PADD 1 37.11 52.59

PADD 2 33.46 48.94

PADD 3 23.69 39.17

AEO Prices

World Oil ($/b)

 All Imported Crudes 24.62 49.82

 Imported low Sulfur Light Crude 55.93

 Electricity to Industrial

 Customers (¢/Kwh) 5.1 6.0

Natural Gas ($/mcf)

 Wellhead 3.07 5.60

 Industrial 4.12 6.64

1 Refiner acquisition cost of domestic and imported crude oil.

2 Acquisition cost reported for PADD 4 is assumed for PADDs 4&5 ex CA.

3 Prices to industrial customers.

4 Assumes 6.3 mcf per foeb.

5 Projected regional prices for crude oil estimated as 2012 projected U.S. price plus the 2004

 regional price deltas.

6 Projected regional prices for electricity and natural gas estimated as the projected

 U.S. price plus average regional price deltas estimated over the period 2001 - 2004.

Sources: Derived from:

 Table 1A, Petroleum Marketing Annual 2004 , EIA/DOE;

 Tables 1, 8, & 13, "Yearly Tables," Annual Energy Outlook 2006, Early Release;

 Table 36, Petroleum Supply Annual, 2004, EIA/DOE;

 Figure 7.7, Electric Power Annuals, 2001 to 2004, EIA/DOE;

 Table 32, Historical Natural Gas Annual 1930 through 1999; and

 Tables 23 & 24, Natural Gas Annuals 2000 to 2004 , EIA/DOE.
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Table A-4b: Crude Oil Acquisition Costs and

Product Prices for Refinery Modeling,

Summer 2002 & Projected 2010

($/b, $2004)

Region and Product 2002 2010

Crude Oil Acquisition Costs

PADD 1 26.08 51.28

PADD 2 26.42 51.62

PADD 3 24.93 50.13

Prices for Refinery Modeling

PADD 1

 Propane 21.79 38.30

 Normal Butane 24.46 41.08

 Iso-butane 24.86 41.47

 Residual Oil: 1 wt% Sulfur 19.50 38.33

PADD 2

 Propane 19.74 37.31

 Normal Butane 24.78 41.35

 Iso-butane 25.18 41.74

 Residual Oil > 3.5 wt% Sulfur 19.75 38.59

PADD 3

 Propane 17.90 39.72

 Normal Butane 23.39 43.21

 Iso-butane 23.79 43.75

 Residual Oil: 1 wt% Sulfur 18.64 37.47

Source:

Crude Oil Prices: Table A-4a.

Other Prices: MathPro projections and ARMS modeling results.
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Refining Economics

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Table A-5: Annual Supply of Major Refined Products,

by PADD

(K b/d)

2002

PADD PDs 4&5 U.S.

Product/Source 1 2 3 ex Calif Calif Total

Gasoline 3,146 2,536 1,309 676 1,180 8,848

Refinery (& Field) Production 1,120 2,023 3,581 601 1,149 8,474

 Net Blndstk Purchases 277 123 -148 12 18 282

 Ref Production - Blndstk Pur 843 1,900 3,729 589 1,131 8,192

Net Imports 463 2 -98 6 1 374

Net Inter-PADD Shipments 1,564 511 -2,174 69 30 0

Jet Fuel & Kerosene 578 333 207 233 305 1,657

Refinery Production 99 228 800 189 262 1,578

Net Imports 49 0 -17 10 37 79

Net Inter-PADD Shipments 430 105 -577 35 7 0

Distillate Fuel Oil 1,356 1,101 680 333 307 3,776

Refinery Production 478 829 1,665 333 316 3,621

Net Imports 240 6 -67 -14 -10 155

Net Inter-PADD Shipments 638 266 -918 14 0 0

Residual Oil 288 47 193 108 64 700

Refinery Production 108 58 289 92 81 628

Net Imports 174 -1 -101 16 -17 72

Net Inter-PADD Shipments 7 -11 4 0 0

All Major Products 5,368 4,017 2,389 1,350 1,856 14,980

Refinery Production 1,805 3,138 6,336 1,215 1,808 14,300

Net Imports 926 8 -282 17 12 680

Net Inter-PADD Shipments 2,637 872 -3,665 119 37 0

Notes: Refinery production adjusted to include stock changes.

 California includes refined products produced in California but sold in adjacent states

 (e.g., Arizona & Nevada)

Source: Derived from Tables 2-23, Petroleum Supply Monthly, Feb. 2003, EIA/DOE.

 Weekly Refinery Fuels Reports for 2002, California Energy Commission Website.
National Clean Gasoline

Refining Economics

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Alliance of Automobile Manufacturers June 2009

Table B-1:Petroleum Supply and Disposition -- Historical 2000-2005 and

AEO 2007 Reference Case Forecast for 2010

(K b/d, except as noted)

AEO Projected Growth

Historical Forecast 2004-2010

Supply & Disposition 2000 2001 2002 2003 2004 2005 2010 Cumulative Annual

Crude Oil Supply 14,840 15,050 14,880 15,340 15,529 15,271 15,659 0.8% 0.1%

Domestic 5,820 5,740 5,740 5,690 5,468 5,178 5,665 3.6% 0.6%

 Alaska 970 960 980 990 910 864 689 -24.3% -4.5%

 Lower 48 4,850 4,780 4,750 4,710 4,558 4,314 4,977 9.2% 1.5%

Net Imports 9,020 9,310 9,140 9,650 10,061 10,093 9,994 -0.7% -0.1%

Liquids from Natural Gas Plants 1,910 1,870 1,880 1,720 1,809 1,717 1,801 -0.5% -0.1%

Other Inputs1

350 300 670 440 341 389 1,018 198.4% 20.0%

Ethanol 221 255 692 213.3% 21.0%

Liquids from Coal 0 0 0 - - 

Other 120 134 326 170.9% 18.1%

Net Product Imports 1,400 1,590 1,420 1,640 2,098 2,508 1,797 -14.3% -2.5%

Imports 2,390 2,540 2,390 2,600 3,057 3,578 3,025 -1.0% -0.2%

 Gross Refined Products 2

2,040 2,080 1,610 1,850 2,069 2,449 1,781 -13.9% -2.5%

 Unfinished Oils 270 380 410 340 490 582 409 -16.5% -3.0%

 Ethers 80 80

 Ethanol 10 7 19 97.1% 12.0%

 Gasoline Blending Components 3

370 410 488 540 816 67.2% 8.9%

Exports 990 950 970 960 959 1,070 1,228 28.1% 4.2%

Refined Petroleum Products Supplied 19,750 19,710 19,700 20,060 20,760 20,750 21,589 4.0% 0.7%

LPG 2,231 2,044 2,163 2,074 2,132 2,030 2,218 4.0% 0.7%

E85 0 0 0 0 0 0 2 - - 

Motor Gasoline4

8,500 8,620 8,850 8,940 9,105 9,159 9,531 4.7% 0.8%

Jet Fuel 1,730 1,660 1,610 1,580 1,630 1,679 1,954 19.9% 3.1%

Distillate Fuel & Kerosene 3,670 3,880 3,790 3,930 4,058 4,118 4,532 11.7% 1.9%

Residual Oil 1,050 860 700 770 865 920 786 -9.2% -1.6%

Other5

2,569 2,646 2,587 2,766 2,970 2,844 2,568 -13.5% -2.4%

Energy Prices ($2004)

Crude Oil ($/b)

 All Imported Crudes 30.00 23.51 24.62 28.46 36.09 47.87 49.82

 Imported Low Sulfur Light Crudes 41.72 55.24 55.93

Natural Gas ($/mcf)

 Lower 48 Wellhead 3.90 4.35 3.07 5.08 5.64 7.31 5.60

 Industrial End-Use 4.79 5.28 4.00 5.77 6.68 8.43 6.63

Electricity, Industrial End-Use (¢/Kwh) 5.0 5.1 5.2 5.3 5.3 5.5 6.0

Domestic Refining

Crude Distillation Capacity (K b/d) 16,600 16,800 16,800 16,800 16,947 17,126 17,822

Capacity Utilization (%) 93.0 93.0 91.0 93.0 93.0 91.0 89.1

Note: Projected growth rates are calculated using 2004 as the base year because of the impact of hurricane Katrina in 2005.

1 Includes alcohols, ethers, petroleum product stock withdrawals, domestic sources of blending components, other hydrocarbons,

 and coal and natural gas converted to liquid fuel.

2 Includes non-ether, gasoline blending components for 1999-2001.

3 Includes imports of ethers in 2002 and thereafter.

4 Includes ethanol and ethers blended into gasoline.

5 Includes aviation gasoline, petrochemical feedstocks, lubricants, waxes, asphalt, road oil, still gas, special naphthas

 petroleum coke, crude oil product supplied, and miscellaneous petroleum products.

Source: Derived from Year-by-Year Tables 1, 8, 11, & 12, Annual Energy Outlook 2007 (Early Release), EIA/DOE; and Tables A11, A13, and A14,

 

Annual Energy Outlook 2007 (and previous), EIA/DOE; and Table B-7, Economic Report of the President, 2006 .
National Clean Gasoline

Refining Economics

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Alliance of Automobile Manufacturers June 2009

Table B-2: U.S. Imports and Exports of Petroleum Products --

Historical 2000-2006 and Projected 2010

(K b/d)

Historical Projected

Commodity 2000 2001 2002 2003 2004 2005 200612010

IMPORTS 2,395 2,543 2,390 2,599 3,066 3,593 3,381 3,025

Gross Refined Products 1,817 1,787 1,607 1,853 2,075 2,445 2,017 1,781

Natural Gas Liquids 257 250 199 271 306 374 353 330

 Pentanes Plus 41 45 16 46 43 47 22 32

 Liquefied Petroleum Gases 215 206 183 225 264 328 331 297

Finished Motor Gasoline 428 454 498 518 498 603 502 364

 Reformulated 197 217 233 249 213 239 65 0

 Other 231 237 265 269 285 364 437 364

Jet Fuel (incl. Kerosene, & Aviation Gas) 165 155 113 115 130 199 187 156

Distillate Fuel Oil 296 344 267 333 326 325 222 185

 15 ppm or less sulfur 4 84 139

 15 to 500 ppm sulfur 134 129 107 135 149 152 72 0

 > 500 ppm sulfur 162 215 161 198 178 173 150 46

Naphthas (for Petrochemical) 119 90 63 87 134 151 115 124

Other Oils (Petrochemical) 143 142 146 146 158 159 183 167

Special Naphthas 11 13 17 11 8 14 14 12

Residual Oil 353 295 249 327 427 530 356 356

 < 0.31 wt% Sulfur 112 40 43 50 89 93 30 57

 0.31 to 1.00 wt% Sulfur 84 102 52 100 141 175 82 108

 > 1.00 wt% Sulfur 156 153 154 178 198 262 244 191

Asphalt & Road Oil 28 26 27 12 43 43 39 42

Lubricants & Waxes 16 10 9 8 12 15 12 13

Miscellaneous Products 0 1 0 1 0 0 0 0

Petroleum Coke 1 6 19 22 33 32 33 33

Unfinished Oils 274 378 410 335 491 582 689 409

Ethers 81 79 61 44 48 55 - - 

Ethanol 0 1 0 1 10 9 - 19

Gasoline Blending Components 223 298 311 367 452 510 675 816

EXPORTS 993 951 975 1,014 1,024 1,133 1,319 1,228

Finished Petroleum Products 866 869 842 897 916 1,010 1,166 1,081

Finished Motor Gasoline 144 133 124 125 125 136 138 128

Special Naphthas 20 23 15 22 27 21 15 14

Jet Fuel , Kerosene, & Aviation Gas 34 31 34 28 44 55 40 38

Distillate Fuel Oil 173 119 112 107 110 138 218 202

 15 ppm or less sulfur 0 0 0 0 0 0 0 0

 15 to 500 ppm sulfur 47 39 54 50 33 39 65 61

 > 500 ppm sulfur 126 80 59 57 77 99 153 142

Residual Fuel Oil 139 191 177 197 205 251 280 260

Asphalt & Road Oil 6 5 6 10 6 11 15 14

Lubricants & Waxes 29 29 37 41 45 45 74 69

Miscellaneous Products 0 0 0 6 3 6 7 7

Petroleum Coke 319 336 337 361 351 347 378 350

Natural Gas Liquids 78 45 67 59 46 60 69 64

Other Liquids 49 37 66 59 63 64 84 84

Other Hydrocarbons/H2/Oxygenates 31 27 33 29 30 42 76 76

Motor Gasoline Blending Components 18 10 33 30 33 22 8 8

1 Reflects annualized January through October data.
National Clean Gasoline

Refining Economics

1—36

Alliance of Automobile Manufacturers June 2009

Table B-2: U.S. Imports and Exports of Petroleum Products --

Historical 2000-2006 and Projected 2010

(K b/d)

Notes on derivation of projections:

IMPORTS -- EIA projection of net product imports plus exports from Table B-1.

Gross Refined Products -- EIA projection from Table B-1

 Natural Gas Liquids -- sum of projected pentanes and LPG

 Pentanes Plus -- average of 2004 and 2006

 Liquified Petroleum Gases -- average of 2004 and 2006

 Finished Motor Gasoline -- 2006 imports of conventional gasoline plus pro rata share of estimated additional combined

 imports of gasolne, jet fuel, and distillate.

 Reformulated Gasoline -- assumed to be zero because of ethanol blending (included in imported gasoline blendstocks)

 Other Gasoline -- equalt to projected gasoline imports

 Jet Fuel -- 2006 imports plus pro rata share of estimated additional combined imports of gasoline, jet fuel, and distillate

 Distillate Fuel Oil -- 2006 imports plus pro rata share of estimated additional combined imports of gasoline, jet fuel,

 and distillate.

 Distillate Fuel Oil <= 15 pmm -- assumed to be 75% of total diesel fuel imports with advent of low sulfur diesel standard

 Distillate Fuel Oil 15 to 500 pmm -- assumed to be zero

 Distillate Fuel Oil > 500 ppm -- difference between projected total distillate fuel imports and imports of ultra low sulfur diesel

 Naphthas (for Petrochemcial) -- average of imports in 2004 and 2006

 Other Oils (Petrochemical) -- average of last three years

 Special Naphthas -- average of last three years

 Residual Oil Total -- imports in 2006

 Residual Oil by Sulfur Content -- total imports times pro rata share over last three years

 Asphalt & Road Oil -- average of last three years

 Lubricants & Waxes -- average of last three years

 Petroleum Coke -- imports in 2006

Unfinished Oils -- EIA projection from Table B-1

Ethers -- assumed to be zero

Gasoline Blending Components -- EIA projection from Table B-1

Ethanol -- EIA projection from Table B-1

EXPORTS -- EIA projection from Table B-1

Finished Petroleum Products:

 Total -- difference between DOE projection of total exports and projected exports of NGL and other liquids

 Specific Finished Products -- share in 2006 times the projected total of finished products

Natural Gas Liquids -- average of last two years

Other Liquids -- exports in 2006

Source: Derived from Tables 20 & 27 (2000-2004) and Tables 23 & 29 (2005), Petroleum Supply Annuals, EIA/DOE;

 Tables 2 & 48, Petroleum Supply Monthly, Dec. 2006 , EIA/DOE;

 DOE Refinery-Level Import Data (for ethanol imports, 2000-2005); and Table B-1.
National Clean Gasoline

Refining Economics

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Alliance of Automobile Manufacturers June 2009

Table B-3:Projected Growth in Use of Refined Products,

by Region

2004 to 2010

Region

Petroleum PADD P 4&5 ex

Product 1 2 3

1

AZ/NV/CA Calif.2

Total

Total Growth

Motor Gasoline1

4.5% 3.2% 6.9% 6.7% 4.9% 4.7%

Jet & Kerosene 17.2% 17.3% 22.5% 19.7% 21.5% 19.9%

Distillate 7.1% 11.2% 16.3% 16.2% 17.7% 11.7%

Residual Oil -14.6% -34.5% -15.6% 20.5% 26.3% -9.2%

Petro Feedstock -5.1% -5.0% -2.3% -7.3% -8.1% -3.5%

Other -23.9% -26.2% -12.5% 1.9% -21.1% -18.2%

Average Annual

Motor Gasoline1

0.7% 0.5% 1.1% 1.1% 0.8% 0.8%

Jet & Kerosene 2.7% 2.7% 3.4% 3.0% 3.3% 3.1%

Distillate 1.2% 1.8% 2.5% 2.5% 2.8% 1.9%

Residual Oil -2.6% -6.8% -2.8% 3.2% 4.0% -1.6%

Petro Feedstock -0.9% -0.8% -0.4% -1.3% -1.4% -0.6%

Other -4.5% -4.9% -2.2% 0.3% -3.9% -3.3%

1 Includes ethanol blended into finished gasoline.

Note that the regional growth estimates are based on AEO 2006, adjusted for total U.S. growth from AEO2007 (Early Release),

 as regional energy use is not provided in AEO 2007 (Early Release). We relied on the AEO2006 projections as indicators

 of the relative growth in petroleum energy demands across regions. 

1 Includes 50% of Arizona energy use.

2 Includes 50% of Arizona and 100% of Nevada estimated and projected energy use.

Sources: Derived from Supplement Tables 1-10, Annual Energy Outlook 2006, DOE/IEA; 

 Tables 48, 49, & 50 (Prime Supplier Sales), Petroleum Marketing Annual 2004, DOE/EIA;

 Table M21, Federal Highway Statistics 2004, FHWA; and Census Population Estimates.
National Clean Gasoline

Refining Economics

1—38

Alliance of Automobile Manufacturers June 2009

Table B-4a: Annual Supply of Major Refined Products,

by Region -- 2004

(K b/d)

PADD PDs 4&5 U.S.

Product/Source 1 2 3 ex Calif Calif Total

Gasoline 3,264 2,622 1,354 723 1,168 9,130

Refinery (& Field) Production 1,243 2,090 3,632 687 1,106 8,757

 Net Blndstk Purchases 370 146 -215 16 62 380

 Ref Production - Blndstk Pur 872 1,944 3,847 671 1,044 8,378

Net Imports 464 1 -103 8 4 373

Net Inter-PADD Shipments 1,557 532 -2,175 28 58 0

Jet Fuel & Kerosene 650 354 150 251 293 1,699

Refinery Production 121 227 816 200 251 1,614

Net Imports 46 1 -20 21 38 85

Net Inter-PADD Shipments 483 127 -645 31 5 0

Distillate Fuel Oil 1,449 1,202 723 374 321 4,069

Refinery Production 464 867 1,845 362 316 3,853

Net Imports 269 0 -57 0 5 216

Net Inter-PADD Shipments 717 336 -1,065 12 0 0

Residual Oil 480 52 169 112 54 867

Refinery Production 112 57 305 106 65 645

Net Imports 318 1 -90 6 -13 222

Net Inter-PADD Shipments 50 -5 -47 1 0

All Major Products 5,843 4,231 2,396 1,460 1,836 15,766

Refinery Production1

1,569 3,094 6,813 1,338 1,675 14,489

Net Imports 1,097 2 -270 34 34 897

Net Inter-PADD Shipments 2,807 989 -3,932 72 64 0

Notes: Refinery production adjusted to include stock changes.

 California includes refined products produced in California but sold in

 adjacent states (e.g., Arizona & Nevada)

1 Includes refinery production of gasoline, less purchased blendstocks.

Source: Derived from Tables 2-12, Petroleum Supply Annual 2004, EIA/DOE;

 and CEC Refinery Reports, 2004, California Energy Commission.
National Clean Gasoline

Refining Economics

1—39

Alliance of Automobile Manufacturers June 2009

Table B-4b: Projected Supply of Major Refined Products,

by Region -- 2010

(K b/d)

PADD PADDs 4&5 2004 Proj. Growth

Product/Source 1 2 3 ex Calif Calif1Total Total 2004-2010

Gasoline 3,401 2,697 1,443 769 1,221 9,531 9,130 4.4%

Refinery (& Field) Production2

1,602 2,130 3,736 667 1,159 9,295 8,757 6.1%

 Net Blndstk Purchases 730 167 -169 -36 117 808 380

 Imports 706 0 66 4 33 808 380

 From Gulf Coast3

24 167 -235 0 44 0

 From Puget Sound4

-40 40 0

 Production - Blndstk Pur5

872 1,964 3,905 704 1,042 8,487 8,378 1.3%

Net Imports 351 1 -128 8 4 236 373

Net Inter-PADD Shipments 1,448 566 -2,165 93 58 0 0

Jet Fuel & Kerosene 761 415 184 301 356 2,018 1,699 18.8%

Refinery Production 121 245 994 240 301 1,900 1,614 17.7%

Net Imports 62 1 -24 25 55 118 85

Net Inter-PADD Shipments 579 169 -785 37 0 0 0

Distillate Fuel Oil 1,526 1,315 827 428 372 4,467 4,069 9.8%

Refinery Production 464 945 2,264 434 379 4,485 3,853 16.4%

Net Imports 51 -1 -70 9 -7 -17 216

Net Inter-PADD Shipments 1,011 371 -1,367 -15 0 0 0

Residual Oil 408 34 142 134 67 786 867 -9.4%

Refinery Production 112 57 312 128 80 689 645 6.9%

Net Imports 214 1 -112 6 -13 96 222

Net Inter-PADD Shipments 82 -23 -59 0 0 0 0

Major Products 6,096 4,461 2,596 1,631 2,017 16,801 15,766 6.6%

Refinery Production6

1,569 3,210 7,474 1,505 1,802 15,560 14,489 7.4%

Net Gas Blndstk Imports 706 0 66 4 33 808 380

Net Finished Prod. Imports 678 2 -335 48 40 433 897

Net Inter-PADD Shipments 3,120 1,083 -4,375 115 58 0 0

Proj.Growth in Refinery

Out-turns, 2004-2010 0.0% 3.7% 9.7% 12.5% 7.6% 7.4%

Gasoline (less Blndstk Pur) 0.0% 1.0% 1.5% 4.8% -0.1% 1.3%

Jet Fuel & Kerosene 0.0% 8.0% 21.8% 20.0% 20.0% 17.7%

Distillate Fuel Oil 0.0% 9.0% 22.7% 20.0% 20.0% 16.4%

Residual Oil 0.0% 0.0% 2.4% 21.0% 23.3% 6.9%

1 Includes California refinery out-turns sold in adjacent states; does not include projected shipments of 25 K b/d

 of EBOB from Pudget Sound refineries to California.

2 Includes net blendstock purchases and "Field Production" of oxygenated gasoline.

3 Assumes 20% growth in PADD 3 out-turns of gasoline blendstocks and allocated pro-rata based on 2002

4 Includes alkylate and isomerate; does not include projected shipments of 25 K b/d of CaRFG to California

 (which is included in PADD 4&5 refinery production of finished gasoline).

5 Not adjusted for ethanol bending that may occur in the destination-PADD.

6 Calculated as the sum of gasoline production (less blendstock purchases) and production of jet fuel & kerosene, distillate, and resid.

Notes: 2012 totals calculated by multiplying 2004 totals by DOE projected growth from 2004 to 2012.

 Numbers in italics for PADD 3 indicate implicit growth in production to balance projected U.S. demand,

 less imports and production in other refining centers.

Sources: Derived from Tables 2-12 & 32, Petroleum Supply Annual 2004, EIA/DOE; and Tables A-5, B-1, B-2, B-3, and B-4a.
National Clean Gasoline

Refining Economics

1—40

Alliance of Automobile Manufacturers June 2009

Table B-5: Projected Refinery Inputs and Net Production,

by Region -- 2010

(K b/d)

Summer 

PADDs 4&5

Inputs & Outputs PADD 1 PADD 2 PADD 3 ex Calif. California U.S.

Refinery Inputs: 2,669 4,032 8,982 19,525

Crude Oil 1,594 3,451 8,347 1,538 1,941 16,908

Natural Gas Liquids 4 83 226 68 11 402

Pentanes Plus 40 110 31 189

Liquified Petroleum Gases 4 42 115 37 11 212

 Ethane

 Propane

 Normal Butane 0 3 24 23 5 55

 Isobutane 4 40 91 15 6 158

Other Liquids 1,071 497 410 2,215

Other Hydrocarbons/H2/Oxy 166 224 236 - - 782

 Other Hydrocarbons/H2 8 44 94

 Oxygenates1

166 216 192 59 55 689

Unfinished Oils -- Total 48 56 315 -52 94 462

Motor Gasoline Blend. Comp. 831 168 -157 -35 119 925

Aviation Gasoline Blend. Comp. -7 0 0 -6

Refinery Outputs: 2,605 3,869 8,717 1,515 2,136 18,890

Liquified Refinery Gases 80 160 547 30 75 894

Ethane/Ethylene 0 23 24

 Ethane 0 16 16

 Ethylene 0 7 7

Propane/Propylene 58 118 389 23 49 639

 Propane 34 84 190 21 44 375

 Propylene 23 34 199 2 5 264

Normal Butane/Butylene 25 47 137 9 35 253

 Normal Butane 25 47 138 9 35 256

 Buytlene 0 -1 -2 0 0 -3

Isobutane/Isobutylene -3 -4 -3 -2 -9 -22

 Isobutane -4 -5 -3 -3 -10 -24

 Isobutylene 0 0 0 0 1 2

Finished Petroleum Products 2,525 3,708 8,170 1,486 2,061 17,996

Finished Motor gasoline 1,691 2,162 3,781 620 1,223 9,478

 Reformulated 969 421 974 21 1,010 3,394

 Other 723 1,741 2,807 600 213 6,083

Finished Aviation Gasoline 5 11 5 22

Jet Fuel 112 242 966 234 303 1,857

Kerosene 9 3 35 2 49

Distillate Fuel Oil 450 961 2,321 430 400 4,559

 CARB (& less than 0.0015 % sulfur) 271 271

 Less than 0.0015 % sulfur 344 868 1,971 426 128 3,740

 Greater than 0.0015 % sulfur 122 90 370 10 0 598

Residual Fuel Oil 103 58 319 127 73 681

 Less than 0.31 % sulfur 45 25 6 3 82

 0.31 to 1.00 % sulfur 44 4 35 39 23 143

 Greater than 1.00 % sulfur 14 54 258 82 47 456

Naphtha to Petrochemical 15 29 205 1 0 249

Other Oils to Petrochemical 9 187 1 9 206

Special Naphthas 2 5 48 1 56

Lubricants & Waxes 19 17 145 0 25 206

Asphalt and Road Oil 129 204 131 69 42 576

Miscellaneous Products 1 12 34 -1 10 57

1 Estimated assuming total ethanol use of 7.5 bgy.

Sources: Derived Petroleum Supply Annual 2004, Vols. 1 &2, EIA/DOE; and

 Table B-4b.
National Clean Gasoline

Refining Economics

1—41

Alliance of Automobile Manufacturers June 2009

Table B-6a: Allocation of Annual Gasoline Use by Region, States, and

Gasoline Type -- 2010

 

(K b/d)

Gasoline Type

EtOH California RFG

Region Conven- Mandate Low RVP Areas Federal Federal State Arizona

& State tional (Minn.) 7.8 7.2 7.0 RFG Area Area CBG Total

PADD 1 920 0 826 0 164 1,491 0 0 0 3,401

Subdistrict 1A 52 0 32 0 375 0 0 0 459

Connecticut 123 123

Maine 16 32 48

Massachusetts 191 191

New Hampshire 13 35 48

Rhode Island 26 26

Vermont 24 24

Subdistrict 1B 98 0 354 0 792 0 0 0 1,244

Delaware 28 28

District of Columbia 10 10

Maryland 16 163 178

New Jersey 290 290

New York 52 128 206 386

Pennsylvania 30 227 94 351

Subdistrict 1C 771 0 439 164 324 0 0 0 1,697

Florida 292 274 567

Georgia 125 63 151 339

North Carolina 118 78 100 296

South Carolina 109 64 173

Virginia 92 173 266

West Virginia 34 23 57

PADD 2 1,212 188 527 0 303 466 0 0 0 2,697

Illinois 125 233 357

Indiana 83 104 6 31 223

Iowa 113 113

Kansas 71 22 93

Kentucky 117 2 3 36 158

Michigan 75 99 168 341

Minnesota 188 188

Missouri 121 102 223

Nebraska 60 60

North Dakota 25 25

Ohio 81 281 362

Oklahoma 103 31 134

South Dakota 30 30

Tennessee 85 127 212

Wisconsin 124 9 43 177

PADD 3 648 0 330 0 62 403 0 0 0 1,443

Alabama 148 33 182

Arkansas 101 2 103

Louisiana 82 64 22 167

Mississippi 116 116

New Mexico 66 66

Texas 135 266 27 381 810

PADDs 4 & 5 ex CA 394 67 391 0 0 0 0 0 119 971

Alaska 23 23

Arizona 79 119 198

Colorado 49 92 140

Hawaii 34 34

Idaho 41 41

Montana 33 33

Nevada 13 76 89

Oregon 59 58 117

Utah 16 52 68

Washington 91 113 204

Wyoming 23 23

CALIFORNIA 746 273 1,019

UNITED STATES 3,174 255 2,074 0 529 2,361 746 273 119 9,531

1 We assume spillover of a small volume of CaRFG into Nevada occurs in 2008 and report it as State CBG.

Note: Gasoline is classified by the area into which it is sold. Volumes reflect year-long (annual, rather than seasonal)
National Clean Gasoline

Refining Economics

1—42

Alliance of Automobile Manufacturers June 2009

Table B-6b: Projected Annual Gasoline Use and Supply Sources,

By Region and Type of Gasoline -- 2010

(K barrels per day)

Gasoline Type

EtOH Low RVP California RFG

Region of Use & Conven- Mandate Areas Federal Federal State Arizona

Origin of Supply tional (Minn.) 7.8 7.01 RFG Area Area CBG Total

Use in PADD 1 920 826 164 1,491 3,401

PADD 1 Refineries 78 325 986 1,389

PADD 2 Refineries 7 10 17

PADD 3 Refineries 649 439 164 392 1,643

Net Imports 186 52 113 351

Use in Subdistrict 1A 52 32 375 459

PADD 1 Refineries 50 0 295 345

PADD 3 Refineries 0

Net Imports 2 32 80 114

Use in Subdistrict 1B 98 354 792 1,244

PADD 1 Refineries 0 325 682 1,007

PADD 2 Refineries 7 10 17

PADD 3 Refineries 0 0 90 90

Net Imports 90 20 20 130

Use in Subdistrict 1C 771 439 164 324 1,697

PADD 1 Refineries 28 9 37

PADD 3 Refineries 649 439 164 302 1,553

Net Imports 94 13 107

Use in PADD 2 1,212 188 527 303 466 2,697

PADD 1 Refineries 72 141 213

PADD 2 Refineries 967 188 325 171 405 2,055

PADD 3 Refineries 151 61 133 62 407

PADD 4 Refineries 21 21

Net Imports 1 0 1

Use in PADD 3 648 330 62 403 1,443

PADD 2 Refineries 22 16 37

PADD 3 Refineries 754 330 62 388 1,534

Net Imports -128 -1 -128

Use in PADDs 4 & 5 ex CA 394 67 391 119 971

PADD 2 Refineries 21 21

PADD 3 Refineries -- direct 67 0 85 152

 -- routed through Calif 0

PADD 4 & 5 (ex CA) Ref. 207 67 315 589

California Refineries 92 76 34 202

Net Imports 8 8

Use in California 746 273 1,019

PADD 4 & 5 (ex CA) Ref. 58 58

California Refineries 0 684 273 957

Net Imports 0 4 4

TOTAL USE 3,174 255 2,074 529 2,361 746 273 119 9,531

U.S. Refinery Production 3,106 255 2,022 529 2,248 742 273 119 9,295

PADD 1 151 465 986 1,602

PADD 2 1,016 188 335 171 420 2,130

PADD 3 1,620 831 358 842 85 3,736

PADDs 4 & 5 ex CA 227 67 315 58 667

California 92 76 684 273 34 1,159

Net Imports 68 52 112 4 236

1 Includes small projected volume (15 K b/d) of gasoline sold to an area in PADD 2 with an RVP limit of 7.2 psi.

Sources: Derived from Tables B-4b and B-6a.
National Clean Gasoline

Refining Economics

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Alliance of Automobile Manufacturers June 2009

Table B-6c: Projected Gasoline Production Volume, RVP, and

Octane, by Type of Gasoline, Destination, and Region -- 2010

Producing Region, Annual Production Seasonal Pool

Type of Gasoline, & Volume Share Production (K b/d) RVP Octane

Destination (K b/d) (%) Summer Winter Summer Winter (R+M)/2

PADD 1 Refineries 1,602 100.0% 1,691 1,526 7.2 14.1 88.1

Conventional 151 9.4% 177 128 8.7 13.8 88.1

 Subdistrict 1A 50 59 43 8.7 14.3

 Subdistrict 1B 0 0 0 8.7 14.2

 Subdistrict 1C 28 33 24 8.7 13.0

 PADD 2 72 85 62 8.7 13.8

7.8 RVP Areas 465 29.0% 546 396 7.6 14.1 88.1

 Subdistrict 1A 0 0 0 7.6 14.3

 Subdistrict 1B 325 381 277 7.6 14.2

 PADD 2 141 165 120 7.6 13.8

RFG 986 61.6% 969 1,001 6.8 14.2 88.1

 Subdistrict 1A 295 290 299 6.8 14.3

 Subdistrict 1B 682 670 693 6.8 14.2

 Subdistrict 1C 9 9 9 6.8 13.0

PADD 2 Refineries 2,130 100.0% 2,162 2,103 8.0 13.8 88.0

Conventional 1,204 56.5% 1,226 1,186 8.7 13.8 88.0

 PADD 1 7 8 7 8.7 13.8

 EtOH Mandate (Minnesota) 188 191 185 8.7 13.8

 PADD 2 other 967 984 952 8.7 13.8

 PADD 3 22 22 21 8.7 12.6

 PADDs 4&5 ex CA 21 21 20 8.7 13.0

7.8 RVP Areas 335 15.7% 341 330 7.6 13.8 88.0

7.0 RVP Areas1 171 8.0% 174 168 6.8 13.8 88.0

RFG 420 19.7% 421 419 6.8 13.8 88.0

 PADD 2 405 406 403 6.8 13.8

 PADD 3 16 16 16 6.8 12.6

PADD 3 Refineries 3,736 100.0% 3,781 3,697 7.8 12.9 87.8

Conventional 1,620 43.4% 1,619 1,621 8.7 12.9 87.7

 Subdistrict 1B 0 0 0 8.7 14.2

 Subdistrict 1C 649 648 649 8.7 13.0

 PADD 2 151 151 151 8.7 13.8

 PADD 3 626 626 626 8.7 12.6

 PADDs 4&5 ex CA 67 66 67 8.7 13.0

 Net Exports 128 127 128 8.7 12.6

7.8 RVPAreas 831 22.2% 830 831 7.6 12.9 87.7

 Subdistrict 1B 0 0 0 7.6 14.2

 Subdistrict 1C 439 439 440 7.6 13.0

 PADD 2 61 61 61 7.6 13.8

 PADD 3 330 330 330 7.6 12.6

 PADDs 4&5 ex CA 0 0 0 7.6 13.0

7.0 RVP Areas 358 9.6% 358 359 6.8 13.2 87.7

 Subdistrict 1C 164 163 164 6.8 13.0

 PADD 2 133 133 133 6.8 13.8

 PADD 3 62 62 62 6.8 12.6

RFG 841 22.5% 884 805 6.8 13.0 88.2

 Subdistrict 1B 90 95 86 6.8 14.2

 Subdistrict 1C 302 317 288 6.8 13.0

 PADD 2 62 65 59 6.8 13.8

 PADD 3 388 408 371 6.8 12.6

 Net Exports 1 1 1 6.8 13.0

Arizona CBG 85 2.3% 89 81 6.8 11.4 88.2

PADDs 4 & 5 ex CA Refineries 667 100.0% 620 707 7.9 12.9

Conventional 227 34.1% 224 230 8.7 13.0

EtOH Mandate (MT & HA) 67 10.0% 66 68 7.6 12.6

7.8 RVP 315 47.2% 310 319 7.6 13.0

California RFG 58 8.7% 21 90 6.8 12.6

California Refineries 1,159 100.0% 1,223 1,105 7.0 12.5

Conventional 92 7.9% 117 71 8.7 13.0

 PADDs 4&5 ex CA 92 117 71 8.7 13.0

 Net Exports 0 0 0 8.7 12.5

7.8 RVP Areas 76 6.5% 96 58 7.6 13.0

California RFG 957 82.6% 967 949 6.8 12.5

Arizona CBG 34 2.9% 43 26 6.8 11.4

TOTAL U.S. 9,294 100.0% 9,478 9,138 7.7 13.3

Conventional 3,294 35.4% 3,362 3,236 8.7 13.3

7.8 RVPAreas 2,022 21.8% 2,124 1,936 7.6 13.3

7.0 RVP Areas 529 5.7% 532 527 6.8 13.4

RFG 2,248 24.2% 2,274 2,225 6.8 13.7

California RFG 1,015 10.9% 987 1,039 6.8 12.5

Arizona CBG 119 1.3% 133 108 6.8 11.4

Notes: RVPs incorporate typical refinery safety factors of about 0.2 psi

 Production of ethanol-blended non-RFG is included in conventional gasoline

 Production of gasoline blendstocks not included in totals (i.e., totals include only finished gasoline).

1 Includes small volume (14 K b/d) of gasoline sold to an area in PADD 2 with an RVP limit of 7.2 psi.

Source: Derived from Tables A-3c and B-6b; 2005 Petroleum Marketing Monthlys; and AAM Gasoline Survey, Summer 2004.
National Clean Gasoline

Refining Economics

1—44

Alliance of Automobile Manufacturers June 2009

Table B-6d: Projected Gasoline Blendstock Use, 2010

K b/d

Source & 

Area of Use Annual Summer Winter

Gulf Coast to: 235 240 231

PADD 1 24 28 22

 RFG 24 28 22

 CG 0 0 0

PADD 2 167 168 165

 RFG 118 117 119

 CG 49 51 46

PADDs 4&5 ex CA: CG 0 0 0

California: RFG 44 44 44

Net Imports to: 808 925 708

PADD 1 706 803 623

 RFG 322 335 325

 CG 383 467 298

PADD 3: CG 66 83 51

PADDs 4&5 ex CA: CG 4 5 3

California 33 35 30

 RFG 3 0 6

 CG 29 34 24

Import Share: 100% 100% 100%

Federal RFG 40% 36% 46%

California RFG 0% 0% 1%

CG 60% 64% 53%

Puget Sound to:

California -- Alky & Isomerate 40 40 40

Note: Imported gasoline blendstocks are assumed to contain no oxygenates.

Source: Derived from Tables 2, 6, 10, 14, 18, & 22, Petroleum Supply Monthly,

 2006 Issues, EIA/DOE; and Table B-4b.
National Clean Gasoline

Refining Economics

1—45

Alliance of Automobile Manufacturers June 2009

Table B-7: Projected Ethanol Annual Use, by Region

and Source of Gasoline Supply, 2010

K b/d

In Gasoline By Source

Region/ Consumed of Gasoline

Source in the Region Supply

PADD 1 340 78

PADD 2 270 194

PADD 3 144 418

PADDs 4&5 ex CA 97 66

California 102 108

Imports1

- 88

Total

K b/d 953 953

Bgy 14.6 14.6

1 Includes ethanol blended with imported finished gasoline and gasoline blendstocks.

Source: Derived from Exhibits B-6a, B-6b, B-6c, and B-6d.
National Clean Gasoline

Refining Economics

1-46

Alliance of Automobile Manufacturers June 2009

Table C-1: National Average Properties of RFG and CG (ex California), 2000-2004

RFG CG1 Pool

2000 2001 2002 2003 2004 2000 2001 2002 2003 2004 2000 2001 2002 2003 2004

Alliance Surveys

Rvp (psi) 6.8 6.8 6.8 6.9 6.9 7.9 7.8 7.9 7.8 7.8 7.7 7.6 7.6 7.6 7.6

Oxygen (wt%) 2.2 2.2 2.2 2.3 2.5 0.6 0.6 0.6 0.5 0.5 1.0 1.0 1.0 0.9 1.0

 MTBE (vol%) 9.2 9.1 9.2 9.5 8.2 0.5 0.3 0.4 0.4 0.6 2.4 2.3 2.3 2.4 2.2

 Tame (vol%) 0.9 0.6 0.6 0.6 0.4 0.0 0.0 0.0 0.0 0.1 0.2 0.2 0.2 0.1 0.2

 Ethanol (vol%) 1.1 1.1 1.3 1.3 2.6 1.5 1.6 1.5 1.3 1.2 1.4 1.5 1.5 1.3 1.5

Aromatics (vol%) 21.5 22.8 21.7 22.5 23.3 30.6 30.6 30.0 30.5 31.1 28.6 28.9 28.2 28.8 29.4

Benzene (vol%) 0.60 0.63 0.55 0.54 0.57 1.21 1.26 1.12 1.13 1.08 1.08 1.12 0.99 1.00 0.97

Olefins (vol%) 11.1 10.1 9.2 10.1 11.3 11.3 10.7 9.6 9.5 9.5 11.3 10.6 9.5 9.7 9.9

Sulfur (ppm) 120 122 140 112 86 276 293 305 249 110 242 256 269 219 105

E200 (%off) 48.5 48.6 48.3 49.1 48.5 44.6 45.1 43.6 43.7 43.5 45.5 45.8 44.6 44.8 44.6

E300 (%off) 84.0 84.0 83.4 82.9 82.2 79.5 80.8 79.5 79.2 80.3 80.5 81.5 80.3 80.0 80.7

DI2

1,149 1,147 1,154 1,149 1,159 1,173 1,162 1,182 1,185 1,181 1,168 1,159 1,176 1,177 1,176

Octane (R+M)/2 88.3 88.2 88.1 88.2 88.5 88.1 88.1 88.0 88.0 88.0 88.1 88.1 88.1 88.0 88.1

EPA Refinery & Importer Reports

Rvp (psi) 6.8 6.8 6.8 6.8 8.0 8.2 8.2 8.2 7.7 7.9 7.9 7.9

Oxygen (wt%) 2.2 2.1 2.2 2.2 0.2 0.2 0.2 0.2 0.7 0.7 0.7 0.7

 MTBE (vol%) 8.8 8.7 8.7 8.6 0.5 0.6 0.6 0.6 2.6 2.6 2.6 2.5

 Tame (vol%) 0.9 0.9 0.7 0.8 0.1 0.1 0.1 0.1 0.3 0.3 0.3 0.2

 Ethanol (vol%) 1.1 1.1 1.3 1.5 0.3 0.2 0.3 0.3 0.5 0.4 0.5 0.6

Aromatics (vol%) 19.3 20.1 20.4 20.1 28.4 28.1 27.9 27.5 26.1 26.1 26.0 25.7

Benzene (vol%) 0.59 0.62 0.59 0.61 1.15 1.16 1.10 1.13 1.01 1.02 0.97 1.00

Olefins (vol%) 10.6 11.8 10.8 11.0 11.7 12.6 12.0 11.9 11.5 12.4 11.7 11.7

Sulfur (ppm) 126 127 124 110 317 300 295 299 268 256 252 254

E200 (%off) 47.7 47.4 47.5 47.9 45.1 44.9 44.8 44.7 45.8 45.6 45.5 45.5

E300 (%off) 84.7 84.4 84.4 84.4 80.7 80.6 80.3 79.8 81.7 81.5 81.4 80.9

EPA Federal RFG Area Surveys

RVP (psi) 6.8 6.8 6.8 6.8 6.9

Oxygen (wt%) 2.3 2.3 2.4 2.5 2.6

 MTBE (wt%) 8.6 8.4 8.2 8.2 7.3

 TAME (wt%) 0.9 1.0 0.8 0.9 0.5

 Ethanol (wt%) 1.8 1.8 2.1 2.4 3.4

Aromatics (vol%) 19.2 20.0 20.2 19.8 21.0

Benzene (vol%) 0.61 0.65 0.62 0.65 0.66

Olefins (vol%) 9.1 10.0 10.6 10.7 10.5

Sulfur (ppm) 130 125 120 109 76

E200 (%off) 48.0 47.6 47.7 48.1 48.2

E300 (%off) 84.9 84.5 84.0 84.0 83.2

1 Includes low-RVP gasoline

2 Does not include an adjustment to account for the adverse effects of ethanol on driveability
National Clean Gasoline

Refining Economics

1-47

Alliance of Automobile Manufacturers June 2009

Table C-2: Average Properties of RFG and CG, by PADD of Origin, 2002-2004

PADD 1 PADD 2 

RFG CG1 Pool RFG CG1 Pool

2002 2003 2004 2002 2003 2004 2002 2003 2004 2002 2003 2004 2002 2003 2004 2002 2003 2004

Alliance Surveys

Rvp (psi) 6.9 7.0 7.0 7.6 7.6 7.7 7.2 7.2 7.3 6.8 6.8 7.0 8.3 8.3 8.3 8.2 8.1 8.2

Oxygen (wt%) 2.2 2.2 2.7 0.5 0.6 1.0 1.5 1.6 2.0 3.2 3.2 3.3 1.3 1.1 1.0 1.6 1.4 1.3

 MTBE (vol%) 11.7 11.3 7.7 0.7 0.8 3.1 7.3 7.2 5.9 0.1 0.1 0.0 0.1 0.0 0.0 0.1 0.0 0.0

 Tame (vol%) 0.2 0.7 0.0 0.0 0.0 0.0 0.1 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Ethanol (vol%) 0.0 0.0 3.8 1.2 1.3 1.3 0.5 0.5 2.8 9.2 9.3 9.6 3.8 3.2 3.0 4.5 3.9 3.8

Aromatics (vol%) 24.0 24.2 24.3 33.4 29.2 30.5 27.7 26.2 26.7 20.5 21.0 20.7 29.3 29.9 29.6 28.3 28.9 28.5

Benzene (vol%) 0.52 0.45 0.52 0.81 0.68 0.71 0.63 0.54 0.60 0.70 0.67 0.76 1.32 1.37 1.18 1.25 1.28 1.13

Olefins (vol%) 10.2 12.4 13.4 9.8 10.2 10.7 10.0 11.5 12.3 5.3 5.6 7.1 8.2 8.1 8.7 7.8 7.8 8.5

Sulfur (ppm) 106 95 93 159 157 111 127 120 100 126 108 96 299 255 153 279 237 146

E200 (%off) 49.1 48.9 48.5 41.9 45.4 43.3 46.3 47.5 46.4 44.8 45.3 46.4 45.7 46.1 44.4 45.6 46.0 44.7

E300 (%off) 83.7 82.6 82.7 79.0 80.4 80.8 81.8 81.8 81.9 84.1 84.3 83.2 80.7 80.6 80.7 81.1 81.1 81.0

DI2

1,144 1,149 1,156 1,206 1,176 1,193 1,168 1,160 1,171 1,180 1,178 1,175 1,151 1,150 1,162 1,155 1,153 1,164

Octane (R+M)/2 88.1 88.4 88.6 88.1 88.0 87.9 88.1 88.2 88.3 88.5 88.5 89.2 88.1 87.9 87.9 88.1 87.9 88.1

EPA Refinery Reports

Rvp (psi) 6.8 8.3 7.4 6.9 8.5 8.3

Oxygen (wt%) 2.1 0.8 1.6 2.6 0.3 0.5

 MTBE (vol%) 11.7 1.6 7.7 0.0 0.0 0.0

 Tame (vol%) 0.1 0.0 0.1 0.0 0.0 0.0

 Ethanol (vol%) 0.0 1.4 0.6 7.0 0.7 1.5

Aromatics (vol%) 21.0 26.5 23.2 19.9 28.7 27.7

Benzene (vol%) 0.57 0.95 0.72 0.82 1.39 1.32

Olefins (vol%) 13.0 13.3 13.1 3.7 9.6 8.9

Sulfur (ppm) 101 230 152 115 351 323

E200 (%off) 47.3 46.6 47.1 45.4 45.8 45.8

E300 (%off) 82.8 81.2 82.2 85.1 80.8 81.3

EPA Federal RFG Area Surveys

RVP (psi) 6.8 6.8 6.9 6.8 6.8 6.9

Oxygen (wt%) 2.1 2.1 2.8 3.3 3.5 3.5

 MTBE (wt%) 10.5 10.7 6.0 0.6 0.1 0.0

 TAME (wt%) 0.9 1.2 0.1 0.0 0.0 0.0

 Ethanol (wt%) 0.0 0.0 4.9 9.2 10.1 10.2

Aromatics (vol%) 21.5 21.5 21.8 18.6 17.9 18.5

Benzene (vol%) 0.59 0.67 0.63 0.71 0.70 0.80

Olefins (vol%) 12.2 12.3 12.8 6.3 6.6 6.2

Sulfur (ppm) 101 87 83 116 116 84

E200 (%off) 47.6 47.3 47.5 46.1 46.1 47.1

E300 (%off) 84.3 84.1 83.7 84.4 84.6 83.9

1 Includes low-RVP gasoline

2 Does not include an adjustment to account for the adverse effects of ethanol on driveability
National Clean Gasoline

Refining Economics

1-48

Alliance of Automobile Manufacturers June 2009

Table C-2, cont: Average Properties of RFG and CG, by PADD of Origin, 2002-2004

PADD 3

RFG CG1 Pool

2002 2003 2004 2002 2003 2004 2002 2003 2004

Alliance Surveys

Rvp (psi) 6.8 7.0 6.9 7.5 7.5 7.4 7.4 7.4 7.3

Oxygen (wt%) 2.0 2.1 2.1 0.1 0.1 0.2 0.5 0.6 0.6

 MTBE (vol%) 10.1 10.9 10.8 0.6 0.7 0.7 2.7 2.9 2.9

 Tame (vol%) 1.0 0.7 0.7 0.0 0.0 0.2 0.2 0.2 0.3

 Ethanol (vol%) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Aromatics (vol%) 20.7 21.9 23.5 30.4 31.3 31.9 28.3 29.3 30.1

Benzene (vol%) 0.54 0.57 0.54 0.98 0.95 0.98 0.88 0.87 0.89

Olefins (vol%) 9.6 10.0 11.1 10.6 10.4 10.0 10.4 10.3 10.2

Sulfur (ppm) 165 123 78 331 244 90 295 218 87

E200 (%off) 48.9 50.2 49.1 41.7 41.5 42.7 43.2 43.4 44.1

E300 (%off) 83.1 82.7 81.7 78.1 77.7 79.7 79.2 78.8 80.1

DI2

1,153 1,141 1,157 1,209 1,214 1,194 1,197 1,198 1,186

Octane (R+M)/2 88.0 88.0 88.2 88.1 88.2 88.3 88.1 88.1 88.3

EPA Refinery Reports

Rvp (psi) 6.8 8.1 7.8

Oxygen (wt%) 2.3 0.1 0.6

 MTBE (vol%) 8.9 0.7 2.5

 Tame (vol%) 0.7 0.1 0.2

 Ethanol (vol%) 1.6 0.0 0.3

Aromatics (vol%) 18.3 26.3 24.6

Benzene (vol%) 0.55 0.95 0.86

Olefins (vol%) 10.9 12.8 12.4

Sulfur (ppm) 131 308 270

E200 (%off) 49.1 43.8 45.0

E300 (%off) 84.3 78.4 79.6

EPA Federal RFG Area Surveys

RVP (psi) 6.8 6.8 6.9

Oxygen (wt%) 2.1 2.1 2.1

 MTBE (wt%) 10.5 10.9 11.0

 TAME (wt%) 0.9 0.9 0.8

 Ethanol (wt%) 0.0 0.0 0.0

Aromatics (vol%) 19.9 19.2 21.0

Benzene (vol%) 0.59 0.61 0.57

Olefins (vol%) 11.3 11.3 11.2

Sulfur (ppm) 147 132 71

E200 (%off) 48.9 49.9 49.0

E300 (%off) 83.6 83.6 81.9

1 Includes low-RVP gasoline

2 Does not include an adjustment to account for the adverse effects of ethanol on driveability
National Clean Gasoline

Refining Economics

1-49

Alliance of Automobile Manufacturers June 2009

Table D-1a: Estimated Cost of Proposed National Clean Gasoline Standard, 

by PADD and Study Case 

PADD 1 PADD 2 PADD 3 PADDs 1-3

Study Case --> #1 #2 #3 #1 #2 #3 #1 #2 #3 #1 #2 #3

RFG --> • • • • • • • • • • • •

Low RVP --> • • • • • • • •

CG --> • • • •

Refining Cost

Total ($million/d) 0.5 0.6 0.7 0.2 0.6 2.1 0.7 2.1 5.0 1.5 3.4 7.8

Capital charge & fixed 0.0 0.0 0.1 0.0 0.0 0.1 0.1 0.2 1.2 0.1 0.3 1.4

All other 0.5 0.6 0.7 0.2 0.6 2.0 0.6 1.9 3.7 1.4 3.0 6.4

Cents/gal of Affected Gasoline

Average 2.1 2.0 2.2 2.0 1.8 2.6 1.4 2.0 2.9 1.6 1.9 2.7

Incremental 2.1 1.8 4.6 2.0 1.7 3.1 1.4 2.6 4.6 1.6 2.3 3.9

Refinery Investment ($B) 0.0 0.0 0.1 0.0 0.1 0.2 0.1 0.3 1.5 0.1 0.4 1.8

Affected Gasoline (K b/d) 565 719 771 292 807 1,976 1,283 2,571 4,046 2,140 4,097 6,793

Cost of Change in Gasoline

Pool Energy Density ($MM/d) -0.1 -0.1 -0.2 0.0 -0.1 -0.8 0.2 -0.2 -0.6 0.1 -0.2 -0.6

Note: In $2005.
National Clean Gasoline

Refining Economics

1-50

Alliance of Automobile Manufacturers June 2009

Table D-1b: Effect of Changes in Energy Prices on the Estimated

Cost of Proposed National Clean Gasoline Standard

Original Study Costs Crude Price Sensitivity Analysis

Study Case --> #1 #2 #3 #1 #2 #3

RFG --> • • • • • •

Low RVP --> • • • •

CG --> • •

Assumed Energy Prices

Crude ($/b) 51.2 125

Electricity (¢/Kwh) 6.1 6.6

Industrial Natural Gas ($/mcf) 6.82 10.5

Refining Cost

Total ($million/d) 1.5 3.4 7.8 2.3 5.4 12.9

Cents/gal of Affected Gasoline 1.6 1.9 2.7 2.5 3.2 4.5

Effect on Estimated Refining

Cost of a $10/b Crude Price

Increase (¢/g)1

0.06 0.09 0.15

Affected Gas Volume (K b/d) 2,140 4,097 6,793 2,140 4,097 6,793

1 Assumes electricity and natural gas prices remain as specified.
National Clean Gasoline

Refining Economics

1-51

Alliance of Automobile Manufacturers June 2009

Table D-2: Operations and New Capacity

(K b/d, except as noted)

PADD 1 

Study Case

Type of #1 #2 #3

2002 2010 RFG RFG+ RFG+

Calib- Refer- Low RVP Low RVP+

Process Process ration ence CG

USE OF EXISTING CAPACITY

Crude Distillation Atmospheric 1,566 1,621 1,621 1,621 1,621

Conversion Fluid Cat Cracker 590 649 655 655 655

Hydrocracker 38 30 5 5 7

Coking 77 66 67 68 68

Visbreaker

Upgrading Alkylation 85 97 97 97 97

Merchant Iso-Octane/ene

Catalytic Polymerization 16 12 10 10 10

Dimersol

Pen/Hex Isomerization 17 17 17 17 17

Reforming 240 212 232 236 240

Oxygenate Prod. MTBE -- FCC-based 7

MTBE -- Field Butane-based

MTBE -- Other

TAME 2

Hydrotreating Naphtha Desulf. 329 291 312 318 320

FCC Naphtha Desulfurization 67 351 351 351 351

Benzene Saturation 0 1

Distillate Desulfurization 376 427 437 436 435

FCC Feed Desulfurization 89 44 44 44 44

Merox (MTBE)

Resid Desulfurization

Hydrogen Hydrogen Plant (MM scf/d) 74 1,109 1,108 1,106 1,110

Fractionation Debutanization 100 109 109 109 109

Lt. Naphtha Spl. (Benz. Prec.) 35 9 9 9 9

Other Aromatics Plant 29 53 53 53 53

Benzene Extraction 3 1 1 1 1

Butane Isomerization 6 10 9 9

Lubes & Waxes 18 19 19 19 19

Solvent Deasphalting 14 19 19 19 19

Sulfur Recovery (K s tons/d) 1 1 1 1 1

Steam Generation (K lb/hr) 7,849 8,298 8,316 8,363 8,400

NEW CAPACITY

Upgrading Alkylation

Pen/Hex Isomerization

Hydrogen Hydrogen Plant (MM scf/d) 0 0

Fractionation Debutanization 1

Depentanization 31 28 44

Medium Naphtha Splitter

Light Gas Processing

Retrofitting Captive MTBE to Alkylate

Tier 2 Desulfurization 4 15 15 14

OPERATIONS

Operating Indices FCC Conversion (Vol %) 74.7 73.1 71.4 71.4 71.4

Reformer Severity (RON) 96.9 98.0 98.0 98.0

Charge Rates Fluid Cat Cracker1590 639 645 645 645

Reformer1

241 214 234 239 242

FCC Olefin Max Cat. (%)

Fuel Use All Fuels (foeb) 104 109 113 113 114
National Clean Gasoline

Refining Economics

1-52

Alliance of Automobile Manufacturers June 2009

Table D-2: Operations and New Capacity

(K b/d, except as noted)

PADD 2 

Study Case

Type of #1 #2 #3

2002 2010 RFG RFG+ RFG+

Calib- Refer- Low RVP Low RVP+

Process Process ration ence CG

USE OF EXISTING CAPACITY

Crude Distillation Atmospheric 3,324 3,328 3,331 3,344 3,402

Conversion Fluid Cat Cracker 1,169 1,141 1,140 1,140 1,117

Hydrocracker 148 160 160 160 160

Coking 319 306 307 309 320

Visbreaker

Upgrading Alkylation 236 251 251 251 251

Merchant Iso-Octane/ene

Catalytic Polymerization 5 5 5 5 5

Dimersol 3 3 3

Pen/Hex Isomerization 119 172 172 172 172

Reforming 687 515 522 534 601

Oxygenate Prod. MTBE -- FCC-based 9

MTBE -- Field Butane-based

MTBE -- Other

TAME

Hydrotreating Naphtha Desulf. 768 841 842 845 909

FCC Naphtha Desulfurization 22 647 647 647 643

Benzene Saturation 10 9 9 9 9

Distillate Desulfurization 890 934 937 945 952

FCC Feed Desulfurization 464 462 463 465 474

Merox (MTBE)

Resid Desulfurization

Hydrogen Hydrogen Plant (MM scf/d) 1,467 1,793 1,805 1,816 1,820

Fractionation Debutanization 217 208 209 209 210

Lt. Naphtha Spl. (Benz. Prec.) 91 266 266 266 266

Other Aromatics Plant 35 50 50 50 50

Benzene Extraction 1 1 1 1

Butane Isomerization 2 5 6 16 24

Lubes & Waxes 19 17 17 17 17

Solvent Deasphalting 16 16 16 16 16

Sulfur Recovery (K s tons/d) 3 4 4 4 4

Steam Generation (K lb/hr) 16,939 17,103 17,160 17,289 17,853

NEW CAPACITY

Upgrading Alkylation

Pen/Hex Isomerization

Hydrogen Hydrogen Plant (MM scf/d) 0 0

Fractionation Debutanization 6

Depentanization 43

Medium Naphtha Splitter

Light Gas Processing

Retrofitting Captive MTBE to Alkylate

Tier 2 Desulfurization 0 2 10 0

OPERATIONS

Operating Indices FCC Conversion (Vol %) 76.3 75.2 75.1 74.8 72.2

Reformer Severity (RON) 98.1 93.6 93.9 94.5 95.3

Charge Rates Fluid Cat Cracker11,145 1,141 1,142 1,147 1,169

Reformer1

700 574 576 583 649

FCC Olefin Max Cat. (%)

Fuel Use All Fuels (foeb) 255 269 272 276 287
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Table D-2: Operations and New Capacity

(K b/d, except as noted)

PADD 3

Study Case

Type of #1 #2 #3

2002 2010 RFG RFG+ RFG+

Calib- Refer- Low RVP Low RVP+

Process Process ration ence CG

USE OF EXISTING CAPACITY

Crude Distillation Atmospheric 7,038 8,387 8,385 8,390 8,390

Conversion Fluid Cat Cracker 2,742 2,744 2,750 2,697 2,748

Hydrocracker 455 575 575 575 575

Coking 1,001 1,199 1,200 1,201 1,218

Visbreaker 12

Upgrading Alkylation 518 581 581 581 581

Merchant Iso-Octane/ene

Catalytic Polymerization 10 11 11 11 11

Dimersol

Pen/Hex Isomerization 146 233 233 233 233

Reforming 1,352 1,231 1,212 1,271 1,370

Oxygenate Prod. MTBE -- FCC-based 72 0 0 0 0

MTBE -- Field Butane-based 69

MTBE -- Other 60

TAME

Hydrotreating Naphtha Desulf. 1,242 1,655 1,655 1,653 1,705

FCC Naphtha Desulfurization 77 1,506 1,506 1,506 1,506

Benzene Saturation

Distillate Desulfurization 1,951 2,458 2,458 2,458 2,458

FCC Feed Desulfurization 1,074 1,119 1,120 1,135 1,201

Merox (MTBE)

Resid Desulfurization 56 170 171 172 177

Hydrogen Hydrogen Plant (MM scf/d) 1,776 2,680 2,680 2,680 2,680

Fractionation Debutanization 511 542 542 542 542

Lt. Naphtha Spl. (Benz. Prec.) 126 192 192 192 192

Other Aromatics Plant 150 196 202 233 233

Benzene Extraction 21 10 10 10 10

Butane Isomerization 65 84 86 95 94

Lubes & Waxes 135 145 145 145 145

Solvent Deasphalting 200 200 200 200 200

Sulfur Recovery (K s tons/d) 10 13 13 13 13

Steam Generation (K lb/hr) 42,704 48,154 48,316 48,753 50,149

NEW CAPACITY

Upgrading Alkylation

Pen/Hex Isomerization

Hydrogen Hydrogen Plant (MM scf/d) 180 302

Fractionation Debutanization 0 0 0 52

Depentanization 291

Medium Naphtha Splitter

Light Gas Processing

Retrofitting Captive MTBE to Alkylate 3 5 4 7

Tier 2 Desulfurization 1 48

OPERATIONS

Operating Indices FCC Conversion (Vol %) 75.7 72.9 72.9 71.5 69.0

Reformer Severity (RON) 98.0 97.6 96.7 98.0 96.9

Charge Rates Fluid Cat Cracker12,685 2,797 2,800 2,837 3,003

Reformer1

1,380 1,261 1,276 1,296 1,433

FCC Olefin Max Cat. (%) 22 17 17 22 21

Fuel Use All Fuels (foeb) 667 772 782 799 828
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Table D-3a: Refinery Inputs1

(K b/d)

PADD 1 PADD 2 PADD 3 

Study Case Study Case Study Case

#1 #2 #3 #1 #2 #3 #1 #2 #3

2002 2010 RFG RFG+ RFG+ 2002 2010 RFG RFG+ RFG+ 2002 2010 RFG RFG+ RFG+

Calib- Refer- Low RVP Low RVP+ Calib- Refer- Low RVP Low RVP+ Calib- Refer- Low RVP Low RVP+

Inputs ration ence CG ration ence CG ration ence CG

Crude Oil 1,566 1,621 1,622 1,627 1,631 3,324 3,328 3,331 3,344 3,402 7,038 8,387 8,385 8,396 8,483

Gasoline Blendstocks 42 40 40 40 40 184 155 155 155 155

Natural Gas Liquids 42 40 40 40 40 139 110 110 110 110

Alkylate

PyGas 45 45 45 45 45

Oxygenates 63 77 77 77 77 85 198 198 198 198 37 405 405 405 405

MTBE 58

Ethanol 2 77 77 77 77 82 198 198 198 198 13 405 405 405 405

Methanol 3 3 24

Other Refinery Inputs 77 48 48 48 48 60 97 95 84 77 381 321 323 319 315

Iso-butane 23 38 36 25 21 7

Normal butane 4 3 3 3 6 8 4

Naphtha 1 33 56 56 56 56 30 25 25 25 25

Kerosene 2 2 2 2 2

Heavy Gas Oil 69 44 44 44 44 232 196 196 196 196

Residual Oil 7 4 4 4 4 110 92 92 92 92

Merchant Plant Inputs 155

Field Butanes 64

Butylenes 48

Methanol 44

Purchased Energy

Electricity (K Kwh) 5,867 6,107 6,193 6,222 6,270 15,038 16,552 16,695 16,871 17,302 39,190 47,835 48,335 48,960 50,322

Natural Gas (K foeb/d) 77 84 87 88 88 197 233 236 239 248 546 683 696 715 746

Total (ex. Purch En) 1,706 1,746 1,747 1,752 1,756 3,511 3,662 3,663 3,666 3,716 7,640 9,268 9,267 9,275 9,357

1 Includes inputs to merchant producers of MTBE
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Table D-3b: Refinery Outputs1

(K b/d)

PADD 1 PADD 2 PADD 3 

Study Case Study Case Study Case

#1 #2 #3 #1 #2 #3 #1 #2 #3

2002 2010 RFG RFG+ RFG+ 2002 2010 RFG RFG+ RFG+ 2002 2010 RFG RFG+ RFG+

Calib- Refer- Low RVP Low RVP+ Calib- Refer- Low RVP Low RVP+ Calib- Refer- Low RVP Low RVP+

Outputs ration ence CG ration ence CG ration ence CG

Total2 1,713 1,761 1,756 1,761 1,765 3,481 3,657 3,657 3,659 3,701 7,741 9,250 9,250 9,252 9,340

BTX 32 54 54 54 54 35 46 46 47 48 171 206 206 206 206

MTBE - Merchant 100

Ethane 24 23 23 23 23

Propane 38 37 36 37 37 92 80 80 82 84 224 232 232 234 237

Propylene 18 23 23 23 23 44 34 34 34 34 178 199 199 199 199

Butane/Butylene 3 15 16 16 17 2 30 10 35

Mixed C45s 5 5 8 7 50

Naphtha 18 17 17 17 17 38 34 34 34 34 174 253 253 253 253

Aviation Gas 5 5 5 5 5 10 11 11 11 11

Gasoline3 810 771 771 771 771 1,914 1,976 1,976 1,976 1,976 3,756 4,172 4,172 4,172 4,172

 Conventional 238 52 52 52 1,429 1,169 1,169 1,169 1,908 1,601 1,601 1,601 126

 7.8 RVP 82 154 154 196 341 341 819 930 930

 7.0 RVP 154 206 47 174 174 515 1,684 262 358 358 1,288 2,763

 RFG, ethanol blended 565 565 565 565 225 292 292 292 292 100 1,283 1,283 1,283 1,283

 RFG, MTBE 490 17 667

Jet Fuel 98 121 121 121 121 225 245 245 245 245 782 1,001 1,001 1,001 1,001

Distillate Fuel

 On -road diesel <0.05 wt% 261 664 1,168

 On-road diesel<0.0015 wt% 344 344 344 344 868 868 868 868 1,971 1,971 1,971 1,971

 Off-road diesel/Heating Oil 206 122 122 122 122 195 90 90 90 90 455 370 370 370 370

Unf. Oil to PetroChem 137 187 187 187 187

Carbon Black Feed 25 31 31 31 31

Residual Oil 90 103 103 103 103 57 58 58 58 58 260 318 318 318 318

Asphalt 121 129 129 129 129 190 204 204 204 204 132 131 131 131 131

Lubes & Waxes 18 19 19 19 19 19 17 17 17 17 135 145 145 145 145

Coke 11 9 9 9 9 74 70 70 71 73 265 299 299 300 304

Sulfur (s tons/d) 1.0 1.0 1.0 1.0 1.0 3.3 3.6 3.6 3.6 3.7 9.8 12.8 12.8 12.8 13.1

1 Includes outputs of merchant producers of MTBE

2 Excludes coke & sulfur

3 Includes production of gasoline blendstocks
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Table D-4a: Average Gasoline Properties -- PADD 1

Property Study Case 1: Study Case 2: Study Case 3:

2002 Calibration 2010 Reference RFG RFG+Low RVP RFG+Low RVP+CG

Octane & 7.8 7.0 MTBE 7.8 7.0 7.8 7.0 RFG/ Nat'l RFG/ Nat'l RFG/

Volume CG RVP RVP RFG Pool CG RVP RVP RFG Pool CG RVP RVP Nat'l Gas Pool CG Gas Nat'l Gas Pool Gas Nat'l Gas Pool

Property

RVP (psi) 8.7 7.6 6.8 7.4 9.7 7.6 7.0 7.3 9.7 7.6 6.8 7.2 9.7 6.8 6.8 7.0 7.1 6.8 6.9

Oxygen (wt%) 0.9 0.7 2.1 1.6 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5

Aromatics (vol%) 27.9 30.0 19.3 22.9 26.2 27.0 17.9 20.3 20.1 30.5 18.4 21.0 24.7 34.4 17.4 21.3 33.0 17.3 21.5

Benzene (vol%) 0.94 0.94 0.59 0.73 0.62 0.62 0.59 0.60 0.62 0.62 0.59 0.60 0.62 0.62 0.59 0.60 0.62 0.59 0.60

Olefins (vol%) 14.0 14.0 12.6 13.2 18.0 18.0 12.1 13.6 14.9 9.2 10.7 10.7 15.7 3.8 11.9 10.5 9.1 10.8 10.4

Sulfur (ppm) 217 300 102 156 30 30 30 30 17 5 4 5 18 4 5 5 4 5 4

E130 (vol% off) 9.3 7.9 8.2 8.5 11.0 8.0 7.1 7.6 11.4 6.5 7.1 7.2 9.7 5.4 7.1 6.9 5.8 7.0 6.7

E200 (vol% off) 45.3 41.1 47.0 45.9 42.6 41.6 47.6 46.1 53.1 43.8 44.6 45.0 50.8 45.4 43.9 44.7 45.7 44.0 44.5

E300 (vol% off) 75.1 75.0 83.6 80.2 72.4 73.9 82.3 79.9 81.3 73.4 80.2 78.9 78.3 76.5 79.4 78.8 75.4 79.9 78.7

Estimated DI1 1,185 1,220 1,147 1,165 1,207 1,220 1,151 1,169 1,100 1,213 1,180 1,181 1,134 1,195 1,187 1,185 1,195 1,185 1,188

En. Den. (MM Btu/bbl) 5.187 5.225 5.108 5.143 5.097 5.123 5.039 5.060 5.012 5.097 5.066 5.069 5.052 5.116 5.065 5.074 5.128 5.059 5.078

Emission Red (%)2

VOCs -1.5 10.3 28.8 28.1 28.0 28.0 28.1

NOx 0.3 -1.5 9.2 13.6 15.4 15.3 15.8

Toxics 14.3 14.5 35.5 33.7 33.6 33.7 34.0

Octane ((R+M)/2) 88.2 88.2 88.2 88.2 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1 88.1

Volume (K b/d) 238 82 490 810 52 154 565 771 52 154 565 771 52 154 565 771 206 565 771

1 ASTM Driveability Index; calculated using modeling results for E130, E200, & E300.

2 As estimated by reduced-form of the Complex Model in ARMS.
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Table D-4b: Average Gasoline Properties -- PADD 2

Property Study Case 1: Study Case 2: Study Case 3:

2002 Calibration 2010 Reference RFG RFG+Low RVP RFG+Low RVP+CG

Octane & 7.8 7.0 EOH MTBE 7.8 7.0 7.8 7.0 RFG/ Nat'l RFG/ Nat'l RFG/

Volume CG RVP RVP RFG RFG Pool CG RVP RVP RFG Pool CG RVP RVP Nat'l Gas Pool CG Gas Nat'l Gas Pool Gas Nat'l Gas Pool

Property

RVP (psi) 8.7 7.6 6.8 6.8 6.8 8.3 9.7 7.8 7.3 7.0 8.8 9.7 7.8 7.3 6.8 8.7 9.7 6.8 6.8 8.5 7.5 6.8 7.4

Oxygen (wt%) 1.5 0.4 0.7 3.5 2.1 1.6 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5

Aromatics (vol%) 26.7 37.1 31.0 18.7 18.0 26.8 23.0 8.0 32.2 16.0 20.2 19.9 22.8 24.9 16.3 20.3 22.8 18.5 16.0 20.7 23.2 16.0 22.1

Benzene (vol%) 1.37 1.37 1.37 0.82 0.82 1.30 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62

Olefins (vol%) 10.1 6.0 10.3 5.2 5.2 9.1 10.3 8.0 7.9 8.3 9.4 8.5 6.8 5.0 13.7 8.7 7.0 8.8 11.4 8.1 7.4 2.8 6.7

Sulfur (ppm) 350 84 350 200 170 304 30 30 30 30 30 26 20 20 5 21 23 5 5 15 4 5 4

E130 (vol% off) 9.7 5.1 5.0 6.7 8.5 8.7 10.8 9.1 5.9 7.3 9.6 10.9 8.1 6.6 7.5 9.5 10.1 8.0 6.7 9.1 7.0 7.6 7.1

E200 (vol% off) 46.7 40.4 49.9 52.0 52.0 46.8 53.1 53.4 42.9 44.0 50.9 53.2 45.7 46.8 50.2 50.9 55.1 43.9 44.1 50.5 49.5 41.9 48.4

E300 (vol% off) 79.5 79.4 78.0 88.4 90.7 80.6 77.8 90.2 91.3 88.4 82.7 83.2 85.7 78.1 79.6 82.7 85.7 76.4 80.4 82.5 80.7 85.2 81.4

Estimated DI1 1,158 1,220 1,159 1,100 1,085 1,157 1,115 1,074 1,156 1,153 1,117 1,094 1,148 1,174 1,142 1,118 1,075 1,195 1,184 1,122 1,144 1,179 1,149

En. Den. (MM Btu/bbl) 5.125 5.237 5.185 5.032 5.094 5.126 5.017 4.973 5.101 5.033 5.019 4.994 5.049 5.073 5.060 5.020 4.993 5.080 5.059 5.025 5.056 5.030 5.052

Emission Red (%)2

VOCs 1.3 14.4 17.2 28.1 28.1 28.0 29.9 28.6 28.0

NOx 0.0 0.4 7.2 9.4 9.6 16.3 14.1 16.0 18.3

Toxics 8.4 8.4 8.4 31.0 33.8 34.9 34.6 34.3 35.5

Octane ((R+M)/2) 88.9 87.8 87.8 87.8 87.8 88.6 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0

Volume (K b/d) 1,429 196 47 225 17 1,914 1,169 341 174 292 1,976 1,169 341 174 292 1,976 1,169 515 292 1,976 1,684 292 1,976

1 ASTM Driveability Index; calculated using modeling results for E130, E200, & E300.

2 As estimated by reduced-form of the Complex Model in ARMS.
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Table D-4c: Average Gasoline Properties -- PADD 3

Property Study Case 1: Study Case 2: Study Case 3:

2002 Calibration 2010 Reference RFG RFG+Low RVP RFG+Low RVP+CG

Octane & 7.8 7.0 EOH MTBE 7.8 7.0 7.8 7.0 RFG/ Nat'l RFG/ Export Nat'l RFG/

Volume CG RVP RVP RFG RFG Pool CG RVP RVP RFG Pool CG RVP RVP Nat'l Gas Pool CG Gas Nat'l Gas Pool CG Gas Nat'l Gas Pool

Property

RVP (psi) 8.7 7.6 6.8 6.8 6.8 7.9 9.7 7.6 7.0 6.8 8.1 9.7 7.6 7.0 6.8 8.1 9.7 6.8 6.8 7.9 8.7 7.3 6.8 7.2

Oxygen (wt%) 0.2 0.2 0.2 3.5 2.1 0.6 3.2 3.5 3.5 3.5 3.4 3.2 3.5 3.5 3.5 3.4 3.2 3.5 3.5 3.4 3.5 3.5 3.4

Aromatics (vol%) 26.9 29.0 35.0 20.0 20.0 26.5 24.6 21.5 26.0 16.0 21.4 26.0 13.9 16.5 22.0 21.2 17.9 27.6 20.6 21.7 29.9 24.2 16.2 21.9

Benzene (vol%) 1.00 0.94 0.56 0.60 0.58 0.87 0.62 0.62 0.62 0.60 0.61 0.62 0.62 0.62 0.60 0.61 0.62 0.62 0.60 0.61 0.62 0.62 0.60 0.61

Olefins (vol%) 12.8 11.5 15.0 8.5 12.5 12.5 11.0 7.0 9.9 10.2 9.8 12.1 10.2 13.2 2.5 8.8 6.8 11.6 4.3 7.5 0.9 5.4 11.3 7.1

Sulfur (ppm) 320 320 320 150 150 285 30 30 30 30 30 22 25 25 5 18 14 5 5 8 5 5 5 5

E130 (vol% off) 9.0 6.3 4.7 7.1 6.8 7.7 10.2 7.1 6.5 7.6 8.4 10.6 8.2 7.4 6.2 8.4 11.1 6.6 6.0 8.1 10.5 6.8 6.6 6.8

E200 (vol% off) 41.7 47.9 40.8 52.0 51.4 45.0 53.0 50.6 43.0 42.2 48.3 51.6 45.2 50.3 47.4 48.7 50.9 45.1 47.8 48.2 54.9 48.8 44.4 47.6

E300 (vol% off) 79.0 79.0 79.0 83.0 83.0 79.8 78.5 87.7 88.4 81.1 82.2 77.5 85.9 82.9 85.2 82.2 86.0 75.6 83.2 81.9 95.2 79.9 87.6 82.7

Estimated DI1 1,197 1,165 1,220 1,118 1,123 1,176 1,116 1,111 1,164 1,191 1,142 1,127 1,151 1,129 1,146 1,138 1,099 1,195 1,151 1,145 1,040 1,153 1,156 1,151

En. Den. (MM Btu/bbl) 5.179 5.226 5.264 5.051 5.086 5.175 5.029 5.023 5.082 5.061 5.042 5.061 4.988 5.030 5.050 5.038 5.014 5.099 5.033 5.046 5.127 5.066 5.020 5.054

Emission Red (%)2

VOCs 0.2 14.2 18.4 28.0 28.9 28.0 28.0 28.2 30.1

NOx -1.1 -1.8 0.0 10.3 7.4 15.5 15.8 16.1 16.3

Toxics 12.1 15.3 11.0 34.0 35.6 34.0 33.7 33.9 35.1

Octane ((R+M)/2) 88.0 88.0 88.0 88.0 88.0 88.0 87.7 87.7 87.7 88.2 87.9 87.7 87.7 87.7 88.2 87.9 87.7 87.7 88.2 87.9 87.7 87.7 88.2 87.9

Volume (K b/d) 1,908 819 262 100 667 3,756 1,601 930 358 1,283 4,172 1,601 930 358 1,283 4,172 1,601 1,288 1,283 4,172 126 2,763 1,283 4,172

1 ASTM Driveability Index; calculated using modeling results for E130, E200, & E300.

2 As estimated by reduced-form of the Complex Model in ARMS.
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Table D-5a: Average Gasoline Composition (Volume Percent) -- PADD 1

Study Case 1: Study Case 2: Study Case 3:

2002 Calibration 2010 Reference RFG RFG+Low RVP RFG+Low RVP+CG

Gasoline 7.8 7.0 MTBE 7.8 7.0 EOH 7.8 7.0 RFG/ Nat'l RFG/ Nat'l RFG/

Blendstock CG RVP RVP RFG Pool CG RVP RVP RFG Pool CG RVP RVP Nat'l Gas Pool CG Gas Nat'l Gas Pool Gas Nat'l Gas Pool

Total (%) 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0

C4s 7.4 5.4 3.5 4.8 8.0 4.2 1.0 2.1 6.4 2.0 1.2 1.7 6.2 0.5 1.3 1.5 0.5 1.5 1.3

Natural Gas Liquids

C5s & Isomerate 6.1 0.3 0.4 2.1 3.0 2.2 7.3 0.1 2.3 2.2 10.5 2.0 2.2 3.0 2.2

Raffinate 2.5 1.5 2.7 3.8 3.3 16.0 3.2 13.4 0.8 3.2 5.7 2.4 3.2

Naphthas (C5-250°) 10.7 13.2 11.1 12.1 7.3 9.4 9.2 3.2 7.7 9.1 8.4 12.5 20.2 5.0 8.5 17.3 5.3 8.5

Hydrocrackate 11.5 1.2 1.9 1.4 1.2 0.4 0.5 2.6 0.5 2.3 0.6

Alkylate 4.1 4.4 14.6 10.5 17.2 12.6 2.2 16.9 12.6 0.9 16.9 12.6 0.5 17.0 12.6

Merchant Alkylate

Iso-Octane/Octene

Poly Gas 3.7 5.5 1.6 10.6 4.0 1.5 6.7 1.3 8.8 3.7 1.3 5.0 1.3

FCC Naphtha 36.3 30.1 43.8 40.2 26.6 53.5 45.0 45.5 64.8 14.1 52.3 45.5 27.7 59.1 45.2 19.4 54.2 44.9

Reformate - Light 6.0 13.2 4.0 5.5 10.2 0.7 1.1 1.6 6.2 0.1 0.9 1.1 4.5 4.0 1.1 4.1 0.2 1.2

Reformate - Med&Hvy 21.7 25.5 6.6 13.0 22.5 17.7 7.7 10.7 42.0 6.9 13.5 19.9 44.6 5.0 13.9 35.2 6.4 14.1

Aromatics

Py Gas

Oxygenates

 MTBE 2.2 4.0 11.5 8.0

 TAME 0.8 0.2

 Ethanol 1.0 0.3 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0

Volume (K b/d) 238 82 490 810 52 154 565 771 52 154 565 771 52 154 565 771 206 565 771
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Table D-5b: Average Gasoline Composition (Volume Percent) -- PADD 2

Study Case 1: Study Case 2: Study Case 3:

2002 Calibration 2010 Reference RFG RFG+Low RVP RFG+Low RVP+CG

Gasoline 7.8 7.0 EOH MTBE 7.8 7.0 7.8 7.0 RFG/ Nat'l RFG/ Nat'l RFG/

Blendstock CG RVP RVP RFG RFG Pool CG RVP RVP RFG Pool CG RVP RVP Nat'l Gas Pool CG Gas Nat'l Gas Pool Gas Nat'l Gas Pool

Total (%) 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0

C4s 6.5 3.2 2.0 1.4 5.4 5.4 5.8 4.2 2.3 2.0 4.7 5.9 4.0 2.0 2.0 4.6 5.3 3.0 1.5 4.1 1.9 2.8 2.0

Natural Gas Liquids 2.4 4.0 2.2

C5s & Isomerate 5.8 7.9 16.0 4.0 6.0 14.3 0.6 8.6 10.6 7.3 11.7 8.6 13.9 2.3 8.6 10.1 8.6

Raffinate 1.3 2.4 0.4 2.0 1.2 1.8 0.6 0.5 1.2 1.9 0.9 1.2 0.4 6.2 1.3

Naphthas (C5-250°) 3.4 3.0 8.2 20.2 24.5 5.7 2.2 15.1 4.1 13.4 6.2 6.7 8.9 7.5 0.3 6.2 6.7 6.2 4.6 6.2 7.4 0.3 6.3

Hydrocrackate 3.4 2.6 2.7 3.8 4.2 4.1 3.2 2.9 4.6 5.0 2.3 3.3 4.1 4.3 3.5 1.3 16.6 3.6

Alkylate 11.7 1.4 23.9 25.9 11.9 2.7 39.6 26.5 12.4 10.2 14.6 14.2 17.2 12.4 6.1 22.4 19.8 12.4 9.5 29.0 12.4

Merchant Alkylate

Iso-Octane/Octene

Poly Gas 0.4 0.6 0.2 0.9 0.2 0.3 0.2

FCC Naphtha 37.9 23.8 41.3 18.7 16.7 34.1 36.7 27.0 27.1 27.1 32.7 29.7 20.9 16.8 68.1 32.7 23.3 41.1 56.2 32.8 35.4 14.6 32.3

Reformate - Light 7.0 26.9 8.6 9.7 8.0 9.4 4.8 52.2 11.2 9.1 10.3 17.2 9.1 14.6 0.6 1.9 9.1 9.0 9.9 9.1

Reformate - Med&Hvy 17.6 26.3 20.2 9.7 8.1 17.6 18.2 4.6 11.5 11.3 11.0 32.4 11.4 13.5 12.4 2.8 11.6 14.8 10.5 14.1

Aromatics 0.4 0.3 0.4 0.3 0.4 0.3 0.3 0.3

Py Gas

Oxygenates

 MTBE 0.1 2.2 3.7 11.5 0.5

 TAME

 Ethanol 4.2 10.0 4.3 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0

Volume (K b/d) 1,429 196 47 225 17 1,914 1,169 341 174 292 1,976 1,169 341 174 292 1,976 1,169 515 292 1,976 1,684 292 1,976
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Table D-5c: Average Gasoline Composition (Volume Percent) -- PADD 3

Study Case 1: Study Case 2: Study Case 3:

2002 Calibration 2010 Reference RFG RFG+Low RVP RFG+Low RVP+CG

Gasoline 7.8 7.0 EOH MTBE 7.8 7.0 7.8 7.0 RFG/ Nat'l RFG/ Export Nat'l RFG/

Blendstock CG RVP RVP RFG RFG Pool CG RVP RVP RFG Pool CG RVP RVP Nat'l Gas Pool CG Gas Nat'l Gas Pool CG Gas Nat'l Gas Pool

Total (%) 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0

C4s 6.5 3.9 2.2 2.1 2.0 4.7 5.4 2.7 2.0 2.0 3.5 5.6 3.0 2.2 1.5 3.4 6.8 1.2 0.5 3.1 7.7 1.8 1.1 1.8

Natural Gas Liquids 5.9 4.0 3.7 2.4 0.5 1.3 7.1 1.6 2.2 3.8 2.3 1.9 1.9 4.5 2.6

C5s & Isomerate 2.6 17.3 22.1 8.3 3.8 14.1 0.3 5.5 2.7 14.5 5.5 1.2 0.5 15.9 5.5 8.3 5.5

Raffinate 0.3 3.0 2.0 0.6 2.9 5.4 2.3 1.1 0.9 4.5 0.5 1.2 1.0 2.8 1.3 17.2 0.8 1.1

Naphthas (C5-250°) 0.7 13.7 3.7 3.2 4.0 5.2 11.2 9.4 14.3 9.7 9.0 6.8 2.3 14.8 9.7 13.6 3.5 11.4 9.8 19.0 12.3 3.1 9.7

Hydrocrackate 8.3 4.2 2.9 2.9 1.4 1.6 1.1 2.9 1.1 1.6 1.9 1.1 8.2 1.3 1.1

Alkylate 13.4 19.5 0.8 16.1 10.1 13.4 20.4 10.0 27.1 13.8 1.8 26.3 21.9 17.5 13.8 21.8 17.6 13.8 16.9 11.8 18.0 13.9

Merchant Alkylate

Iso-Octane/Octene

Poly Gas

FCC Naphtha 40.8 30.0 45.7 24.6 42.5 38.7 39.9 25.4 36.9 36.2 35.3 48.6 40.4 51.1 10.5 35.3 31.5 56.4 18.8 35.3 25.8 54.3 33.8

Reformate - Light 8.3 7.6 18.3 10.4 9.0 2.0 12.8 28.8 0.1 6.1 1.5 1.2 14.8 5.4 9.6 7.7 6.1 5.1 6.5 5.4

Reformate - Med&Hvy 14.8 21.9 2.9 4.5 6.0 13.7 18.3 9.3 6.7 11.2 17.6 2.6 3.5 12.3 11.4 5.3 9.5 18.1 10.6 20.4 13.5

Aromatics 0.6 0.1 2.9 0.9 21.5 0.4 0.9

Py Gas 11.8 14.0 1.2 3.5 1.1 3.5 1.1 3.5 1.1 9.4 2.6 1.1

Oxygenates

 MTBE 0.8 0.8 0.8 11.5 2.7

 TAME

 Ethanol 0.2 10.0 0.3 9.2 10.0 10.0 10.0 9.7 9.2 10.0 10.0 10.0 9.7 9.2 10.0 10.0 9.7 10.0 10.0 9.7

Volume (K b/d) 1,908 819 262 100 667 3,756 1,601 930 358 1,283 4,172 1,601 930 358 1,283 4,172 1,601 1,288 1,283 4,172 126 2,763 1,283 4,172
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Table D-6: Shadow Values of Complex Model Parameters & Driveability Index and Cost of Octane

PADD 1 PADD 2 PADD 3

Study Case Study Case Study Case

#1 #2 #3 #1 #2 #3 #1 #2 #3

2002 2010 RFG RFG+ RFG+ 2002 2010 RFG RFG+ RFG+ 2002 2010 RFG RFG+ RFG+

Gasoline Calib- Refer- Low RVP Low RVP+ Calib- Refer- Low RVP Low RVP+ Calib- Refer- Low RVP Low RVP+

Property Type ration ence CG ration ence CG ration ence CG

RVP (psi) CG -0.277 -0.744 -0.875 -0.932 -0.228 -0.430 -0.435 -0.437 -0.178 -0.339 -0.368 -0.523 -0.802

7.8 RVP -0.277 -0.744 -0.882 -0.228 -0.430 -0.435 -0.178 -0.339 -0.368

7.0 RVP -0.277 -0.228 -0.430 -0.435 -0.178 -0.339 -0.368

RFG -0.277 -0.744 -0.877 -0.934 -0.934 -0.228 -0.430 -0.435 -0.437 -0.818 -0.178 -0.339 -0.357 -0.522 -0.802

Nat'l Gas -0.934 -0.934 -0.437 -0.818 -0.522 -0.802

Oxygen (wt%) CG 0.000 0.000

7.8 RVP 0.000 0.000

7.0 RVP 0.000 0.000

RFG

Nat'l Gas

Aromatics (vol%) CG

7.8 RVP

7.0 RVP

RFG -0.017

Nat'l Gas

Benzene (vol%) CG -0.388 -0.666 -0.616 -0.838 -0.041 -1.023 -1.027 -1.029 -0.978 -1.041 -0.553 -1.217

7.8 RVP -0.388 -0.666 -0.623 -0.041 -1.023 -1.027 -0.978 -1.041

7.0 RVP -0.388 -0.041 -1.023 -1.027 -0.978 -1.041

RFG -0.388 -0.666 -0.619 -0.841 -0.841 -0.041 -1.023 -1.027 -1.029 -1.383 -0.978 -1.354 -0.864 -1.217

Nat'l Gas -0.841 -0.841 -1.029 -1.383 -0.864 -1.217

Olefins (vol%) CG -0.005

7.8 RVP -0.005

7.0 RVP -0.005

RFG -0.005

Nat'l Gas

Sulfur (ppm) CG 0.000 -0.005 -0.031 -0.032 -0.003 -0.003 -0.003 0.000 -0.002 -0.004 -0.002 -0.953

7.8 RVP 0.000 -0.005 -0.032 -0.003 -0.003 0.000 -0.003 -0.004

7.0 RVP 0.000 -0.003 -0.003 0.000 -0.003 -0.004

RFG 0.000 -0.005 -0.003 0.000 -0.387 -0.499 -0.953

Nat'l Gas -0.499 -0.953

E200 (vol% off) CG

7.8 RVP

7.0 RVP

RFG

Nat'l Gas

E300 (vol% off) CG

7.8 RVP

7.0 RVP

RFG

Nat'l Gas

ASTM Driveability CG

 Index 7.8 RVP

7.0 RVP

RFG

Nat'l Gas

Cost of Octane CG 1.0 1.1 1.2 0.5 0.5 0.5 0.4 0.4 0.4 0.9

 (¢/oct-gal) 7.8 RVP 1.0 1.1 0.5 0.5 0.4 0.4

7.0 RVP 0.5 0.5 0.4 0.4

RFG 1.0 1.1 1.1 1.1 0.5 0.5 0.5 0.7 0.4 0.7 0.7 0.9

Nat'l Gas 1.1 1.1 0.5 0.7 0.7 0.9

Note: A negative shadow value indicates that limits imposed on a Complex Model parameter constrained "refinery operations," i.e., a cost

 was incurred to meet the parameter limit. A positive shadow value on the oxygen paramter indicates the "refinery" would prefer

 to blend less oxygenate (and vice versa). The shadow value indicates the cost of changing a given parameter by one unit (percent point)

 on the last barrel of gasoline produced. Alternatively, it indicates the cost of making a small reduction for a given parameter that,

 when summed over all barrels of a given gasoline class, equals a change of one unit (percent point).
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Table D-7: Selected 2002 Calibration Results vs.

Reported Information

PADD 1 PADD 2 PADD 3

Reported Calibration Reported Calibration Reported Calibration

Crude Inputs (K b/d) 1588 1,566 3371 3,324 7147 7,038

Operations

Charge Rates (K/b/d)

 Fluid Cat Cracking 586 590 1169 1,145 2743 2,685

 Hydrocracking1

39 38 142 148 599 455

 Coking 77 77 328 319 1001 1,001

Operating Indices

 FCC Conversion 74.7 76.3 75.7

 Reformer Severity 96.9 98.1 98.0

Prices/Marginal Cost ($/b)2

Gasoline3

 Conventional 32.3 31.43 31.60 32.4 29.28

 Federal RFG 34.3 32.11 32.05 33.9 29.74

Distillates

 Jet Fuel 31.2 29.00 29.89 30.1 28.15

 On-road Diesel 30.3 28.93 30.00 29.4 28.12

 Off-road Diesel 29.6 28.69 29.56 28.6 27.63

Pool Gasoline Properties4

RVP (psi) 7.4 7.4 8.3 8.3 7.8 7.9

Oxygen (wt%) 1.6 1.6 0.5 1.6 0.6 0.6

Aromatics (vol%) 23.2 22.9 27.7 26.8 24.6 26.5

Benzene (vol%) 0.72 0.73 1.32 1.30 0.86 0.87

Olefins (vol%) 13.1 13.2 8.9 9.1 12.4 12.5

Sulfur (ppm) 152 156 323 304 270 285

E130 (vol% off) 7.0 8.5 8.0 8.7 7.0 7.7

E200 (vol% off) 47.1 45.9 45.8 46.8 45.0 45.0

E300 (vol% off) 82.2 80.2 81.3 80.6 79.6 79.8

DI 1156 1165 1164 1157 1,180 1,176

1 EIA reported charge rate includes charges to "lube hydrocracking."

2 In $2004.

3 Reported prices are for regular grade gasoline, whereas ARMS marginal costs are for pool gasoline. 

4 Reported pool gasoline properties are based on PADD-level data provided by EPA for 2003, except for E130,

 which is based on data from the Alliance "North American Fuels Survey," Summer 2002. DI is estimated by

 formula using E130, E200 & E300.
National Clean Gasoline

Emission Benefits

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Alliance of Automobile Manufacturers June 2009

Chapter 2 2BEmission Benefits of a National Clean Gasoline
National Clean Gasoline

Emission Benefits

2—ii

Alliance of Automobile Manufacturers June 2009

Emission Benefits of a National Clean Gasoline (NCG)

August 2008

for

Alliance of Automobile Manufacturers

by

Air Improvement Resource, Inc. 

47298 Sunnybrook Lane

Novi, Michigan

48374

248-380-3140
National Clean Gasoline

Emission Benefits

2—iii

Alliance of Automobile Manufacturers June 2009

CONTENTS

1.0 EXECUTIVE SUMMARY .................................................................... 2—1

2.0 INTRODUCTION............................................................................... 2—6

3.0 EMISSION INVENTORY METHOD........................................................ 2—8

3.1 Overview................................................................................................................... 2—8

3.2 Fuel Characteristics by PADD.................................................................................. 2—8

3.3 EPA and ARB Predictive Models............................................................................. 2—9

3.3.1 EPA Predictive Model ........................................................................................ 2—10

3.3.2 ARB Predictive Model........................................................................................ 2—10

3.4 Results from EPA MSAT Testing of Tier 2 Vehicles ............................................ 2—13

3.5 Model Used in This Analysis.................................................................................. 2—16

3.6 MOBILE6.2 Technology Fractions........................................................................ 2—16

3.7 Vehicle Activity Inputs........................................................................................... 2—17

3.8 MOBILE6 Inputs.................................................................................................... 2—18

4.0 RESULTS..................................................................................... 2—20

4.1 Emission Percent Changes...................................................................................... 2—20

4.2 Emission Inventory Changes .................................................................................. 2—21

4.3 Other Emission Reductions..................................................................................... 2—24

5.0 DISCUSSION ................................................................................ 2—25

REFERENCES........................................................................................ 2—28

APPENDIX. EMISSION CHANGES VS RVP ................................................ 2—29
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Emission Benefits

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Emission Benefits of National Clean Gasoline

1.0 Executive Summary

Background. Several programs directed at changing the formulation of gasoline have provided 

dramatic reductions in VOC, CO, NOx and SOx emissions in the last 14 years. First, Federal and 

California Phase 1 reformulated gasoline reduced emissions in the early to mid-1990s. California 

Phase 2 reformulated gasoline reduced emissions in California in 1996, and Federal Phase 2 

reduced emissions in non-California areas in 2000. The Tier 2/Low sulfur regulations 

implemented by EPA in 2004 further reduced sulfur levels to improve catalytic converter 

performance and further reduce SOx emissions. Finally, California is finalizing changes to its 

RFG3 regulations, which involve the implementation of a new Predictive Model for evaluating 

alternative specifications to the California RFG3 specifications and adding the effects of new 

exhaust emissions data and ethanol permeation effects into the model.

In spite of the contributions to improved air quality that the above reformulations have made, 

further changes in gasoline specifications could be very beneficial. They would reduce 

emissions further, helping the states to attain the newly adopted 8-hour ozone standards and 

other environmental objectives. Lowering the sulfur level, in particular, would enable new leanburn spark ignition engines to be used in the U.S., which can reduce greenhouse gas emissions 

relative to conventional spark ignition engines. The Alliance of Automobile Manufacturers 

initiated this study to estimate the emission benefits of a National Clean Gasoline NCG). 

The specifications for National Clean Gasoline include a 7 RVP summertime limit, a 10 ppm 

sulfur cap, and a 1250 driveability index cap. Driveability index would be estimated with the 

recently revised ASTM DI equation, which adds an ethanol term, and newly adopted cap of 

1250.F

19

F NCG would continue the 1 psi RVP waiver for NCG that replaces conventional gasoline, 

but would not continue the waiver in states with low RVP gasoline in the summer, whether or 

not they currently have a 1 psi waiver for ethanol. 

Methodology. In areas with Conventional gasoline, RVP levels would be reduced from about 

9.7 psi on average to just below 7 psi, and average sulfur levels would be reduced from about 30 

ppm to 5 ppm. In areas with low RVP gasoline (either 7.8 or 7.2 psi), RVP would also be 

reduced to just under 7 psi, and average sulfur to about 5 ppm. Finally, in RFG areas, RVP is 

already under 7 psi, so average sulfur would be reduced from just under 30 ppm to about 5 ppm. 

There would be small changes in other fuel properties, such as aromatics, olefins, and distillation 

properties (E200 and E300), as determined in a separate cost analysis conducted by MathPro, 

Inc. 

MathPro, Inc. estimated typical fuel properties that would occur in states in the part of the 

county generally east of the Rocky Mountain States (i.e., in Petroleum Administration Defense 

Districts 1-3) if NCG were implemented. We used the fuel property information for the 

Reference Case and for the NCG case from the MathPro report to estimate the emission benefits 

of NCG in PADDs 1-3. 

 

19 The Alliance stands behind its own Distillation Index (which uses a different correction factor than the ASTM 

index) and recommended cap of 1200 as a way to further reduce emissions but specified the ASTM equation and 

cap for NCG to minimize fuel production cost estimates performed in a separate analysis. 
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Emission Benefits

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Alliance of Automobile Manufacturers June 2009

The MOBILE6 model was used to estimate baseline exhaust and evaporative emissions for the 

on-road fleet for 2010, 2015, and 2020, and also the evaporative hydrocarbon benefits of lower 

volatility due to NCG. The California ARB Predictive Model was used with the MOBILEgenerated baseline inventories to estimate the exhaust emission benefits of NCG. This model was 

modified slightly from the default model released by the ARB in May 2008 to include the RVP 

term on exhaust emissions. We also performed an emission inventory sensitivity case, where we 

utilized emission testing performed by EPA as a part of the Mobile Source Air Toxics Rule on 

Tier 2 vehicles to develop fuel correction factors for Tier 2 vehicles. 

Emissions were estimated on a county-by-county basis, using mostly local inputs. Inspection and 

Maintenance programs were also included where applicable. We also estimated separate benefits 

for areas with conventional gasoline, low RVP gasoline, and reformulated gasoline (RFG). 

Results. NCG has a significant effect on evaporative HC and exhaust NOx emissions, as shown 

in the chart below. This chart shows the percent reductions for 2010, 2015, and 2020 for all three 

PADDs. Evaporative HC reductions range from 12%t o 19%, and exhaust NOx reductions range 

from 10% to 14%. Exhaust HC reductions range from 1% to almost 4%.

To show how the emission reductions compare with total on-road inventories, baseline and NCG 

inventories are shown in the two charts below. Total on-road HC and NOx are reduced 

significantly by NCG. These emission reductions would be important to states trying to meet the 

new, more stringent ozone ambient air quality standard adopted by the EPA. 
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Emission Benefits

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Alliance of Automobile Manufacturers June 2009

 
National Clean Gasoline

Emission Benefits

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Alliance of Automobile Manufacturers June 2009

We believe this emission inventory analysis is conservative. Our examination of the EPA MSAT 

Tier 2 vehicles showed that they were more sensitive to sulfur reductions than the ARB model 

indicates. If this higher sensitivity is included for Tier 2 (2007 and later fully phased-in Tier 2 

vehicles) vehicles, the emission benefits of NCG increase from the above. This is shown in the 

two charts below. 
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Emission Benefits

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Alliance of Automobile Manufacturers June 2009
National Clean Gasoline

Emission Benefits

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Alliance of Automobile Manufacturers June 2009

2.0 Introduction

Currently, 3 basic types of gasoline are used in non-California areas of the U.S. – conventional 

gasoline (CG), low RVP gasoline, and federal reformulated gasoline (RFG). Most reformulated 

gasoline contains ethanol and is required in urban areas with severe ozone non-attainment 

problems, as defined under the Clean Air Act. Areas with less severe ozone non-attainment 

problems have been allowed to adopt different fuel quality requirements, and many of those 

areas have implemented low RVP gasoline to obtain additional evaporative VOC reductions 

compared to conventional gasoline. Conventional gasoline is used in the remainder of the nation.

The use of ethanol in all gasolines is increasing, both with EPA’s 2005 Renewable Fuel Standard 

(RFS) requirements, and now with the adoption of the Energy Security and Independence Act of 

2007. 

In 2004, EPA implemented low sulfur gasoline requirements, which limited maximum sulfur 

levels to 80 ppm and reduced average sulfur levels to 30 ppm and below. This reduction in sulfur 

improves catalytic converter performance, thereby reducing a variety of emissions from the 

entire gasoline-powered vehicle fleet. In 2007, EPA reduced toxic emissions from gasolinepowered vehicles and non-vehicle evaporative emission sources by requiring benzene to be 

reduced to 0.6 wt %. 

In spite of the improvements in gasoline quality and emissions characteristics, additional 

improvements in gasoline can be identified that would further reduce emissions, and also reduce 

the number of different fuels used in the U.S. For example, the RVP of conventional gasoline 

could be reduced, thereby reducing evaporative VOC emissions. Sulfur levels could also be 

further reduced, reducing exhaust VOC, CO, and NOx emissions. F

20

F

For purposes of investigation, the Alliance of Automobile Manufacturers developed a proposed 

gasoline specification called National Clean Gasoline (NCG) and undertook to study the fuel’s 

emissions and costs. Estimated costs are contained in a companion report ―Refining Economics 

of a National Clean Gasoline Standard for PADDs 1-3‖ (hereafter referred to as the ―MathPro

report‖) and the emissions inventory analysis is contained in this report. [1] The key limits for 

National Clean Gasoline are shown below. 

 Sulfur cap: 10 ppm

 RVP cap: 7.0 psi

 Driveability Index cap: 1250

NCG is assumed to have a benzene level consistent with EPA’s recent Mobile Source Air Toxics 

Rule, or 0.62 % by volume. [2] In addition, it is assumed to contain 10% ethanol by volume. 

There are no additional requirements for aromatics, olefins, E200, or E300. The driveability 

index cap is intended to provide better national control over the entire distillation range, 

especially as the RVP is reduced to 7.0 psi.F

21

F In the above requirement, DI is estimated with the 

ASTM recently revised formula: 

DI = 1.5*T10 + 3*T50 + T90 + 2.403*ETOH Vol % [3]

 

20 With the implementation of the revised Predictive Model in 2010 in California, it is likely that sulfur levels in 

California will be reduced to around 10 ppm, or 1/3 of the remainder of the U.S.

21 ASTM limits gasoline DI to 1250, but the standard applies at the refinery gate, not at retail (i.e., after blending 

with ethanol), and not all states require the ASTM standard. The Alliance’s North American Fuel Survey conducted 

in the summer of 2007 showed several gasoline samples exceeding 1250 DI. 
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Emission Benefits

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Alliance of Automobile Manufacturers June 2009

Regarding the RVP waiver for ethanol blends in some states, NCG would continue the 1.0 psi 

RVP waiver for NCG that replaces conventional gasoline, but would not continue the waiver in 

states with low RVP gasoline in the summer, whether or not they currently have a 1 psi waiver 

for ethanol. The reason for not continuing a 1 psi waiver in states that have low RVP is the 

assumption that these states are implementing low RVP to achieve air quality benefits, and 

continuation of the waiver undermines these benefits. 

This report addresses the emission inventory benefits of NCG in PADDs 1, 2, and 3 of the U.S. 

F

22

F These three areas are shown in Figure 1, and comprise states in the eastern part of the U.S. 

Figure 1

PADDs 4 and 5 were not evaluated because PADD 5 is predominantly California, whose fuel is 

already very close to NCG, and PADD 4 includes the mountain states where there are few ozone 

nonattainment areas and relatively small gasoline volumes compared to the rest of the country. 

This study uses fuel parameter inputs developed from the MathPro report, and several different 

emission models to estimate emission inventory benefits of NCG. NCG is assumed to be fully 

implemented in 2010, and VOC and NOx emission benefits for on-road vehicles are estimated 

for the 2010, 2015, and 2020 calendar years. There would be additional emission benefits from 

off-road equipment and vehicles for this fuel, but these are not evaluated in this report. 

The remainder of this report is divided into the following sections:

 Section 3: Methods

 Section 4: Results

 Section 5: Discussion

 

22 PADD refers to Petroleum Administration for Defense District.
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Alliance of Automobile Manufacturers June 2009

3.0 Emission Inventory Method

3.1 Overview

Determining the emission benefits of NCG depends on having fuel characteristics for the states 

in the 3 PADDs for the reference case and for the control scenarios. This information is available 

from the MathPro report. 

In this analysis we estimated the baseline VOC and NOx emission inventories with the 

MOBILE6.2 model. Emission inventories are estimated for exhaust and evaporative VOC, and 

NOx, from all on-road gasoline vehicles except motorcycles. 

To estimate inventories for NCG, we estimated the evaporative VOC differences based on RVP 

changes using the MOBILE6.2 model. But the exhaust emission differences cannot be estimated 

with MOBILE6.2 alone because the MOBILE model does not accept the different fuel inputs 

and evaluate their effects on exhaust emissions, other than sulfur, RVP and oxygenates. F

23

F To 

estimate the effects of NCG on exhaust inventories, the ARB Predictive Model was used to 

estimate the percent differences in exhaust emissions, and the percent differences were applied to 

exhaust emissions estimated from MOBILE6.2.F

24

F The remainder of this section is divided into 

the following subsections:

 Fuel Characteristics by PADD

 EPA and ARB Predictive Models

 Results from EPA MSAT Testing of Tier 2 Vehicles

 Technology Fractions from MOBILE6.2

 Vehicle Activity Estimates

 MOBILE6 Inputs

3.2 Fuel Characteristics by PADD

The MathPro report developed the costs of a national clean gasoline. The report contains tables 

that describe the estimated characteristics of gasolines produced in PADDs 1, 2, and 3 under the 

reference case and NCG cases, based on refinery modeling. The report also contains tables that 

show the estimated volumes of fuels used in each PADD, and their sources (which PADD the 

gasoline came from). 

Table B-6b of the MathPro report shows the projected annual gasoline use and supply sources by 

region and type of gasoline. Tables D4a, D4b, and D4c show the average gasoline properties 

produced in each PADD for the 2010 Reference Case (baseline), and Study Cases 1-3. The 

emission inventory analysis only evaluated the Reference Case and Study Case 3 (full 

implementation of NCG).F

25

F For each PADD, we weighted the fuel properties produced by 

PADD in MathPro’s report by the volumes of fuel consumed in each PADD by their PADD 

location. The resulting fuel properties of fuel consumed by each PADD under the Reference 

Case and Study Case 3 are shown in Table 1. 

 

23 While only RVP, sulfur and DI are controlled under NCG, other properties such as aromatics, olefins, E200, and 

E300 also change under NCG, and these changes must be taken into account in the emissions analysis. 

24 The EPA Predictive Model was also evaluated, but the ARB Predictive Model was selected for this study. This is 

discussed further in this section. 

25 MathPro also evaluated two study cases which phased-in NCG, but for this analysis of emission inventory 

benefits, we wanted to consider only the fully phased-in NCG requirements. 
National Clean Gasoline

Emission Benefits

2—9

Alliance of Automobile Manufacturers June 2009

Fuel properties are shown for four regions for the reference case – conventional, 7.8 RVP, 7.0 

RVP, and RFG. Under NCG, the conventional, 7.8, and 7.0 RVP are converted to National 

Gasoline, and RFG is also modified to form a national clean RFG. As shown in the table, the 

biggest changes are in RVP and sulfur. For example, RVP in conventional areas in PADD 1 is 

reduced from 9.7 to 7.27, and sulfur is reduced from 30 to 4.77 ppm. The reductions in RVP for 

RFG areas are much smaller because gasoline that meets RFG requirements already has very low 

RVP to reduce VOC emissions. 

3.3 EPA and ARB Predictive Models

The NCG requirements reduce fuel volatility and sulfur levels, and also implement a DI cap. The 

MOBILE6.2 model can be used to evaluate the impacts of volatility changes on evaporative 

emissions. The model is also capable of evaluating sulfur changes, but the model includes a 

sulfur floor of 30 ppm, such that values that are input below 30 ppm will be reset to 30 ppm. As 

a result of this limitation and the fact that other fuel properties besides sulfur and volatility are 

changing, other models needed to be considered for evaluating the exhaust emission changes. In 

this analysis, we considered the use of an EPA Predictive Model a near-final version of the ARB 

Table 1. Weighted Average Properties of Fuels Used by PADD

PADD Scenario Fuel Type

RVP

(psi)

Oxy

(wt%)

Arom

(vol%)

Benz

(vol%)

Olef

(vol%)

Sulfur

(ppm)

E130

(%)

E200

(%)

E300

(%)

1 Reference Conventional 9.70 3.24 24.72 0.620 11.72 30.00 10.32 51.86 77.83

7.8 RVP 7.63 3.48 23.61 0.620 11.63 30.00 7.52 46.87 81.98

7.0 RVP 6.96 3.48 26.00 0.620 9.88 30.00 6.47 43.00 88.39

RFG 6.94 3.48 17.38 0.593 11.52 30.00 7.25 46.09 81.93

NCG Nat'l Gas 7.27 3.48 26.33 0.620 6.32 4.77 6.54 48.04 78.83

RFG/Nat'l Gas 6.80 3.48 16.99 0.593 10.96 4.70 6.91 44.14 82.12

2 Reference Conventional 9.70 3.45 23.33 0.620 10.74 30.00 10.75 52.53 77.56

7.8 RVP 7.75 3.48 14.66 0.620 10.53 30.00 8.61 49.95 85.57

7.0 RVP 7.17 3.48 29.49 0.620 8.76 30.00 6.15 42.94 90.01

RFG 6.97 3.48 16.00 0.617 8.54 30.00 7.37 43.73 87.44

NCG Nat'l Gas 7.43 3.48 24.29 0.620 7.22 4.20 6.85 49.04 80.08

RFG/Nat'l Gas 6.80 3.48 16.04 0.617 3.89 4.61 7.45 42.19 85.54

3 Reference Conventional 9.70 3.21 24.52 0.620 10.96 30.00 10.25 52.96 78.46

7.8 RVP 7.64 3.48 21.45 0.620 7.00 30.00 7.09 50.63 87.74

7.0 RVP 6.96 3.48 26.00 0.620 9.88 30.00 6.47 43.00 88.39

RFG 6.81 3.48 16.01 0.601 10.10 30.00 7.57 42.30 81.35

NCG Nat'l Gas 7.34 3.48 24.21 0.620 5.44 4.98 6.78 48.78 79.92

RFG/Nat'l Gas 6.80 3.48 16.24 0.601 10.95 4.98 6.67 44.31 87.53
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Predictive Model. We also evaluated the recent EPA MSAT testing on Tier 2 vehicles to see how 

it would compare to these models. 

3.3.1 EPA Predictive Model

AIR obtained an EPA Predictive Model spreadsheet from EPA. [4] The spreadsheet included the 

coefficients of several models that were developed by the EPA based on the CRC E-67 testing 

program. [5] EPA based the models on the results of this program because it was the testing 

program available at the time that EPA evaluated alternative predictive models. The CRC E-67 

testing program evaluated changes in fuel RVP, T50, and T90, but did not evaluate changes in 

sulfur levels below 30 ppm. Therefore, we would not expect this EPA Predictive Model to 

adequately reflect changes in emissions that would occur with low sulfur levels, but to confirm 

this expectation we evaluated the model further.

EPA fitted a number of different emission models through the E-67 data, and then averaged 

several of the best models for HC and NOx. We plotted VOC and NOx emissions versus sulfur 

level from the EPA combined Predictive Model, as shown in Figure 1. The figure shows very 

little change in emissions versus sulfur (the y axis scale is small). For example, reducing sulfur 

from 50 ppm to 10 ppm reduces THC by just over 0.8% and NOx by 0.6%. These small changes 

are not consistent with either the ARB Predictive Model or the MSAT data, as shown in later 

sections. Therefore, the EPA Predictive Model was not used in this analysis. 

Figure 1

3.3.2 ARB Predictive Model

California released proposed modifications to the Predictive Model in June 2007 and May 2008. 

[6,7] This followed approximately 3 years of work and stakeholder meetings in which the ARB 

added new emissions data, developed new analytical methods, and received much input, 

including additional analytical work from the stakeholders. This analysis uses the June 2007 

version of the Predictive Model. Before finalizing this report we compared the two versions of 
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the model to determine the effect that the later version of the model would have on estimated 

NCG benefits, and found that these benefits would increase slightly if the later version of the 

model were used. 

The ARB Predictive Model includes the following fuel parameter inputs:

 RVP

 T50

 T90

 Sulfur

 Aromatics

 Olefins

 Benzene

The model estimates percent changes in VOC, NOx, and toxics emissions in comparison to those 

of the California Phase 3 reformulated gasoline reference specifications. The Predictive Model is 

used by gasoline marketers to certify that alternative gasoline formulations will comply with the 

California Phase 3 regulation. 

Figure 2 shows VOC and NOx emissions vs sulfur for the ARB Predictive model and the EPA 

Predictive Model discussed earlier. The ARB Predictive Model shows that emissions are more 

sensitive to sulfur than the EPA Predictive Model. F

26

 

26 There are changes in emissions with other fuel properties as well, but these are not shown, as the primary effects 

are for sulfur and RVP. For further information on the effects of these fuel properties, please refer to the ARB 

Predictive Model report.
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Figure 2

The Predictive Model estimates emission percent changes in calendar year 2015 from emission 

percent changes by 3 different technology groups – Tech 3, Tech 4 and Tech 5 vehicles. The 

model year groups of these vehicles are as follows:

 Tech 3: 1981-1985 vehicles

 Tech 4: 1986-1995 vehicles

 Tech 5: 1996+ vehicles

For application in this study, we used the individual Tech group functions, rather than the 

aggregated Predictive Model output, because the aggregated model year output is only applicable 

for calendar year 2015, and this study evaluates from 2010 to 2020. This required the 

development of technology group fractions from the MOBILE6.2 model for this purpose. 

Section 3.6 shows these technology fractions as developed from MOBILE6.2.

The ARB PM needed one modification to be used in this analysis. The default ARB model does 

not include a term for the effect of RVP on exhaust emissions (the term occurs, but is ―zeroed 

out‖ in the model). The reason for this is that RVP values in California are in a very tight range 

around 7 RVP, and in that tight range, exhaust emissions are not expected to change. However, 

in non-California areas RVP in the summer can vary from 7 to 9 RVP. For this reason, we 

allowed the model to include the RVP term. No RVP interaction terms (such as RVP * sulfur, 

and RVP * T50) are present.F

27

F Appendix 1 shows a chart that illustrates how emissions change 

for RVP, and also compares the changes in exhaust emissions from the ARB PM to the MOBILE 

model for exhaust. 

 

27 The underlying RVP data used to develop the modified ARB model ranged from 6 to 10 psi.
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3.4 Results from EPA MSAT Testing of Tier 2 Vehicles

In preparation for implementing its Mobile Source Air Toxics rule, which was published in 

February of 2007, EPA conducted a vehicle test program with vehicles certified to the Tier 2 

emission standards, where the vehicles were tested on a range of several fuel properties. [8] 

The fuel properties varied in this testing program included RVP, sulfur, and benzene. 

For this part of the analysis, we developed a model that predicts emissions versus fuel sulfur and 

RVP, based only on the MSAT data, so that the response of the Tier 2 vehicles could be 

compared to the ARB model for Tech 3, Tech 4, and Tech 5 vehicles. In the following two 

figures, we have estimated the change for each vehicle in VOC and NOx emissions from the 

base sulfur value of 32 ppm to 6 ppm. Figure 3 for THC shows that 7 of the 9 vehicles show 

percent reductions of between 7% and 22% for reducing sulfur from 32 ppm to 6 ppm. Two 

vehicles show increases in THC emissions of 4% and 7%, respectively, but the average reduction 

is 11%. Figure 4 for NOx shows that all 9 vehicles experienced reductions with lower sulfur. The 

NOx reductions range from 10% to over 50% reduction, and the average reduction is 33%. 
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Figure 3

Figure 4
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Figures 5 and 6 show the percent changes in VOC and NOx emissions between 0 and 50 ppm 

sulfur for the ARB Predictive Model modified to include an RVP term, and the results of the 

MSAT data. The results show that the Tier 2 vehicles have the most sensitive response to 

reductions in sulfur levels. This is important because Tier 2 vehicles will dominate the light duty 

fleet in the 2015-2020 timeframe. 

Figure 5
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Figure 6

3.5 Model Used in This Analysis

For most of this study, we use the individual Tech group responses of the ARB Predictive Model 

to evaluate the emission differences due to changes in fuel parameters for NCG. However, we 

conduct one sensitivity analysis where we used the ARB Predictive Model for Tech 4 and Tech 5 

vehicles, and use the MSAT response for sulfur for fully phased-in Tier 2 (2007 and later) 

vehicles. The purpose of this case is to show the effects of the more Tier 2 vehicles on the 

results, if their emissions response is more sensitive to reduced sulfur levels, as indicated by the 

MSAT data. 

3.6 MOBILE6.2 Technology Fractions

The use of the ARB Predictive Model requires the development of technology fractions for the 

three ARB technology groups from MOBILE6.2 information. However, since Tech 3 vehicles 

include those of 1981-1985 model years, and since the first calendar year of evaluation is 2010 

and MOBILE only computes emissions for 25 model years, there is no need to estimate the Tech 

3 fractions. Using MOBILE6, technology fractions were estimated for 2010, 2015, and 2020 for 

Tech 4 and Tech 5 vehicles. These fractions are shown in Figure 7. 
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Figure 7

The figure shows that Tech 5 vehicles (1996+) dominate the 2010-2020 timeframe. 

3.7 Vehicle Activity Inputs

Vehicle miles traveled (VMT) by vehicle class (all gasoline classes individually except 

motorcycles) and I/M status was estimated for 2010, 2015 and 2020 utilizing the Clean Air 

Interstate Rule (CAIR) model inputs, and aggregating the VMT over each PADD area on a bycounty basis.F

28

F [9] VMT by PADD and I/M status is shown in Figure 8. 

 

28 The CAIR rule was a recent rule that EPA modeled that contain mobile modeling inputs.
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Figure 8

3.8 MOBILE6 Inputs

Temperatures – we used summer average minimum and maximum temperatures of 72F and 96F 

because this is the range of temperatures used by EPA to estimate the cost effectiveness of 

vehicle emission controls in a number of vehicle rulemakings. 

Speeds - Default MOBILE6.2 roadway types and speeds were utilized. 

Inspection and Maintenance Inputs – Using EPA’s National Mobile Inventory Model, (NMIM), 

AIR determined the counties that have I/M, and in each PADD, modeled I/M and non I/M areas 

separately. [10] Although there may be considerable variation in I/M programs throughout the 

regions, all I/M programs were modeled as ―enhanced.‖ The I/M program values are shown in 

Table 2. The table shows two I/M programs – one for 1996-2050 vehicles (I/M Program 1 OBD 

only) and one for 1995 and earlier (I/M Program 2). 
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Table 2. I/M Program Descriptions

Parameter I/M Program 1 I/M Program 2

Program Type OBD, Test Only IM240, Test Only

Calendar Years 2002-2050 1998-2050

Inspection Frequency Biennial Biennial

Model Years 1996-2050 1974-1995

Vehicles LDGV-LDGT4 LDGV-LDGT4

Stringency 20% 20%

Compliance 96% 96%

Waiver Rates 3% pre MY81, 3% MY81+ 3% pre MY81, 3% MY81+
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4.0 Results

This section presents the results of the inventory analysis. We discuss the percent changes in 

exhaust and evaporative emissions first, followed by the inventory impacts in tons per summer 

day. 

4.1 Emission Percent Changes

The emission percent changes produced by implementing NCG are shown in Figure 9. The 

figure shows the percent reductions for exhaust VOC, evaporative VOC, and NOx. The percent 

reductions are shown by PADD and for 2010, 2015, and 2020. 

The exhaust VOC and exhaust NOx benefits of NCG increase somewhat in each five-year 

increment between 2010 and 2020. The increase between 2010, 2015, and 2020 is due to the 

phase-out of Tech 4 vehicles with smaller benefits than Tech 5 vehicles. 

Evaporative percent benefits are slightly lower in 2015 than in 2010, but stay constant between 

2015 and 2020. On a percent basis, the evaporative benefits are the largest compared to exhaust 

emission reductions, ranging between 12% and 20% depending on the PADD. The NOx 

reductions range between 10% and 14%, and the exhaust VOC reductions range between 1% and 

4%. 

Figure 9
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4.2 Emission Inventory Changes

The emission inventory impacts by PADD and calendar year are shown in Figure 10. Total 

reductions for all 3 PADDS are also shown. Exhaust VOC impacts for the 3 PADD area are 

about 4 tons per day for all 3 years. Evaporative VOC impacts are 55 tpd in 2010, 39 tpd in 

2015, and about 30 tpd in 2020. NOx impacts are 90 tpd in 2010, 64 tpd in 2015, and 49 tpd in 

2020. 
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Figure 10

Figures 11 and 12 show the change in emissions for NOx and total VOC from the base case to 

the NCG case, both by PADD, for the total of the PADDs, and by calendar year. NCG provides 

very significant reductions in both total VOC and NOx, continuing out to 2020. These reductions 

would be very valuable to states trying to attain either the existing or recently tightened 8-hour 

ambient ozone standard
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Figure 11

Figure 12
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4.3 Other Emission Reductions

In addition to reducing VOC and NOx, NCG probably also reduces other pollutants, such as 

carbon monoxide (CO), various toxics species, and two greenhouse gases – methane and nitrous 

oxide (N2O). CO would be reduced because it is the improvement in catalyst efficiency with 

lower sulfur that reduces both exhaust VOC and NOx, and would reduce CO as well. The 

exhaust toxic species such as 1,3 butadiene and formaldehyde are usually estimated as a ratio to 

total exhaust VOC. If total exhaust VOC is being reduced with lower sulfur, then toxics would 

also be reduced. Finally, methane is also usually estimated as fraction of total exhaust VOC, so 

methane would be reduced, and N2O is fraction of total NOx, so if NOx is being reduced, then 

N2O is also being reduced. 
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5.0 Discussion

The previous section shows that the reduction in sulfur and RVP will significantly reduce VOC 

and NOx emissions from the on-road fleet, and continue to do so in the future with Tier 2 

vehicles. These results are dependent on several variables, including the accuracy of projected 

fuel property changes in different regions of the U.S., the accuracy of such inputs as the vehicle 

fleet composition and VMT and the accuracy of the emission estimates produced by the 

MOBILE model (for evaporative emissions) and the ARB Predictive Model (for exhaust 

emissions).

With regard to changes in evaporative emissions from MOBILE, these benefits are based on 

RVP tests on pre-enhanced evaporative vehicles. Enhanced evaporative vehicles which started 

with the 1996 model year, and Tier 2 evaporative vehicles with lower exhaust standards, which 

started in the 2004 model year, could be less sensitive to changes in RVP than MOBILE 

indicates because of the greater degree of control these vehicles have of evaporative emissions. 

This can probably only be resolved through testing. For the time being, we have to rely on 

MOBILE6’s predictions.

With regard to changes in exhaust emissions using the ARB Predictive model and the 

modifications made to enable modeling of RVP tailpipe effects, there is the normal level of 

uncertainty associated with the accuracy of any model. But the primary exhaust emission fuel 

property in this analysis is sulfur. Our examination of the available emission data indicates that 

the newest vehicle technologies are more sensitive to sulfur at levels below 30 ppm than older 

technologies, and so we conclude that the exhaust emission reductions estimated in this study are 

reasonable. And, as indicated in the next paragraph and plots, the case could be made that the 

reductions we have estimated here are too conservative. 

Our analysis of the MSAT data showed that Tier 2 vehicles appear to be even more sensitive to 

sulfur than the Low Emission Vehicles tested in earlier testing programs These low emission 

vehicles were used a foundation for the Tech 5 group in the ARB Predictive Model. We 

performed a sensitivity analysis to determine the effect of the higher sensitivity MSAT Tier 2 

vehicles, assuming that 2007 and later cars and LDTs would have sulfur effects like the MSAT 

Tier 2 vehicles instead of the ARB Tech 5 effects. The results are shown in comparison with the 

primary results in the previous section in the following two plots (VOC and NOx).
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Figure 13
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Figure 14

The results show that the VOC and NOx emission inventories decrease further from the primary 

case (emission benefits of NCG increase). If the MSAT Tier 2 vehicles better represent the 

effects of sulfur on late model vehicles, then the benefits of NCG as estimated in this study are 

conservative.
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References

1. ―Refining Economics of a National Clean Gasoline Standard for PADDS 1-3‖, for 

Alliance of Automobile Manufacturers, MathPro, October 5, 2007. 

2. Fact Sheet: Control of Hazardous Air Pollutants from Mobile Sources: Final Rule to 

Reduce Mobile Source Air Toxics, EPA420-F-07-017, February 2007.

3. ASTM D4814, Table 1, footnote C.

4. Personal communication with Megan Beardsley, EPA, October 2007.

5. ―Final Report, Effects of Ethanol and Volatility Parameters on Exhaust Emissions‖, CRC 

Project No. E-67, January 30, 2006.

6. 2007 Draft Predictive Model v3.0 (March 26, 2007), 

www.arb.ca.gov/fuels/gasoline/premodel/premodel.htm

7. California Procedures for Evaluating Alternative Specifications for Phase 3 Reformulated 

Gasoline Using the California Predictive Model, released May 1, 2008, 

www.arb.ca.gov/fuels/gasoline/premodel/premodel.htm.

8. ―Joint EPA-Automobile Industry Tier 2 Vehicle Fuel Effects Test Program, Final 

Report,‖ December 2006.

9. ―Clean Air Interstate Rule, Emissions Inventory Technical Support Document,‖ 4 March 

2005, US EPA. 

10. National Mobile Inventory Model, http://www.epa.gov/oms/nmim.htm
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Appendix. Emission Changes vs RVP

As indicated in Section 3.3, the ARB PM needed one modification to be used in this analysis. 

The default ARB model does not include a term for the effect of RVP on exhaust emissions (the 

term occurs, but is ―zeroed out‖ in the model). The reason for this is that RVP values in 

California are in a very tight range around 7 RVP, and in that tight range, exhaust emissions are 

not expected to change. However, in non-California areas RVP in the summer can vary from 7 to 

9 RVP. For this reason, we allowed the model to include the RVP term. No RVP interaction 

terms (such as RVP * sulfur, and RVP * T50) are present

The charts below show the percent change in exhaust emissions with RVP for the ARB 

Predictive Model with the RVP term not zeroed-out. We also show the estimated changes in a 

calendar year 2015 run of MOBILE6 under summertime conditions. The ARB model shows 

some exhaust HC reductions and minimal NOx reductions for reducing RVP. For comparison, 

the MOBILE model shows similar HC reductions and a slightly larger NOx reduction. The ARB 

PM model effects were used in the inventory analysis. 
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Appendix A

Alliance of Automobile Manufacturers June 2009

APPENDIX A. MathPro Inc.

UMathPro Inc. Capabilities

Overview 

MathPro Inc. is a consulting firm specializing in technical and economic analysis of the 

petroleum refining and related industries. The firm is recognized for sound, independent, and 

objective analysis of refining economics. 

The principals of MathPro Inc., David S. Hirshfeld and Jeffrey A. Kolb, have extensive 

experience in the analysis of refining technology and economics. They have carried out 

numerous studies – for public and private sector clients – of regulatory, economic, and technical 

issues affecting the refining industry in the U.S. and various parts of the world. 

The firm’s clients include: 

 Petroleum Companies and Industry Organizations – American Petroleum Institute; 

National Petrochemical and Refiners Association; Western States Petroleum Association; 

National Petroleum Council; Oxygenated Fuels Association; BP North America; 

ChevronTexaco; ExxonMobil; Tosco Corporation (now part of ConocoPhillips); Amoco 

Corporation; Irving Oil; Sun Company; Suncor Inc.; Plains LPG

 Chemicals and Bio-fuels Companies – Gevo, Inc.; Arkenol Inc.; ARCO Chemical 

Company; Lyondell Chemical Co.; Equistar Chemicals; Grace Davison

 Automobile Companies and Industry Organizations – Engine Manufacturers 

Association; Alliance of Automobile Manufacturers; Association of International 

Automobile Manufacturers; Canadian Motor Vehicle Manufacturers Association; Ford 

Motor Co.; American Honda 

 Consulting and Professional Service Firms – TIAX LLC; Cambridge Energy Research 

Associates; Abt Associates; Comcept, Inc.; Kilborn, Inc.; Riverstone Partners; Clean 

Fuels Clearing House; Clean Fuels Advisory Council;

 Government Agencies – U.S. Environmental Protection Agency; U.S. Departments of 

Energy and Treasury; California Energy Commission; Arizona Department of 

Environmental Quality; National Renewable Energy Laboratory; Ozone Transport 

Assessment Group (OTAG); Alberta Energy Research Institute; Environment Canada; 

British Columbia Ministry of Environment, Land, and Parks; and the World Bank.

Project Experience

MathPro Inc. has conducted studies for clients on a range of refining-related issues, including: 

 Refining values (in the U.S., Canada, and other countries) of a number of crude oils 

(including crude blends in the Strategic Petroleum Reserve) in various refineries;

 Effects on refining economics, under various economic scenarios, of refinery streams and 

blendstocks produced by suppliers outside the refining sector (e.g., ethanol, iso-butanol, 

higher oxygenates, iso-octane/iso-octene, pyrolysis gasoline);

 Refining costs and national costs of prospective ethanol mandates, under various 

economic scenarios; 
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 The Net Energy Value and the total production cost of corn ethanol, with current and 

prospective production technologies; 

 Effects on refining economics of new process units or technologies (e.g., for gasoline and 

diesel fuel sulfur control, resid upgrading, coke gasification, etc.); 

 Effects of changes in gasoline and diesel fuel specifications on refinery energy 

requirements and greenhouse gas emissions; and 

 Refinery energy use and CO2 emissions from processing various U.S., Canadian, and 

imported crude oils in different U.S. refining regions.

MathPro Inc. has conducted numerous studies for public and private sector organizations, 

analyzing the economic consequences to the refining industry of environmental regulations and 

other government programs bearing on gasoline and diesel fuel quality, including: 

 Federal and state ethanol mandates

 California reformulated gasoline (CARB 2, CARB 3, and CARB 3A) programs

 Gasoline toxics control (MSAT1 and MSAT2) programs

 Gasoline sulfur control (U.S., Canada, Europe)

 Diesel fuel sulfur control (U.S., Europe) 

 MTBE phase-out (state and federal levels)

 Federal reformulated gasoline (RFG1 and RFG2) programs 

 Federal oxygenated gasoline programs

 State gasoline programs and standards (including the Arizona CBG program) 

 8-hour ozone standard

 Driveability Index control proposals

 Vapor pressure (RVP) standards (U.S. EPA Phases 1 and 2)

 Lead phase-down (in the U.S. and various European countries) 

Many of these studies produced estimates of regulatory costs that were confirmed by the 

industry's operating results after the regulations took effect. 
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Appendix B

Alliance of Automobile Manufacturers June 2009

APPENDIX B. AIR IMPROVEMENT RESOURCE, Inc. 

3BAIR IMPROVEMENT RESOURCE, INC.

AIR IMPROVEMENT RESOURCE, Inc. (AIR) was formed in 1994 to provide engineering 

and consulting services in the area of mobile and stationary source emissions modeling and 

technology evaluation. AIR provides expert services on a broad spectrum of projects to national 

and international industries, associations, legal firms, and governmental agencies. AIR performs 

studies for a broad range of clients in the following areas:

 emission inventory modeling and analysis

 emission characterization, including the effect of fuel composition on emissions

 statistical analysis of emission data

 technology assessment

 analysis of fuel properties and the effects of different fuel properties on emissions

 development of fuel economy models and future fuel economy projections

 costs and cost-effectiveness of on-highway and off-highway vehicle engine/fuel-related 

emission regulatory controls

 health effects and exposure/risk assessment of air toxins analysis of ambient air data 

 emissions and air quality trends analysis

 analysis of Inspection and Maintenance (I/M) programs and program data

 meteorological and climatological research and consulting services 

 air quality plan development including U.S. State and Federal Implementation Plans

 air dispersion modeling and photochemical grid modeling

AIR was founded by Thomas L. Darlington, President, who has twenty-six years of experience 

with the automotive and engine industry in the field of mobile source emissions modeling, 

analyzing emissions data, fuels, and vehicle testing procedures. Other employees are shown 

below:

Steven Cadle, Ph.D. – 34 years at GM Research, expert in real world vehicle emissions, 

particulate emissions, testing programs, well-to-wheels emissions 

Jon Heuss – 34 years at GM, expert in the relationship of emissions to air quality, the technical 

basis for air quality and emission standards, and health-effects 

Dennis Kahlbaum – Professional Meteorologist, computer programmer, statistician, and analyst. 

Programmer of many emission inventory models. 

George Wolff, Ph.D. – 31 years at GM, Atmospheric Scientist, expert in air quality, climatology, 

greenhouse gas science. 

A business and contracts manager supports the senior staff of analysts.