## REFINING ECONOMICS OF A NATIONAL LOW SULFUR, LOW RVP GASOLINE STANDARD

A study performed for



## The International Council for Clean Transportation

by



## MathPro Inc.

P.O. Box 34404 West Bethesda, Maryland 20827

- 0404

October 2 5
, 20 11Refining Economics of National Low Sulfur, Low RVP Gasoline Final Report

October 2 5 , 20 11 i T A B L E O F C O N T E N T S

Executive Summary 1

1. Sulfur and RVP Standards Considered in the Analysis 6

2. Refinery Modeling Methodology 7 2.1 Cases Analyzed With the Refining Models 7 2.1.1 Calibration Cases (2010) 7 2.1.2 Baseline Cases (2015) 8 2.1.3 Study Cases (2015) 8 2.2 Key Elements of the Methodology 9 2.3 Representation of Capital Costs for Sulfur and RVP Control 1 2

3. Technical Considerations 1 4 3.1 Sulfur Control 1 4 3.2 RVP Control (Summer) 1 6

4. Results of the Analysis 1 8 4.1 Summary of Primary Results 1 8 4.2 Discussion of Results 2 1 4.2.1 Sulfur Control 2 1 4.2.2 RVP Control 2 2 4.3 Sensitivity Analysis 2 3 4.4 The Economic Effect of Increased Energy Density in the Gasoline Pool 2 4

5. Additional Comments 2 6 5.1 Maintaining Gasoline Production at Baseline Volumes 2 6 5.2 “Over

- Optimization” and “Under

- Optimization” 2 6 5.3 Cost Elements Developed in This Study Reflect Conservative Assumptions 2 7 5.4 Capabilities of Foreign Refiners Were Not Considered 2 8 5.5 Downstream Costs Were Not Considered 2 8
Appendix A: Detailed Results of the Refinery Modeling 2 9Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 1 

### E XECU TIVE 

### S UMMARY

In 2009, MathPro Inc. completed a study for t he Alliance of Automobile Manufacturers (Alliance) dealing with the technical and economic effects in the U.S. refining sector of the Alliance’s proposed federal standard for a national “clean g asoline” (NCG) for use throughout the United States (ex California). 1 The proposed NCG standard w as intended to augment the federal standard for reformulated gasoline (RFG) and to cover all special gasolines (“boutique fuels”) and conventional gasoline ou tside of the RFG areas.

More recently, other proposed new gasoline standards have been discussed, most notably lower sulfur and lower RVP standard s . A recent report issued by the American Petroleum Institute API) 2 addressed several such standards. The International Council for Clean Transportation (ICCT) retained MathPro to update and extend the 2009 NCG analysis to cover standards that EPA might consider in its forthcoming rule

- making on Tier 3 gasoline. The updat es involve the analytical methodology , modeling tools, and assumptions

. The extensions comprise modeling runs to assess the economics of proposed gasoline standards bearing on sulfur content and summer RVP

. This report delineates the technical approach for the present analysis and pres ents its findings

. Scope of the Analysis : Gasoline Standard s Considered

The analysis covers regional refining operations, summer and winter , in four refining regions: PADD 1, PADD 2, PADD 3, and PADD 4.

Table ES

- 1 shows the t hree prospective gaso line standards considered in th e analysis

.

Table ES-1: Gasoline Standards Considered

1 2 3 Type Comments Sulfur

Sulfur (wppm) 10 10 10 Avg. Summer and winter

RVP (psi) Max. All RVP standards apply to finished gasoline after Summer ethanol blending Conventional gasoline 9 8 Proposed new standard Low RVP gasoline 7.8/7.0 7.8/7.0 Existing standard, as required by local programs Federal RFG < 7 < 7 As needed for certification via the Complex Model Winter

-- -- Varies by region Property Gasoline

RVP Standards

1 Refining Economics of a National Clean Gasoline Standard for PADDs 1

- 3 ; submitted to the Alliance of

Automobile Manufacturers by MathPro Inc.; June 2008

2 Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline ; s ubmitted to the American Petroleum

Institute by Baker & O’Brien, Inc.; July 2011Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 2 The sulfur limit in Table ES

- 1 would apply to all gasoline: conventional gasoline (CG), low

RVP gasoline (LRVP), and federal reformulated gasoline (RFG). Of t he RVP limits in Table ES

- 1 , only the limit fo r CG would be a new standard; the RVP limits for LRVP and RFG a re the current standards . (Federal and California RFG have an effective RVP limit of about 6 .8 psi after ethanol blending. The ethanol RVP waiver does not apply to RFG .)

Other gasoline pro perty standards represented in the analysis are the same as in the 2009 Alliance analysis

– in particular, benzene content = 0.62 vol% average (consistent with MSAT2), and average Driveability Index ( DI ) = 1220 at the refinery (but including the 24 number adjustment established by ASTM to account for ethanol blending).

Technical Approach

We analyzed the refining economics of the proposed sulfur and RVP standard s by means regional refinery LP modeling, using MathPro’s proprietary refinery modeling syste m , ARMS

. W e applied four models, representing aggregate refining operations in PADD 1, PADD 2, and PADD 3, and PADD 4, respectively. 3 The target time period for the analysis was 201 5 ( summer and winter gasoline season s).

Using price and national volu me projections from AEO 20 11 (Reference Case) and recent MathPro studies , we developed regional (i.e., PADD

- level) projections of (1) d emand for and domestic refinery production of gasoline

– RFG, CG, and L RVP

– a nd other refined products and (2) regional aggregate crude oil slates for 2015

. The refinery modeling for each region encompassed 20 1 0 Calibration Case s (summer and winter) , 201 5 Baseline ( Reference ) Case s (summer and winter)
, and three 201 5 Study Cases (summer and winter)

– one for each of the three prospective standards s hown in Table ES

- 1

. Study Case 1 addresses only the 10 ppm sulfur standard (i.e., with no change in the Baseline RVP). Study Cases 2 and 3, respectively, address the 9 psi and 8 psi RVP standards for finished CG
, with the sulfur standard fixed at 10 ppm.

The Baseline and Study Cases represent essentially all finished gasoline as ethanol

- blended at 10 vol% (E10) ( with only minimal volumes of E85 sold in 2015).

All of the Study Cases represent the U.S. refining sector maintain ing regional and total U.S. gasoline production at the 2015 Baseline volumes. That is, the y represent the U.S. refining
sector meet ing the indicated sulfur and RVP standards without reducing gasoline out

- turns.

3 We did not consider PADD 5 in the analysis, because (i) most of the gasoline volume produced and consumed in

PADD 5 is produced in California and (ii) California’s gasolin e standards are more stringent than those considered here.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 3 Comparison of the results returned by the regional refining models for each Study case with those returned for the corresponding Baseline case yield ed estimates of the investment

r equirements and refining costs associated with the contemplated sulfur standard and with the contemplated RVP s tandards.

Where more than one reasonable assumption could be made regarding a particular study parameter, we strove to ma ke conservative choices, such as:

 A ll existing FCC post

- treaters would require revamping to meet the 10 ppm sulfur standard  Th e average capital investment ( CapEx ) for revamping the fleet of FCC post

- treaters is 50% of the CapEx for grassroots post

- treaters (even though some of the existing units may require no revamping)  The base CapEx for new process capacity in PADD 4 is 50% higher than that of the base (U.S. Gulf Coast) CapEx estimates used for the other PADDs, to reflect the small size of the PADD 4 refineries  The target rate of return on refinery investments is 10% after tax

T he study included a sensitivity analysis to assess the effects on the study’s findings of three key economic parameters in the regional refining models :

 T he capital investment required for revamping existing gasoline desulfurization capacity to meet the 10 psi sulfur standard (50%  30% of grassroots CapEx)  T he value of bu tane and pentane rejected from the summer gasoline pool to meet tighter RVP standards (gasoline blendstock value  fuel value)  R eturn on investment (10% after tax  7% pre

- tax)

Results of the Analysis

Table ES

- 2 shows the estimated total (PADDs 1, 2, 3, and 4) capital investment, annual refining cost, and per

- gallon refining cost associated with the 10 ppm sulfur standard, the 9 psi RVP standard, and the 8 psi RVP standard.

Table ES

- 2 shows two per

- gallon refining costs for Study Cases 2 and 3. One of these reflects the cost of sulfur control and RVP control allocated to all U.S. gasoline production, year

- round; the other reflects the indicated cost of sulfur control (1.4¢/gal) plus the cost of RVP control allocated only to the gasoline volume a ffected by the RVP standard: summer CG (about 30% of total annual U.S. gasoline production, but with significant regional variation).

The estimated investment, annual refining cost, and per

- gallon refining cost of meeting the 10 ppm sulfur standard ( St udy Case 1 ) are about $ 3.9 billion
, $ 1.5 billion , and 1. 4 ¢/gallon
, respectively.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 4 Table ES-2: Primary Results: Estimated Capital Investment and Refining Cost (PADDs 1-4)

Sulfur } Notes RVP }

Gasoline Volume (K b/d) 7,080 7,080 7,080
Capital Investment ($Bil) 3.9 4.2 5.2 Debutanization 0 0.23 0.27 Depentanization 0 0.00 0.21 Alkylation 0 0.05 0.13 FCC Naphtha Desulfurization 3.20 3.32 3.61 All Other 0.72 0.65 0.93
Annual Refining Cost ($MM/yr) 1.5 2.7 4.2 Capital Charge and Fixed Cost 1.00 1.13 1.31 C4/C5 Interseasonal Transfer 1 0.04 0.21 0.75 Refining Operations 2 0.49 1.38 2.15
Per-Gallon Refining Cost (¢/gal) 3 Entire Gasoline Pool 1.4 2.5 3.9 RVP-Affected Summer Gasoline 1.4 5.3 10.2
Energy Density-Related Savings (¢/gal) 4 0 0.2 0.6

Notes:

1 C4/C5 Interseasonal Transfer cost is the sum of inter-seasonal storage and transport costs for transferring

to the winter season C4 and C5 material rejected in the summer season to achieve RVP control.

2 Refining Operations cost includes catalysts and chemicals, changes in refinery inputs and outputs, and additional refinery energy use

and hydrogen consumption.

3 Per-Gallon Refining Cost for sulfur control (Case 1) applies to all U.S. gasoline, year-round, in all three cases.

Per-Gallon Refining Cost for RVP control (Cases 2 and 3) is incurred only in producing conventional gasoline in the summer. Cost of RVP control is allocated in two ways: to Entire Gasoline Pool and to the RVP-Affected Summer Gasoline only.

4 Energy Density-Related Savings is the national savings/(cost) associated with a change in the energy density (BTU/gal) of

gasoline produced under the contemplated standards, relative to the baseline energy density. Study Case 1 30 ppm  10 ppm 10 psi 2

10 psi  9 psi 10 psi  8 psi 3 10 ppm

The estimated investments and annual refining costs of meeting the 9 psi RVP standard and the 10 ppm sulfur standard ( Study Case 2 ) are about $ 4.2 billion and $ 2.7 billion , respectively. The estimated incremental cost of achieving the 9 RVP standard alone is 1.1¢/gal ( = 2. 5 ¢

– 1. 4 ¢) allocated across all U.S. gasoline production and 3. 9 ¢/gal (= 5.3 ¢

– 1. 4 ¢) allocated only to summer CG.

The estimated inve stments and annual refining costs of meeting the 8 psi RVP standard and the 10 ppm sulfur standard ( Study Case 3) are about $ 5

. 2 billion and $ 4

. 2 billion , respectively. The estimated incremental cost of achieving the 8 RVP standard alone is 2

. 5 ¢/gal (= 3

. 9 ¢

– 1. 4 ¢) allocated across all U.S. gasoline production and 8

. 8 ¢/gal (= 10.2 ¢

– 1. 4 ¢) allocated only to summer CG.

The sensitivity analysis indicates that (i) reducing the average CapEx for revamping gasoline desulfurization facilities (to 30% of grassroots) and (ii) reducing the return on investment (to 7% before tax) has the cumulative effect of reducing the estimated cost of sulfur control (alone) from 1.4¢/gal (as shown in Table ES

- 2) to 0.8¢/gal. Conversely, downgrading the value of rejec ted butane and pentane (to fuel value) significantly increases the estimated cost of RVP control.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 5 The line item Energy Density

- Related Savings in Table ES

- 2 denotes the estimated effect of the proposed gasoline standards on the energy density of the entir e gasoline pool and consequently on the national cost of gasoline consumption. This change accrues to consumers and not the refining sector.

All of these estimates apply to refining operations that meet the specified sulfur and RVP standards while maintaining U.S. and regional gasoline production a t the baseline values.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 6 

### 1. S ULFUR AND 

### RVP S TANDARDS 

### C ONSIDERED IN THE 

### A NALYSIS

Table 1.1 shows the three prospective gasoline standards considered in the analysis.

Table 1.1: Gasoline Standards Considered

1 2 3 Type Comments Sulfur

Sulfur (wppm) 10 10 10 Avg. Summer and winter

RVP (psi) Max. All RVP standards apply to finished gasoline after Summer ethanol blending Conventional gasoline 9 8 Proposed new standard Low RVP gasoline 7.8/7.0 7.8/7.0 Existing standard, as required by local programs Federal RFG < 7 < 7 As needed for certification via the Complex Model Winter

-- -- Varies by region Gasoline Standards Property RVP

The sulfur standard in Tab le 1.1 would apply to all finished gasoline: conventional gasoline (CG), low

- RVP gasoline (LRVP G ), and federal reformulated gasoline (RFG). This standard is l ess stringent than the proposed sulfur standard considered in the 2009 Alliance study (10 ppm
cap at the refinery)

Of the RVP limits in Table ES

- 1, only th ose for CG would be new; the RVP limits for L RVPG and RFG are the current standards. (Federal and California RFG have an effective RVP limit of about 6.8 psi after ethanol blending. The ethanol RVP waiver does not apply to RFG.)

T he proposed RVP limits shown in Table 1.1 a pply to finished gasoline, after ethanol blending. They represent reductions of 1 psi and 2 psi, respectively, from the current RVP standard for CG
, which is 10 psi after ap plication of the 1 psi ethanol waiver. For purposes of this analysis, t he contemplated standards apply to all conventional gasoline (CG), 4 but not to LRVP G or RFG. (Federal and California RFG already have a more stringent RVP standard: 7 psi with no etha nol RVP waiver. In practice, as

- produced RFG has RVP < 6.8.)

T he 9 RVP standard for finished, ethanol

- blended gasoline is less stringent than the proposed RVP standard addressed in the 2009 Alliance study ( 7 psi before application of the 1 psi ethanol RVP waiver )

. The 8 RVP standard is essentially the same as the RVP standard in the 2009 Alliance study. In contrast , t he RVP standard addressed in the recent study published by API is 7 psi with no ethanol waiver. This standard is considerably more str ingent, and therefore more costly to implement, than either of the RVP standard s shown in T able 1.1

.

4 However, for the 9 psi RVP standard (only), the analysis recognizes the existing low

- RVP CG areas.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 7 

### 2

. R EFINERY 

### M ODELING 

### M ETHODOLOGY

We analyzed the refining economics of the proposed sulfur and RVP standards by means of four refinery LP model s, rep resenting regional refining operations in PADD 1, PADD 2, PADD 3, and PADD 4, respectively. 5

We constructed the four refining models using MathPro’s proprietary refinery modeling system ( ARMS ), which includes a crude assay database, technical charact erizations of more than fifty refining processes, and representative blending properties of refined product blendstocks. Though developed from a common data base, the regional models are distinct in terms of aggregate refining process capacity, composite c rude oil slate, refinery inputs and outputs, and refined product specifications

. We developed and applied the four regional refining model s through a sequence of C alibration
, Baseline (or Reference )

, and S tudy cases. Each such case included summer and w inter components.
The target time period for the analysis was 2015 (summer and winter gasoline seasons).

2 .1 Cases Analyzed With the Refining Models

2.1.1 Calibration Cases (2010)

Consistent with our standard practice in studies of refining operat ions, our first step in applying the regional models was to calibrate each model to the corresponding regional refining operations in a prior time period

– in this instance, 2010 summer and winter. Well

- calibrated models provide assurance that subsequent uses of the models will adequately represent refining operations under alternative sets of requirements, such as refined product standards, and/or with different crude and product slates.

Calibrating a refining model involves adjusting some of the model’s internal technical coefficients

– such as yields from certain refining processes, blending properties of refinery streams, or process capacity utilization rates

– as needed so that solutions returned by the model closely approximate reported refining oper ations.

The reported 2010 regional refining operations to which we calibrated included crude oil throughput; feed rates to fluid cat cracking, delayed coking, and fluid coking; average gasoline properties (including octane, sulfur content, RVP, benzene content, and aromatics content); and

5 We did not consider PADD 5 in the analysis, because (i) most of the gasoline volume prod uced and consumed in

PADD 5 is produced in California and (ii) California’s gasoline standards are more stringent than those considered here.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 8 the marginal costs (shadow values) of producing the major refined product categories (gasoline, jet fuel, diesel fuel, and residual fuel).

Regarding the marginal costs of production returned by the models, the objecti ve of the calibration was to ensure that (1) the marginal costs of the various refined products bear the same general relationship to one another as do the reported market prices for these products, (2) the marginal costs of meeting various product specifi cations are reasonable, and (3) the marginal value of various intermediate refinery streams and blendstocks are reasonable in relation to product prices.

2

. 1. 2 Baseline Cases (2015)

T he next step wa s to establish 2015 summer and winter Baseline Cases f or each regional refining model. Solutions returned by the regional refining models for these cases constitute t he baseline values for th e analysis.

The Baseline Cases incorporate the primary r egulatory programs affecting gasoline and diesel fuel prope rties that are now in effect or are scheduled to be in effect by 2015. These i nclude (1) continuation of the 1 psi summer RVP waiver for CG and (2) nation

- wide implementation of

 T he Tier 2 gasoline sulfur standard (average sulfur level in gasoline < 30 ppm) ;  The MSAT 2 standard on toxic emissions from gasoline (average benzene levels in gasoline < 0.62 vol%) ; and  T he Ultra

- Low Sulfur Diesel (ULSD) standard (maximum sulfur level in on

- road and off

road diesel < 15 ppm)

To establish the Baseline cases, w e used projections of total U.S. refinery inputs and outputs for 2015 drawn from the Reference Case of EIA’s Annual Energy Outlook 2011(AE O 2011) and allocated these inputs and outputs to the various PADDs on the basis of recent PADD

- level data on refinery inputs and outputs published by the U.S. Energy Information Administration (EIA).

T he Baseline cases for each PADD embody the same regional crude slates as the corresponding C alibration cases, because we assumed that crude oil slates would not change si gnificantly between 2010 and 2015.

2

. 1. 3 Study Cases (2015)

Table 2.1 shows the Baseline and Study Cases analyzed.

Study Case 1 addresses only the 10 ppm sulfur standard (i.e., with no change in the Baseline RVP). Study Cases 2 and 3, respectively, address the 9 psi and 8 psi RVP standards for CG
, with the sulfur standard fixed at 10 ppm.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 9 Table 2.1: 2015 Baseline and Study Cases Analyzed

2015 Baseline 1 2 3 Type Comments Sulfur

Sulfur (wppm) 30 10 10 10 Avg. Summer and winter

RVP (psi) Max. All RVP standards apply to finished gasoline after Summer ethanol blending Conventional gasoline 10 9 8 Proposed new standard Low RVP gasoline 7.8 7.8 7.8 Existing standard, as required by local programs Federal RFG < 7 < 7 < 7 As needed for certification via the Complex Model Winter

-- -- Varies by region Gasoline 2015 Study Cases Property RVP

The winter portions of Study Cases 2 and 3 (the RVP cases) differ from one another in the volume of refinery inputs of light gases (C 4 and C 5 ) rejected by r efineries in the summer to meet the RVP standard and then stored for use in the winter.

Comparison of the results returned by the regional refining models for each Study case with those returned for the corresponding Baseline case yielded estimates of the investment requirements and refining costs associated with the contemplated sulfur standard and with the contemplated RVP standards.

2.2 Key Elements of the Methodology

 The Baseline and Study Cases represent virtually all finished gasoline as et hanol

- blended at 10 vol% (E10) (with only minimal production E85 )

.
 T he Study Cases represent the U.S. refining sector maintaining regional and total U.S. gasoline production at the 2015 Baseline volumes.

Desulfurization leads to s ome loss of gasoline yield and octane

. Debutanization and depentanization remove volumes of high

- octane blendstocks, particularly butane. T he analysis represents each regional refining sector replac ing all of the gasoline volume and
octane lost in sulfur control and in RVP control . The solutions returned by the regional refining models indicate the least

- cost set of actions for doing so.

Available options for volume and octane replacement include increasing crude runs, changing various refining operations (e.g., incre asing reformer severity, practicing C 5 alkylation), and investing in additional refining process capacity.

 The Baseline and Study Cases maintain regional refinery crude slates comparable to those in 2010.

 The summer and winter components of each Stud y Case interact in several ways :Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 10  Process unit capacity added in one season (usually the summer) season is available for use in the other season

. However, t he models represent the capital costs of additional capacity intended for use in only one season as being amortized entirely in th at season

. This places a high hurdle on investment in seasonal capacity.

 Butane and pentane volumes rejected by the refining sector for RVP control in the summer season are available in like volumes as inputs in the winte r season. The implicit sales prices of these rejected volumes in the summer reflect their marginal values as gasoline blendstocks in the winter (returned by the regional refining model s ) minus the estimated cost of inter

- seasonal transfer, comprising stor age , handling, transport, and interest costs.

 The estimated costs of inter

- seasonal transfer vary by region . T he estimates
, in ¢ /gal, are shown in Table 2. 2

.

Table 2.2: Estimated Costs of Inter-Seasonal Transfer (¢/gal)

PADD 1 PADD 2 PADD 3 PADD 4

47 41 33 64

These costs include the per

- gallon cost associated with construction of new sto rage capacity.

 Regional energy prices

– crude oil acquisition cost and natural gas price to industrial users

– in 2015 are estimated from EIA data on regional prices and AEO2011 forecast prices . (The estimated regional prices are shown in Appendix, Exhib it A

- 6).

 The regional models represent production of finished E10 gasoline s, comprising base blends (CBOBs and RBOBs) produced at the refinery and ethanol blend ed downstream of the refinery. Accordingly, the RVP limits represented in the model reflect ( 1) a safety margin in blending (to allow for measurement tolerances) and (2) ethanol’s estimated effect on blend RVP (which is > 1 psi in summer E10 and increases slightly with decreasing base blend RVP).

Table 2. 3 (next page) shows the RVP limits speci fied in the regional models for refinery

produced CBOBs and RBOBs in the summer and winter to accommodate ethanol’s RVP “up

- lift” plus a small safety margin.

 The winter RVP limits embodied in the various regional refining models were based on the averag e RVP s of finished winter gasoline at the retail level, as reported in the recent North American Fuels Surveys published by the Alliance of Automobile Manufacturers

 In the regional models’ representation of gasoline blending, blend RVP is computed using
t he RVP blending index (VPBI) method, with VPBI = RVP 1.2Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 11  The regional models represent Driveability Index (DI) using the ASTM definition:

DI ( o F) = 1.5*T 10 + 3.0*T 50 + 1.0*T 90 + 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 models include a uniform DI standard

– DI < 1250 (per

- gallon, in the field)

– represented as DI < 119 6 (average, at the refinery gate), where

119 6 = 1250

– 30 (safety margin)

– 24 (ethanol adjustment)

 Other gasoline property standards represented in the analysis are the same as in the 2009 Alliance analysis

– in particular, benzene content = 0.62 vol% average (consistent with MSAT2)

.
 T he models add refinery hydrogen production capacity (with purchased natural gas as feed ) to support the additional hydrotreating required for sulfur control. 6

6 This assumption is convenient for analytical purposes

. Many refineries would meet their requirements for

add itional hydrogen not by adding refinery capacity but rather by purchasing merchant hydrogen. However, the choice of hydrogen sourcing is not important to the analysis. Table 2.3: Representation of RVP Standards in the Regional Refining Models

RFG Comm ents

RVP standard (finished gasoline) 9 8 7 CG standards include 1 psi ethanol waiver

Blending safety margin 0.2 0.2 0.2 Ethanol's estimated effect on blend RVP 1.09 1.15 1.23

Refinery gate RVP limit 7.7 6.7 5.6 Specification set in the regional models

Comments

RVP target (finished gasoline) 14 13 12 Winter RVP target varies by region

Blending safety margin Not considered in the winter analysis Ethanol's estimated effect on blend RVP 0.66 0.74 0.82

Refinery gate RVP limit 13.3 12.3 11.2 Specification set in t he regional models

Notes:

1 Winter RVP targets are intended to denote an average of monthly RVP standards in a given region.

2 Safety margins are not considered in the winter, because RVP targets in each region are based on data captured

at the retail le vel. CG Summer RVP (psi)

Winter RVP (psi)Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 12 2.3 Representation of Capital Costs for Sulfur and R VP Control

Refiners will meet more stringent sulfur and RVP standards through some (refinery

- specific) combination of :

 Add ing new, “grassroots” process units

 Expand ing the throughput capacity of existing process units

 Re vamping (or re trofitting ) existi ng process units to enable operation at higher severity (e.g.,

more stringent sulfur control )

The regional refining models used in this study represent one of these investment routes for each process (e.g., revamp economics for existing FCC naphtha desulfurizers, grassroots economics for new FCC naphtha desulfurizers 7 ). We assume d that (1) the capital investment ( C ap E x ) 8 per unit of FCC post

- treating capacity added by expansions and revamps is 50% of the capital cost per unit of capacity (ISBL+OSB L) for a grassroots unit.

Eac h investment alternative is represented in terms of an estimated process

- specific capital cost ( ISBL+OSBL ) per barrel/day of capacity . These estimates represent the investment s required for capacity increments correspondin g to representative size units ( e.g., 40 K Bbl/day for FCC naphtha hydrotreating)

. (In practice, larger units would have lower per

- barrel capital costs; smaller units would have higher per

- barrel capital costs .) All capital costs are expressed in $2010.

Table 2. 4 summarizes capital investment factors in the regional refining models for a representative sub

- set of the refining processes involved in sulfur and RVP control. The regional models include analogous values for all refining processes represen ted.

The grassroots capital investments shown in Table 2.4 apply specifically to a U.S. Gulf Coast location. Table 2. 5 shows the regional multipliers used in the analysis to account for regional differences in capital costs for refinery projects.

In ad dition, for PADD 4, we increased the capital cost factors by 50% to reflect the adverse scale economies due to the small average size of the PADD 4 refineries.

7 New FCC naphtha desulfurizers would be required in those refineries that no w meet the 30 ppm sulfur standard

with FCC feed desulfurization alone.

8 For brevity, we use the term “ CapEx ” to denote capital investment.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 13 Table 2.4: Capital Cost Factors in the Regional Refining Models

Grassroots Capital Cost Purpose Process (ISBL+OSBL) Comments (K$/Bbl/day)

Sulfur Control FCC Naphtha Desulfurization 1.83 Grassroots and revamp investments, as appropriate FCC Feed Desulfurization 6.7 Not included in the analysis Hydrogen Production 43.3 Grassroots economics

RVP Control Fractionation: Debutanization 3.6 Grassroots economics Fractionation: Depentanization 0.44 Grassroots economics

Octane-Barrel Replacement Alkylation 12.1 Doubled and allocated to the summer season

Notes:

1 Grassroots capital costs are for a U.S. Gulf Coast location and are in $2010.

2 Grassroots capital cost for the hydrogen plant is in K$/foeb/day

.
3 Capital cost for Debutanization is in K$/Bbl butane removed

.

Capital cost for Depentanization is in K$/Bbl depentanizer feed

.

For estimating the per

- gallon capital charges associated with the investments in refining capacity, we used the following assumptions:

 Rate of return: 10% after tax 9  Operating life: 15 years  Depreciation schedule: 10 year double declining balance  Construction period: 3 years  Tax rate: 40 % (federal and state)

9 This rate of return typifies what refiners use when evaluating conventional refinery investment opportu nities.

EPA uses lower rates of return (e.g., 7% before tax) when estimating the “social” (national) costs of regulations

. Table 2.5: Investment Location Factors

PADD 1 1.5 PADD 2 1.3 PADD 3 1.0 PADD 4 1.4Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 14 

### 3. T ECHNICAL 

### C ONSIDERATIONS

This section discusses the technical routes represented in the regional refining models for achieving more stringent sulfur and RVP standards.

3.1 Sulfur Control

At present, all U.S. refineries p roduc e gasoline with an ave rage sulfur content of 30 ppm (the Tier 2 standard)

. I n a typical U.S. conversion or coking refinery, FCC naphtha is the primary source of sulfur in the gasoline pool

. It constitutes approximately 35% of the gasoline pool
, and by virtue of its volume and its sulfur content accounts for about 95% of the sulfur content of untreated gasoline. Consequently, the primary task in meeting a stringent gasoline sulfur standard is reducing the sulfur content of FCC naphtha. Meeting th e current 30 ppm standard
requ ires that the FCC naphtha have average sulfur content of **≈** 50 ppm. 10

U.S. refineries achieve this level of sulfur control by one of three means:

 FCC feed hydrotreating (“pre

- treating”) to reduce the sulfur content of FCC feed to a level sufficiently low that the FCC naphtha produced by the FCC unit has sulfur content of around 50 ppm (This requires a suitable crude slate and severe FCC feed hydrotreating.)

 FCC naphtha hydrotreating (“post

- treating”) to reduce the sulfur content of the FCC naphtha to about 50 ppm.

 A combination of pre

- treating and post

- treating.

Table 3.1 shows the number of gasoline

- producing U.S. refineries using each approach, by PADD, as well as the total FCC capacity of the refineries in each category.

Table 3.1: Distribution of FCC Pre-Treating and Post-Treating Capacity, by PADD

PADD 1 PADD 2 PADD 3 PADD 4 PADD 5 Total

Number of refineries with FCC units 9 24 38 13 14 98 Pre-treater and post-treater 1 3 19 1 7 31 Pre-treater only 0 8 5 4 4 21 Post-treater only 7 12 12 3 2 36 Neither one 1 1 2 5 1 10

Total capacity of FCC units (K Bbl/day) 610 1,179 2,920 175 816 5,700 Pre-treater and post-treater 48 286 1631 19 475 2,459 Pre-treater only 0 316 319 57 230 922 Post-treater only 497 555 908 53 90 2,103 Neither one 65 23 62 46 21 217

10 Meeting the 30 ppm standard also requires desulfurization of other sulfur

- containing gasoline blendstocks (such as

natural gasol ine, straight run naphtha, and coker naphtha).Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 15 Table 3.1 , deri ved from the most recent Oil & Gas Journal and EIA surveys of U.S. refining capacity, indicates that t he majority of U.S. refineries use post

- treating, either alone or in combination with pre

- treating. 11

Producing gasoline with average sulfur content of 10 ppm (the proposed standard) requires reducing the average sulfur content of FCC naphtha to **≈** 10 ppm. In general, t h ere are th ree prospective routes for doing so , all of which are represented in the regional refining models

.
 Revamp an existing FCC feed hydrotreater (“pre

- treater”) to reduce the sulfur content of FCC feed to a level sufficiently low that the FCC naphtha produced by the FCC unit has sulfur content of around 10 ppm.

 Revamp an existing FCC naphtha hydrotreater (“post

- treater”) to reduce the sulfur content of the FCC naphtha to about 10 ppm.

 Install a new, grassroots FCC naphtha hydrotreater to reduce the sulfur content of the FCC naphtha to about 10 ppm.

Each of these require s additions to hydrogen supply, refinery energy supply, su lfur recovery facilities
, and off

- sites.

The r efineries that now meet the Tier 2 sulfur standard with post

- treating (with or without pre

treating) would most likely follow the second route: revamp the existing post

- treater

. 12

We understand that many of the FCC naphtha hydrotreaters installed to meet the Tier 2 sulfur standard are already capable of producing treated FCC naphtha with sulfur content < 10 ppm. Only those u nits that do not have this capability would require revamping. However, to be

co nservative, w e assumed that all existing FCC naphtha hydrotreating capacity would require revamping to meet the 10 ppm standard.

The r efineries that now meet the Tier 2 sulfur standard solely with pre

- treating (i.e., no post

treating) could adopt eithe r the first or the third route : revamp the existing pre

- treater to further reduce the sulfur content of the FCC feed or install a grassroots post

- treater

. We assumed that refineries now meeting the Tier 2 sulfur standard solely with pre

- treating would ado pt the third route: install a grassroots post

- treater.
If the refinery’s sole focus is on gasoline sulfur control 13

, then installing a grassroots post

treater is likely to be the less costly route , in terms of both investment and operating cost

.

11 Table 3.1 shows 10 refineries meeting the 30 ppm standard with neither pre

- treating nor post

- treating. This likely

reflects mis

- r eporting of process capacity.

12 We assumed that all refineries report ed as having neither FCC pre

- treating or post

- treating capacity have post

treating capacity.

13 That is, gasoline sulfur control a s opposed to controlling gasoline sulfur in conjunction with improving FCC

performance and/or reducing refinery emissions of S Ox.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 16 The req uired post

- treater would (1) be smaller than the FCC pre

- treater (because it would process only FCC naphtha rather than FCC feed), (2) have lower per

- barrel capital cost than the FCC pre

- treater, and (3) require less additional hydrogen and e nergy to meet the sulfur standard

. Using these criteria and the data on FCC post

- treating capacity shown in Table 3.1 , we estimated the number of refineries that would likely add grassroots post

- treating capacity and the number likely to revamp existing units , as wel l as the total associated FCC capacity in each category, by PADD

. These estimates are embodied in the regional models.

3.2 RVP Control (Summer)

Refiners can reduce summer gasoline RVP from current levels to the levels considered in this analysis by se veral routes, either alone or in combination (depending on the RVP standard, refinery crude slate, and refinery configuration )

. T he most economical route in most situations would be to first increas e the scope and extent of debutanization, to reduce the b utane content of the gasoline pool a s much as possible
, a nd then

– if necessary

– supplement debutanization with depentaniz ation of a limited number of refinery streams (primarily light FCC naphtha and straight run naphtha , but also alkylate, isomerate, an d light hydrocracked naphtha )

. In general, r educing finished gasoline RVP to 9 psi or 8 psi (corresponding to about 7.7 psi and 6.7 psi, respectively, before ethanol blending) should be feasible in m any refineries through enhanced debutanization alone, without depentanization or other measures

. However, reducing finished gasoline RVP to 7 psi (corresponding to about 5.6 psi before ethanol blending)

– as is

now required in federal and California RFG

– would likely require depentanization ( as refiners’

ex perience in producing federal and California RFG indicates )

. Because of the tight specification on the pentanes content of butane sold as LPG or petrochemical feedstock, the C 4 /C 5 separation in debutanizers must be performed so as to leave

some C 4 s in t he C 5 + material going to the gasoline pool. However, suitably upgrading refinery debutanization faci l ities and l ight ends recovery systems to sharpen the C 4 /C 5 separation can reduce the butane content of the gasoline pool to < 1 vol%, without degrading th e quality of product butane. This approach involves (1) modifying debutanizers to take more pentane overhead at the processing units, thereby reducing the butane content of the debutanized streams, and (2) sending the debutanizer overhead streams to a refin ery light ends plant designed to make a sharp C 4 /C 5 separation. The butane

- free C 5 stream can be blended to gasoline or segregated for other dispositions.

Then, d epentanization can be added to remove much of the residual butanes as well as larger volumes of pentanes, as may be needed to meet the specified RVP standard. Residual C 4 material can be removed from the depentanizer overhead, and the stabilized C 5 stream can have various dispositions (including inter

- seasonal transfer)

.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 17 Reducing g asoline RVP may require further changes in refinery operations. For example, it may require rejecting some volume of heavy gasoline components to the distillate fuel pool, in order to maintain compliance with the gasoline DI standard. In addition, it may involve increasing alkylate production to replace the gasoline volume and octane lost as a result of further debutanization and depentanization.

The alternative dispositions of C 4 s ( and possibly C 5 s ) removed from the summer gasoline pool include:

 S toring them, either at the refinery or a remote storage facility, for use in the winter season (or, equivalently, selling them to a third party in the summer and purchasing them in the winter);

 Using them as alkylation feed, with suitable investment in ex panding and/or revamping the alkylation unit;

 Using them as hydrogen plant feed, to displace purchased natural gas; and

 Using them as refinery fuel, or s elling them at a distressed price level approximating fuel value )

.

The first option, inter

- seasona l transfer
, implies that butane and pentane ( if any ) removed and stored in the summer season become refinery inputs, in like volumes, in the winter season. Refineries would have an economic incentive to practice inter

- seasonal transfer if the marginal val ues of the butane and pentane in the winter are greater than the sum of ( 1 ) the cost of inter

seasonal transfer and (2) their value in the summer in alternative uses (e.g., as refinery fuel)

. The marginal values of butane and pentane generally are highe r in the winter than in summer because of the relaxed RVP standards in the winter. B utane and pentane can be used in the winter to maintain gasoline and other refined product out

- turns with reduced crude through

- put and other cost

- reducing changes in refi nery operations.

Each refinery would face its own set of circumstances

– geographic and economic

– that would influence its disposition of choice for butane (and possibly pentane) removed from the summer gasoline pool. For purposes of this study, we assu med that refineries would choose storage and inter

- seasonal transfer. (However, we conducted a sensitivity analysis to assess the effects of selling the C 4 s and C 5 s at fuel value.)Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 18 

### 4. R ESULTS OF THE 

### A NALYSIS

4.1: Summary of Primary Results

Table 4.1 shows the estimated capital investment, annual refining cost, per

- gallon refining cost, and energy density

- related savings for each Study Case.

Table 4.1: Primary Results: Estimated Capital Investment and Refining Cost (PADDs 1-4)

Sulfur } Notes RVP }

Gasoline Volume (K b/d) 7,080 7,080 7,080
Capital Investment ($Bil) 3.9 4.2 5.2 Debutanization 0 0.23 0.27 Depentanization 0 0.00 0.21 Alkylation 0 0.05 0.13 FCC Naphtha Desulfurization 3.20 3.32 3.61 All Other 0.72 0.65 0.93
Annual Refining Cost ($MM/yr) 1.5 2.7 4.2 Capital Charge and Fixed Cost 1.00 1.13 1.31 C4/C5 Interseasonal Transfer 1 0.04 0.21 0.75 Refining Operations 2 0.49 1.38 2.15
Per-Gallon Refining Cost (¢/gal) 3 Entire Gasoline Pool 1.4 2.5 3.9 RVP-Affected Summer Gasoline 1.4 5.3 10.2
Energy Density-Related Savings (¢/gal) 4 0 0.2 0.6

Notes:

1 C4/C5 Interseasonal Transfer cost is the sum of inter-seasonal storage and transport costs for transferring

to the winter season C4 and C5 material rejected in the summer season to achieve RVP control.

2 Refining Operations cost includes catalysts and chemicals, changes in refinery inputs and outputs, and additional refinery energy use

and hydrogen consumption.

3 Per-Gallon Refining Cost for sulfur control (Case 1) applies to all U.S. gasoline, year-round, in all three cases.

Per-Gallon Refining Cost for RVP control (Cases 2 and 3) is incurred only in producing conventional gasoline in the summer. Cost of RVP control is allocated in two ways: to Entire Gasoline Pool and to the RVP-Affected Summer Gasoline only.

4 Energy Density-Related Savings is the national savings/(cost) associated with a change in the energy density (BTU/gal) of

gasoline produced under the contemplated standards, relative to the baseline energy density. Study Case 1 30 ppm  10 ppm 10 psi 2

10 psi  9 psi 10 psi  8 psi 3 10 ppm

Table 4.1 shows one estimated per

- gallon refining cost for Study Case 1 because the cost of meeting the 10 ppm sulfur standard would apply to all U.S. gasoline considered in this study (i.e., production in PADDs 1, 2, 3, and 4), year

- round. Table 4.1 shows two per

- gallon refining costs for Study Cases 2 and 3. One of these reflects the cost of sulfur control and the cost of RVP control allocated to all U.S. gasoline production; the other is the sum of the per

- gallon cost of RVP control (1.4¢/gal) plus the cost of RVP control allocated only to the gasoline volume affected by the RVP standard: summer CG. (Summer CG constitutes about 30% of total annual U.S. gasoline production, but this share varies from region to region

– smallest in PADD 1, largest in PADD 4.)Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 19 The estimated investment, annual refining cost, and per

- gallon refini ng cost of meeting the 10 ppm sulfur standard ( Study Case 1 ) are about $ 3.9 billion
, $ 1.5 billion , and 1. 4 ¢/gallon
, respectively.

The estimated investments and annual refining costs of meeting the 9 psi RVP standard and the 10 ppm sulfur standard ( Study Case 2 ) are about $ 4.2 billion and $ 2.7 billion , respectively. The estimated incremental cost of achieving the 9 RVP standard alone is 1.1¢/gal (= 2.5¢

– 1.4¢) allocated across all U.S. gasoline production and 3. 9 ¢/gal (= 5.3¢

– 1.4¢) allocated only to

s ummer CG.

The estimated investments and annual refining costs of meeting the 8 psi RVP standard and the 10 ppm sulfur standard ( Study Case 3) are about $ 5

. 2 billion and $4. 2 billion , respectively. The estimated incremental cost of achieving th e 8 RVP standard alone is 2

. 5 ¢/gal (= 3.9¢

– 1.4¢) allocated across all U.S. gasoline production and 8

. 8 ¢/gal (= 10.2¢

– 1.4¢) allocated only to summer CG.

The per

- gallon costs shown in Table 4.1 are the result of dividing the estimated annu al refining cost by the total annual U.S. gasoline production in PADDs 1, 2, 3, and 4. The cost of meeting the 10 ppm sulfur standard (Study Case 1) would apply to all U.S. gasoline considered in this study (i.e., production in PADDs 1, 2, 3, and 4), year

- round. However, t he cost of meeting the RVP standards (Study Cases 2 and 3) would apply to CG only, not to LRVP G and federal RFG, and only for the summer season. To highlight this point, Table 4.1 shows the estimated total annual cost of RVP allocated i n two ways: across the total annual volume of all gasoline produced in PADDs 1, 2, 3, and 4, year

- round and across only the summer volume of CG.

The line item Energy Density

- Related Savings in Table 4.1 denotes the estimated effect of the proposed gasoline standards on the energy density of the entire gasoline pool and consequently on the national cost of gasoline consumption. Removing C 4 and C 5 volumes from the gasoline pool to meet more stringent RVP standards leads to an increase in the energy density of the complying gasoline, which translates directly into a corresponding change in vehicle fuel economy. Hence, an increase in the gasoline pool’s energy density means a decrease in total gasoline consumption (at constant vehicle miles traveled) , most likely leading to a net decrease in gasoline imports.

Table 4. 2 (next page) shows the estimated capital investment, annual refining cost, per

- gallon refining cost, and energy density

- related savings, by PADD, for each Study Case.

In general, the estimated per

- gallon costs of sulfur and RVP control are lowest in PADD 3 and highest in PADD 4. The PADD 3 results reflect PADD 3’s lower regional investment factor and the existing (baseline) share of LRVP G and RFG in the PADD 3 gasolin e pool. The PADD 4 results reflect high CapEx costs

– the consequence of the high location factor for refinery investment in PADD 4 and the 1.5 multiplier that we applied to capital costs in PADD 4 (Section 2.3) , which apply to both process capacity and s torage facilities.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 20 Table 4.2: Estimated Capital Investment and Refining Costs, by Study Case and PADD

PADD 1 PADD 2 PADD 3 PADD 4 Total

Gasoline Volume (K b/d) 681 2,009 4,091 299 7,080
Capital Investment ($Mil) 473 1,193 1,810 441 3,917 Debutanization Depentanization Alkylation FCC Naphtha Desulfurization 459 1,002 1,512 223 3,196 All Other 14 191 297 218 720
Annual Refining Cost ($MM/yr) 121 544 739 127 1,531 Capital Charge and Fixed Cost 135 331 434 99 999 C4/C5 Interseasonal Transfer 5 18 14 1 38 Refining Operations -19 194 291 27 493
Per-Gallon Refining Cost (¢/gal) Entire Gasoline Pool 1.2 1.8 1.2 2.8 1.4 RVP-Affected Summer Gasoline 1.2 1.8 1.2 2.8 1.4
Energy Density-Related Savings (¢/gal) 0.0 0.0 -0.1 0.0 -0.1

Increase in CO2 Emissions (K MT/day) 0.3 4.1 3.2 0.3 8.0

PADD 1 PADD 2 PADD 3 PADD 4 Total

Gasoline Volume (K b/d) 681 2,009 4,091 299 7,080
Capital Investment ($Mil) 520 1,443 1,806 472 4,241 Debutanization 6 152 56 13 227 Depentanization Alkylation 47 47 FCC Naphtha Desulfurization 459 1,067 1,567 226 3,319 All Other 8 224 183 233 648
Annual Refining Cost ($MM/yr) 185 805 1,569 159 2,718 Capital Charge and Fixed Cost 148 432 437 108 1,125 C4/C5 Interseasonal Transfer 33 101 64 15 213 Refining Operations 4 272 1,068 36 1,380
Per-Gallon Refining Cost (¢/gal) Entire Gasoline Pool 1.8 2.6 2.5 3.5 2.5 RVP-Affected Summer Gasoline 5.2 4.2 6.2 5.4 5.3
Energy Density-Related Savings (¢/gal) -0.1 0.2 0.3 0.2 0.2

Increase in CO2 Emissions (K MT/day) 0.7 3.9 4.0 0.3 8.9

PADD 1 PADD 2 PADD 3 PADD 4 Total

Gasoline Volume (K b/d) 681 2,009 4,091 299 7,080
Capital Investment ($Mil) 611 1,412 2,614 520 5,157 Debutanization 20 165 56 33 274 Depentanization 204 8 212 Alkylation 133 133 FCC Naphtha Desulfurization 459 1,149 1,762 238 3,608 All Other 98 591 241 930
Annual Refining Cost ($MM/yr) 297 1,237 2,433 244 4,211 Capital Charge and Fixed Cost 175 429 583 124 1,311 C4/C5 Interseasonal Transfer 86 195 402 64 747 Refining Operations 36 613 1,448 57 2,154
Per-Gallon Refining Cost (¢/gal) Entire Gasoline Pool 2.8 4.0 3.9 5.3 3.9 RVP-Affected Summer Gasoline 12.1 8.1 11.3 12.4 10.2
Energy Density-Related Savings (¢/gal) 0.0 0.8 0.7 0.3 0.6

Increase in CO2 Emissions (K MT/day) 0.9 4.0 5.7 0.3 10.9 Study Case 2 Sulfur: 10 ppm / RVP: 10 psi  9 psi

Study Case 3 Sulfur: 10 ppm / RVP: 10 psi  8 psi Study Case 1 Sulfur: 30 ppm  10 ppm / RVP: 10 psiRefining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 21 Appendix A presents more detailed results of the anal y sis.

 Exhibit A

- 1 shows economic results of the analysis, by PADD, for each Study Case. (It is similar to Table 4.2. )

 Exhibit A

- 2 shows estimated refin ing sector operati ons, use of existing process capacity, and investments in new process capacity , for each Study Case, by PADD.

 Exhibit A

- 3 shows estimated refining sector input and output volumes for each Study Case, by PADD.

 Exhibit A

- 4 shows estimated properties of the total gasoline pool, the RFG pool, and the CG/LRVPG pool, for each Study Case, by season and by PADD.

 Exhibit A

- 5 shows estimated volume

- weighted composition (by blendstock) of the total gasoline pool (RFG, CG, and LRVPG) for each Study Case, by season a nd by PADD.

 Exhibit A

- 6 shows the estimated 2015 crude oil acquisition costs and natural gas prices used in the analysis, by PADD.

4.2 Discussion of Results

4.2.1 Sulfur Control

As discussed in Section 3.1, the analysis posited that

 T he refiner ies that now meet the 30 ppm Tier 2 sulfur standard with both pre

- treating and post

- treating would revamp their existing post

- treaters.

 The refineries that now meet the 30 ppm Tier 2 sulfur standard with post

- treating only would revamp their existing po st

- treaters

.
 The (relatively few) refineries in PADDs 1

- 4 that now meet the 30 ppm sulfur standard with
pre

- treating only would install grassroots post

- treaters

.

Exhibit A

- 2 shows the estimated capacity additions, by PADD, consistent with these “rul es.”

We understand that many of the post

- treating units installed to meet the Tier 2 sulfur standard are already capable of producing treated FCC naphtha with sulfur content < 10 ppm. However, th os e that do not have this capability would require revampi ng. In this regard, the estimated
cost s of sulfur control, shown in Table s 4.1 and 4.2 , reflect two conservative assumptions: (1) all existing post

- treaters would require revamping to meet the 10 ppm standard and (2) the average CapEx f o r revamping an ex isting post

- treater is 50% of the grassroots CapEx

.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 22 4.2.2 RVP Control

T able 4.3 summarizes the estimated aggregate (PADDs 1

– 4) additions to refining process capacity required to meet t he 9 psi and 8 psi RVP standard s (w ith added capacity required to

m eet the 10 ppm sulfur standard already in place )

. Exhibit A

- 2 shows the estimated capacity additions for each PADD.

Table 4.3: Estimated Capacity Additions for RVP Control

Process 9 psi 8 psi

Direct RVP Control Debutanization 51 60 Depentanization 0 481
Octane Replacement Butane Isomerization 0 9 Alkylation 3 7
Volume Replacement FCC Naphtha Desulfurization 58 205 Benzene Saturation -26 -39 Distillate Desulfurization 9 56 Distillate Dearomatization 0 107 Hydrogen Production 1 73

Note:

1 All capacity additions are in K Bbl/day of feed, except as noted below.

Debutanization capacity is in K Bbl/day of C4 removed. Alkylation capacity is in K Bbl/day of alkylate produced. Hydrogen capacity is in MM Scf/day

. (K Bbl/day) (1) Capacity Additions

The capacity additions for debutanization and depentanization are to achieve the specified RVP control. The capacity additions fo r the other processes are to replace the gasoline octane and volume lost to the summer gasoline pool due to the removal of C 4 and C 5 volumes.

As Table 4.3 indicates, enhanced debutanization suffices to meet the 9 psi standard; additional depentanization is not required. 14 In PADDs 1, 2, and 3, m eeting the 8 psi standard entails reducing the butane content of the summer gasoline pool to < 1 vol% and requires both enhanced debutanization and depentanization

. In PADD 4, enhanced debutanization suffices to meet the 8 psi standard.

As discussed in Section 3.2, the C 4 and C 5 volumes removed in the summer are made available in winter to the refining sector in the same PADD, at a significant inter

- seasonal transfer cost (Table 2.2).

14 In PADD 1, depentanization is already practiced to meet the RVP standards for RFG and LRVPG, which

constitute most of PADD 1’s total gasoline production . The removed pentanes are blended to CG. Meeting lower RVP standards on the CG produced in P ADD 1 would require alternative dispositions for these pentane volumes.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 23 RVP control affe cts refinery operations in a number of ways beyond the addition of new capacity . The indicated changes are visible in Exhibit A

- 2. For example:

 Refinery crude runs increase in the summer

– reflecting the need to replace lost gasoline octane and volume

– and decrease in the winter

– reflecting the availability of additional gasoline volumes through the inter

- seasonal transfer of C 4 and C 5 volumes.

 FCC feed rates increase, leading to increased production of FCC naphtha, to replace lost gasoline volume and octane. This in turn leads to a requirement for additional FCC post

treating capacity (which is indicated in Table 4.3).

These effects are most pronounced for the 8 psi standard.

4.3 Sensitivity Analysis

After analyzing the Study Cases, we c onducted brief sensitivity analyses to assess the effects of three economic parameters on the results of the analysis: the CapEx required for revamping FCC post

- treating capacity, the value of C 4 s and C 5 s, and the return on investment.

Table 4.4 shows t he estimated effects of each of these changes on the economic results of the three Study Cases

.
 Reducing the assumed average CapEx for revamping FCC post

- treaters from 50% to 30% of the grassroots CapEx for the same FCC post

- treater capacity :  R educes t he estimated investment cost for sulfur control by about $1 billion ;  R educes the estimated annual refining cost by about $300 million/year ; and  R educes the estimated per

- gallon refining cost by 0.3¢/gal

.
 Downgrading the value of butane and pentane rejec ted in the summer from gasoline blendstock value to fuel value :  R educes the estimated investment cost for RVP control by about $0.5 billion ;  Increases the estimated annual refining cost for the 9 psi and 8 psi RVP standards by about $1 billion/year and $ 4 billion/year, respectively ;  I ncreases the e stimated per

- gallon refining cost for the 9 psi and 8 psi RVP standards by about 1¢/gal and 4¢/gal
, respectively, with the increased costs allocated over the entire gasoline pool ; and  Increases the estimated per

- gallon ref ining cost for the 9 psi and 8 psi RVP standards by about 6¢/gal and 20¢/gal
, respectively, with the increased costs allocated only to the share of the gasoline pool that is affected by the RVP standard

.
 Reducing the assumed target return on investment from 10% after tax to 7 % before tax :  Leaves the estimated investment cost for sulfur control and RVP control unchanged ;  Reduces the estimated annual refining cost s for sulfur control, RVP control to 9 psi, and RVP control to 8 psi by about $0.3 billion, $0.1 billion, a nd $0.2 billion, respectively ;Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 24  Reduces the estimated per

- gallon refining cost for sulfur control by 0.3¢/gal ;  Reduces the estimated per

- gallon refining cost for the 9 RVP standard and 8 RVP standards by about 0.1¢/gal and 0.3¢/gal
, res pectively, with the increased cos ts allocated over the entire gasoline pool; and  Reduces the estimated per

- gallon refining cost for the 9 psi and 8 psi RVP standards by about 2¢/gal and 43⁄4¢/gal
, respectively, with the increased costs allocated only to the share of the gasoline pool that is affected by the RVP standard

.

Table 4.4: Results of Sensitivity Analyses

1 2 3 Sulfur } 10 ppm RVP } 10 psi 9 psi 8 psi

Cost of Revamping FCC Post-treater Change revamp CapEx from 50% to 30% of grassroots CapEx
**D** Capital Investment ($Mil) -1,027 -1,027 -1,027
**D** Annual Refining Cost ($MM/yr) -299 -299 -299
**D** Per-Gallon Refining Cost (¢/gal) -0.3 -0.3 -0.3

Value of Rejected C4/C5 Volumes Downgrade rejected C4/C5 volumes (summer) to fuel value
**D** Capital Investment ($Mil) 0 -533 -533
**D** Annual Refining Cost ($MM/yr) 0 1,018 4,148
**D** Per-Gallon Refining Cost (¢/gal) Entire Gasoline Pool 0 0.9 3.8 RVP-Affected Summer Gasoline 0 6.1 19.9

Return on Investment Change the ROI on CapEx from 10% after tax to 7% before tax
**D** Capital Investment ($Mil) 0 0 0
**D** Annual Refining Cost ($MM/yr) -298 -395 -630
**D** Per-Gallon Refining Cost (¢/gal) Entire Gasoline Pool -0.3 -0.4 -0.6 RVP-Affected Summer Gasoline -0.3 -2.2 -5.0

Gasoline Volume (K b/d) 7,080 7,080 7,080 Sensitivity Analysis Study Case

10 ppm

4.4 The Economic Effect of Increased Energy Density in the Gasoline Pool

As noted in Section 4.1 and Tables 4.1 and 4.2, removing C 4 and C 5 volumes from the gasoline pool to meet more stringent RVP standards leads to a small i ncrease in the energy density of the complying (nearly butane

- free) summer gasoline, which is only partially offset by a small decrease in the energy density of winter gasoline.

A change in gasoline energy density translates directly into a correspondin g change in average vehicle fuel economy. Hence, an increase in the gasoline pool’s energy density means a decrease in total gasoline consumption (at constant vehicle miles traveled). We assumed, for purposes of this analysis, that the reduction in total gasoline demand would lead to aRefining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 25 corresponding decrease in the volume of gasoline imports, with domestic gasoline production volume remaining constant.

The cost savings realized from the energy density effect would not accrue to the domestic refining sector. It would accrue to gasoline consumers, in the form of reduced expenditures for gasoline, thereby providing a partial offset to the national cost of the contemplated RVP standard.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 26 

### 5

. A DDITIONAL 

### C OMMENTS

Various study assumptions and premises merit discussion and should be considered in assessing the results of the refinery modeling.

5 .1 Ma intaining Gasoline Production at Baseline Volumes

As discussed in Section 2.2, we specified that the Study Cases represent the U.S. refining sector mai ntaining regional and total U.S. gasoline production at the 2015 Baseline volumes. That is, the refining sector as a whole replaces all the octane

- barrels lost in sulfur control and in RVP control. The solutions returned by the regional refining models indicate the least

- cost set of actions for doing so.

Recent history may offer some perspective for this specification. T he past twenty five years have witnessed the enactment of a number of ever more stringent regulatory programs affecting refined pro duct quality , especially for gasoline and diesel . During this period, a number of U.S. refineries have closed; some perhaps due in whole or in part to the investment and other costs required for regulatory compliance. However, during the same period, ove rall U.S. refining capacity, as well as light product out

- turns, has increased. Gasoline and diesel imports have increased, but much of the increase has come from “short

- haul” refineries in eastern Canada and the Caribbean that are closely tied to U.S. fu els markets. This history suggests that the U.S. refining sector as a whole

– though not necessarily each individual refinery

– has the resources and incentives to meet refined product demand even as it complies with new regulatory programs

. Moreover, to the extent that they are realized, mandated future increases in the volume of bio

- fuels used in gasoline and diesel fuel will tend to exert downward pressure on refinery capacity utilization , thereby easing the task of meeting demand for refined products

.

5. 2 “Over

- Optimization” and “Under

- Optimization”

Models of regional refining a ggregate s, such as those used in this study, essentially represent all regional refining capacity as well as intermediate and final gasoline blendstocks, as th ough all refining capacity in the region were a single, fully integrated refining complex . Consequently, aggregate refining models are viewed as hav ing a tendency to “over

- optimize”

– that is, to return solutions that describe operating results somewhat better than the refining sector could achieve in practice , given the market conditions and process technologies represented in the models. However, the possibility of some over

- optimization has not proven to be an impediment to the use of aggregate refin ery modeling for analyzing the economics of prospective fuels regulations.

One potential source of over

- optimization in th e results returned by aggregate r efining models has to do with capacity utilization. I n principle, a regional aggregate model ca n represent the available process capacity in a region being used s omewhat more efficient ly than individual refineries can achieve in isolation

. For example, a regional aggregate model can, in effect, makeRefining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 27 spare process capacity in one refinery available for use by other refineries in the region

– a seemingly spurious effect

. However, to some extent, refiners located in close proximity to one another within a region can and do interact in this manner

– buying and selling refinery inputs, sharing capacity via tolling agreements, etc. Such arrangements yield economic benefits to the refining sector that cannot be captured by modeling individual refineries in isolation. A model’s ability to capture economic benefits of inter

- refinery transactions is not nec essarily “ over

– optimization
, ” as it usually viewed in the context of regional refinery modeling.

More broadly, optimization models, of the kind used in this study, offer a unique and valuable analytical benefit : they represent the collective profit

- maximi zing behavior of refiners responding to price signals. Such price signals are generated by the relative abundance o r scarcity of economic resources: crude oil and other refinery inputs, refining capacity, and refined products.

By contrast, refinery

- by

- refinery simulation , a non

- optimizing approach to model ing refining sector operations
, offer s no direct means of representing market dynamics or capturing refiners’ p r o spective response s to price signals generated by the actions of other refiners, marke t participants , and regulators . For example, a refinery’s independent decision to shut down or to curtail gasoline production would , in isolation, lead to reduced product supply in its market area. T he resulting price signals would likely induce other re finers serving that market area to increase their product out

- turns, by changing operations and/or investing in new capacity. A nalyses based on refinery

- by

- refinery simulation appear to capture only rarely the likely economic responses of refiners to chan ging conditions

– even when the chang ing conditions are themselves the focus of the analysis.

Consequently, one might conclude that while aggregate optimization modeling of refining sector operations return results that tend to be “over

- optimized,” refin ery

- by

- refinery simulation of refining sector operations leads to results that tend to be “under

- optimized.”

5.3 The Cost Estimates Developed in This Study Reflect Conservative Assumptions

In this context, “conservative assumptions” means technical o r economic assumptions that lead
t o higher estimated costs of compliance than would other, perhaps equally reasonable assumptions.

Where more than one reasonable assumption could be made regarding a particular study parameter, we strove to choose the mo re conservative a lternative. Examples of t he conservative assumptions embodied in this analysis include:

 A ll existing FCC post

- treaters would require revamping to meet the 10 ppm sulfur standard

.
 The average CapEx for revamping the fleet of FCC post

- tre aters is 50% of the CapEx for grassroots post

- treaters (even though some of the existing units may require no revamping)

.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 28  The CapEx for new process capacity in PADD 4 is 50% higher than that of the standard CapEx estimates used for the other PADDs, to refl ect the small size of the PADD 4 refineries

.
 The target rate of return on refinery investments is 10% after tax

. Our use of conservative assumptions was not intended to inflate the cost estimates, but rather to minimize the likelihood of the analysis produ cing “low

- ball” estimates of the refining costs for complying with the contemplated sulfur and RVP standards.

5. 4 Capabilities of Foreign Refiners to Produce Tier 3 Gasoline Were Not Considered

Using EIA’s AEO 2011 Reference Case forecast of re fined product imports, we project imports of gasoline blending components to constitute more than 12% of total U.S. gasoline supply in 201 5 . Most gasoline imports come into PADD 1, where imports constitute about 31% of total gasoline supply (including int er

- regional transfers from PADD 3). A handful of refineries in eastern Canada and the Caribbean Basin are consistent suppliers to the U.S.
, and they account for most of PADD 1’s gasoline imports. The re st of the imports come from “opportunity” suppliers, refineries in northern Europe, Africa, the Middle East, and Asia.

A s noted i n Section 3, an important premise in the analysis was that the U.S. refining sector would maintain the baseline (Reference Case) volumes of gasoline production in each PADD wh ile meeting the contemplated low sulfur, low RVP gasoline standards. The refining analysis indicated that the U.S. refining sector could do so without significant investment in new capacity beyond what would be needed for compliance with the Tier 3 standa rd.

Implicitly, the analysis assumed that the off

- shore refineries supplying imported CBOBs and RBOBs would likewise be able to maintain their production of gasoline blendstocks at baseline volumes

. However, analysis of the capabilities and economics o f foreign suppliers wa s far beyond the scope of this study.

5. 5 Downstream Costs Were Not Considered

O ur analysis does not address additional costs incurred downstream of the refinery

– from the refinery gate to the pump

– in moving, storing, and dis tributing low sulfur, low RVP (Tier 3) gasoline. These costs should be relatively small, because the contemplated standard will be a national one, applying to all CG, and will not involve any additional segregations in pipelines and terminals. T here are likely to be some downstream costs incurred to minimize sulfur pick

- up due to contact with higher

- sulfur streams, primarily jet fuel, in the pipeline system. T his cost would be independent of the RVP standard.Refining Economics of National Low Sul fur, Low RVP Gasoline Final Report

October 25 , 20 11 29 

## APPENDIX A

DETAILED RESULTS OF THE REFINERY MODELINGLow Sulfur/Low RVP GasolineExhibit A-1:Summary of Refinery Modeling Results10 ppm Sulfur 9.0 RVP/10 ppm Sulfur 8.0 RVP/10 ppm SulfurPADD 1 PADD 2 PADD 3 PADD 4 Total PADD 1 PADD 2 PADD 3 PADD 4 Total PADD 1 PADD 2 PADD 3 PADD 4 TotalGasoline Pool Volume (K b/d) 6812,0094,0912997,0796812,0094,0912997,0796812,0094,0912997,079Investment ($MM) 473 1,193 1,810 4413,917520 1,443 1,806 4724,240611 1,412 2,614 5205,158Debutanization6 152 56 1322620 165 56 33274Depentanization204 8213Alkylation4747133133FCC Naphtha Desulfurization 459 1,002 1,512 2233,196459 1,067 1,567 2263,319459 1,149 1,762 2383,609All Other 14 191 297 2187208 224 183 23364898 591 241930Annual Refining Cost ($MM/y) 121 544 739 1271,531185 805 1569 1592,718297 1237 2433 2444,211Capital Charge & Fixed 135 331 434 99999148 432 437 1081,125175 429 583 1241,310C4/C5 Interseasonal Transfer 5 18 14 13833 101 64 1521386 195 402 64747Refining Operations -18 194 291 274944 272 1068 361,38036 613 1448 572,154Per Gallon Refining Cost (¢/gal)Entire Gasoline Pool 1.2 1.8 1.2 2.81.41.8 2.6 2.5 3.52.52.8 4.0 3.9 5.33.9RVP-Affected Summer Gasoline 1.2 1.8 1.2 2.81.45.2 4.2 6.2 5.45.312.1 8.1 11.3 12.410.2Energy Density-Related Savings (¢/gal) 0.0 0.0 -0.1 0.00.0-0.1 0.2 0.3 0.20.20.0 0.8 0.7 0.30.6Increase in CO2 Emissions (K MT/d) 0.3 4.1 3.2 0.38.00.7 3.9 4.0 0.38.90.9 4.0 5.7 0.310.9October 14, 2011MathProLow Sulfur/Low RVP Gasoline

Exhibit A-2:

Type

of Process Process
USE OF IN-PLACE CAPACITY Crude Distillation Atmospheric Conversion Fluid Cat Cracker Hydrocracking Coking Upgrading Alkylation* Iso-octene/octane Catalytic Polymerization* Dimersol* Pen/Hex Isomerization Reforming - CCR Reforming - Other Hydrotreating Naphtha Desulfurization FCC Naphtha Desulfurization Benzene Saturation Distillate Desulfurization Distillate Dearomatization FCC Feed Desulfurization (Conv) FCC Feed Desulfurization (Deep) Resid Desulfurization Hydrogen (MM scf/d) Hydrogen Production Hydrogen Recovery Fractionation Debutanization Depentanization Lt. Naphtha Spl. (Benz. Prec.) Med. Naphtha Spl. Hvy. Reformate Spl. FCC Naphtha Splitting Heavy FCC/Lt Cycle Oil Splitting Othe r Aromatics Plant* Benzene Extraction* Butane Isomerization Lubes & Waxes* Solvent Deasphalting Sulfur Recovery* (K s tons/d) Steam Generation (K lb/hr)

NEW CAPACITY Upgrading Alkylation* Hydrotreating FCC Naphtha Desulfurization Benzene Saturation Hydrogen Hydrogen Plant* (MM scf/d) Fractionation Debutanization Depentanization Medium Naphtha Spl. Othe r Butane Isomerization Retrofit/Revamp Tier 2 Diesel Desulfurization Distillate Dearomatization FCC Naphtha Desulfurization
OPERATIONS Fluid Cat Cracke r Charge Rate Conversion (Vol %) Olefin Max Cat. (%) Catalyst Coke (K b/d) Reforme r Charge Rate Severity (RON)
FUEL & ENERGY Fuel Use Natural Gas & Refinery Gases (foeb) Energy Use Fuel & Power (Billion btu/d) CO2 Emissions CO2 Emissions (K MT/d)

* Capacity defined in terms of volume of output. Refinery Modeling Results -- PADD 1 Operations and New Capacity (K b/d, except as noted)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win

1,195 972 1,125 1,011 1,128 1,010 1,135 1,000 1,148 987

501 473 508 477 510 493 514 483 526 471

22 10 22 7 22 4 22 5 22 6 30 19 44 17 44 17 44 16 44 16 79 70 79 64 79 64 79 71 79 74

13 13 13 13 13

17 17 17 17 17 17 17 17 17 17 49 49 49 49 49 49 49 49 49 49 107 81 107 88 109 80 109 80 108 80 244 184 262 199 263 220 265 217 269 213 295 267 301 273 303 282 306 272 311 262

12 15 12 15 12 14 12 13 12 10 308 282 297 321 299 298 340 304 340 306

39 36 40 37 40 38 40 37 41 36 295 267 301 273 303 282 306 272 311 262

36 41 41 41 41 41 41 41 41 41

80 45 79 35 80 41 80 37 80 38 149 149 149 149 149 76 54 76 61 73 63 79 62 90 61

11 23 69 61 60 12 31

11 6 11 10 11 9 10 9 10 9

10 10 10 10 10 4 10 10 10 10 14 15 16 15 16 15 16 15 16 15 18 18 18 18 18 18 18 18 18 18 0.61 0.51 0.61 0.49 0.61 0.47 0.61 0.47 0.62 0.47 3,605 2,831 3,578 2,922 3,595 2,933 3,657 2,969 3,722 2,955

3 7

221 14 33 44 1 4

1 335 335 335

557 516 566 522 569 537 574 526 586 513 68.2 68.0 67.8 68.4 67.8 68.5 67.8 68.6 67.8 68.6

8.9 1.2 0.7 9.2 1.3 17.0 20 21 21 21 21 21 21 21 21 20 170 146 182 163 184 150 184 148 184 146 101.3 97.6 97.0 93.4 97.9 94.3 97.6 95.1 96.9 97.1

55 45 55 47 56 47 57 47 58 47 549 478 549 493 554 494 564 493 575 487 38.5 34.6 38.6 35.4 39.1 35.6 40.0 35.4 40.8 34.9

October 14, 2011 Page 1 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-2:

Type

of Process Process
USE OF IN-PLACE CAPACITY Crude Distillation Atmospheric Conversion Fluid Cat Cracker Hydrocracking Coking Upgrading Alkylation* Iso-octene/octane Catalytic Polymerization* Dimersol* Pen/Hex Isomerization Reforming - CCR Reforming - Other Hydrotreating Naphtha Desulfurization FCC Naphtha Desulfurization Benzene Saturation Distillate Desulfurization Distillate Dearomatization FCC Feed Desulfurization (Conv) FCC Feed Desulfurization (Deep) Resid Desulfurization Hydrogen (MM scf/d) Hydrogen Production Hydrogen Recovery Fractionation Debutanization Depentanization Lt. Naphtha Spl. (Benz. Prec.) Med. Naphtha Spl. Hvy. Reformate Spl. FCC Naphtha Splitting Heavy FCC/Lt Cycle Oil Splitting Othe r Aromatics Plant* Benzene Extraction* Butane Isomerization Lubes & Waxes* Solvent Deasphalting Sulfur Recovery* (K s tons/d) Steam Generation (K lb/hr)

NEW CAPACITY Upgrading Alkylation* Hydrotreating FCC Naphtha Desulfurization Benzene Saturation Hydrogen Hydrogen Plant* (MM scf/d) Fractionation Debutanization Depentanization Medium Naphtha Spl. Othe r Butane Isomerization Retrofit/Revamp Tier 2 Diesel Desulfurization Distillate Dearomatization FCC Naphtha Desulfurization
OPERATIONS Fluid Cat Cracke r Charge Rate Conversion (Vol %) Olefin Max Cat. (%) Catalyst Coke (K b/d) Reforme r Charge Rate Severity (RON)
FUEL & ENERGY Fuel Use Natural Gas & Refinery Gases (foeb) Energy Use Fuel & Power (Billion btu/d) CO2 Emissions CO2 Emissions (K MT/d)

* Capacity defined in terms of volume of output. Refinery Modeling Results -- PADD 2 Operations and New Capacity (K b/d, except as noted)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win

3,285 3,171 3,209 3,067 3,218 3,074 3,243 3,053 3,287 3,043 1,114 1,070 1,079 1,009 1,054 1,008 1,066 983 1,096 987

234 234 234 234 234 234 234 234 234 234 361 346 329 327 335 329 340 327 346 324 243 234 239 211 242 224 243 222 243 237

5 55555515 3333333333 167 167 167 167 167 167 167 167 167 167 292 292 292 292 292 292 292 292 292 292 281 261 267 220 302 271 304 265 313 262 772 716 751 788 781 802 784 795 900 793 486 463 486 444 486 582 486 582 486 579 22 26 22 50 22 48 22 45 1,013 1,042 999 997 1,014 1,040 1,008 1,044 1,047 1,041 18 16 18 18 18 18 18 18 18 18 225 215 216 203 218 204 220 202 225 201 486 463 486 444 486 582 486 582 486 579

535 535 535 535 535 535 535 535 535 535

210 161 195 141 202 161 194 172 194 171 111 111 111 111 111 111 253 266 255 197 209 182 204 186 299 189

53 28

222 135 490 28 479 458 16 17 22 34 34 34 34 34 32 34

14 14 14 14 14 14 14 14 14 25 9999999999 16 16 16 16 16 16 16 16 16 16 3.26 3.17 3.09 3.02 3.10 3.02 3.14 2.99 3.18 2.98 9,516 9,461 9,741 9,671 10,159 9,883 10,259 9,796 10,305 9,887

152 179 214 24 4 13 36 38 17 377 417 442 401 475 420 485 423 441 402 32 35

9 3 10 3

540 540 540

1,220 1,163 1,173 1,102 1,180 1,105 1,194 1,095 1,218 1,088 69.2 69.8 70.1 70.3 68.1 69.4 68.3 68.5 68.7 69.1

9.9 22.7 7.4 24.2 10.8 19.9 10.0 12.3 3.3 18.1 42 40 40 37 40 38 40 37 41 37 587 560 602 518 645 583 645 577 650 565 99.5 99.4 94.8 97.8 95.5 98.1 95.9 97.9 96.8 99.1

186 184 186 179 193 186 194 185 196 185 1,695 1,672 1,678 1,602 1,731 1,666 1,741 1,650 1,757 1,649 123.8 122.2 122.5 116.5 126.1 121.0 126.8 119.9 127.4 119.6

October 14, 2011 Page 2 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-2:

Type

of Process Process
USE OF IN-PLACE CAPACITY Crude Distillation Atmospheric Conversion Fluid Cat Cracker Hydrocracking Coking Upgrading Alkylation* Iso-octene/octane Catalytic Polymerization* Dimersol* Pen/Hex Isomerization Reforming - CCR Reforming - Other Hydrotreating Naphtha Desulfurization FCC Naphtha Desulfurization Benzene Saturation Distillate Desulfurization Distillate Dearomatization FCC Feed Desulfurization (Conv) FCC Feed Desulfurization (Deep) Resid Desulfurization Hydrogen (MM scf/d) Hydrogen Production Hydrogen Recovery Fractionation Debutanization Depentanization Lt. Naphtha Spl. (Benz. Prec.) Med. Naphtha Spl. Hvy. Reformate Spl. FCC Naphtha Splitting Heavy FCC/Lt Cycle Oil Splitting Othe r Aromatics Plant* Benzene Extraction* Butane Isomerization Lubes & Waxes* Solvent Deasphalting Sulfur Recovery* (K s tons/d) Steam Generation (K lb/hr)

NEW CAPACITY Upgrading Alkylation* Hydrotreating FCC Naphtha Desulfurization Benzene Saturation Hydrogen Hydrogen Plant* (MM scf/d) Fractionation Debutanization Depentanization Medium Naphtha Spl. Othe r Butane Isomerization Retrofit/Revamp Tier 2 Diesel Desulfurization Distillate Dearomatization FCC Naphtha Desulfurization
OPERATIONS Fluid Cat Cracke r Charge Rate Conversion (Vol %) Olefin Max Cat. (%) Catalyst Coke (K b/d) Reforme r Charge Rate Severity (RON)
FUEL & ENERGY Fuel Use Natural Gas & Refinery Gases (foeb) Energy Use Fuel & Power (Billion btu/d) CO2 Emissions CO2 Emissions (K MT/d)

* Capacity defined in terms of volume of output. Refinery Modeling Results -- PADD 3 Operations and New Capacity (K b/d, except as noted)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win

7,671 7,271 7,328 7,056 7,337 7,056 7,373 7,073 7,497 6,966 2,487 2,279 2,454 2,386 2,452 2,406 2,458 2,430 2,524 2,324

727 727 727 727 727 727 727 727 727 727 1,149 1,069 1,145 1,075 1,147 1,074 1,167 1,078 1,198 1,059

581 488 581 479 581 488 581 497 581 494

20 20 20 20 19 19 19 19 19 19 19 19 19 19 213 213 213 213 213 213 213 213 213 213 820 820 820 820 820 820 820 820 820 820 545 489 497 423 515 428 532 430 567 439 1,670 1,465 1,602 1,434 1,604 1,541 1,613 1,545 1,730 1,522 1,239 1,138 1,239 1,207 1,239 1,325 1,239 1,352 1,239 1,294

65 64 73 64 73 64 76 64 65 2,386 2,335 2,263 2,248 2,245 2,226 2,261 2,259 2,411 2,210 4 4 4 4 4 4 4 4 4 111 978 893 972 932 970 939 1,009 954 1,056 913 1,239 1,138 1,239 1,207 1,239 1,325 1,239 1,352 1,239 1,294

875 875 875 875 875 875 875 875 875 875

509 410 513 398 520 408 515 429 515 439 303 303 303 303 303 303 561 408 376 518 357 512 413 516 423 455

93 472 478 464 412 463 465 458

586 668 963 1,322 1,265 110 128 164 121 173 124 145 124 130 132

50 50 50 50 50 3 137 133 145 137 145 137 145 137 145 137 202 202 202 202 202 202 202 202 202 202 10.25 9.91 10.26 9.90 10.31 9.91 10.38 9.92 10.60 9.78 27,741 25,366 28,811 26,274 29,014 26,605 28,724 26,906 29,050 26,467

140 169 276 54 51 23 33 1,679 1,728 1,893 1,941 1,997 1,987 1,994 1,987 2,040 2,037 16 16 468

57 51 50 104 16 107 1,377 1,377 1,377

2,600 2,374 2,584 2,479 2,579 2,498 2,684 2,538 2,809 2,429

71.9 71.8 71.5 72.3 71.6 72.4 69.6 72.2 68.7 72.0 45.9 48.6 47.9 45.0 48.0 44.4 49.3 39.9 29.8 37.9 104 98 102 98 102 98 102 99 103 96 1,325 1,317 1,348 1,250 1,363 1,251 1,352 1,254 1,407 1,262 99.2 95.1 93.9 93.7 94.6 94.0 96.9 94.0 96.4 94.3

495 471 499 474 505 479 504 482 515 481 4,463 4,236 4,481 4,258 4,519 4,297 4,508 4,324 4,588 4,292 325.0 309.8 327.4 313.7 331.0 316.6 330.8 318.3 336.4 316.0

October 14, 2011 Page 3 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-2:

Type

of Process Process
USE OF IN-PLACE CAPACITY Crude Distillation Atmospheric Conversion Fluid Cat Cracker Hydrocracking Coking Upgrading Alkylation* Iso-octene/octane Catalytic Polymerization* Dimersol* Pen/Hex Isomerization Reforming - CCR Reforming - Other Hydrotreating Naphtha Desulfurization FCC Naphtha Desulfurization Benzene Saturation Distillate Desulfurization Distillate Dearomatization FCC Feed Desulfurization (Conv) FCC Feed Desulfurization (Deep) Resid Desulfurization Hydrogen (MM scf/d) Hydrogen Production Hydrogen Recovery Fractionation Debutanization Depentanization Lt. Naphtha Spl. (Benz. Prec.) Med. Naphtha Spl. Hvy. Reformate Spl. FCC Naphtha Splitting Heavy FCC/Lt Cycle Oil Splitting Othe r Aromatics Plant* Benzene Extraction* Butane Isomerization Lubes & Waxes* Solvent Deasphalting Sulfur Recovery* (K s tons/d) Steam Generation (K lb/hr)

NEW CAPACITY Upgrading Alkylation* Hydrotreating FCC Naphtha Desulfurization Benzene Saturation Hydrogen Hydrogen Plant* (MM scf/d) Fractionation Debutanization Depentanization Medium Naphtha Spl. Othe r Butane Isomerization Retrofit/Revamp Tier 2 Diesel Desulfurization Distillate Dearomatization FCC Naphtha Desulfurization
OPERATIONS Fluid Cat Cracke r Charge Rate Conversion (Vol %) Olefin Max Cat. (%) Catalyst Coke (K b/d) Reforme r Charge Rate Severity (RON)
FUEL & ENERGY Fuel Use Natural Gas & Refinery Gases (foeb) Energy Use Fuel & Power (Billion btu/d) CO2 Emissions CO2 Emissions (K MT/d)

* Capacity defined in terms of volume of output. Refinery Modeling Results -- PADD 4 Operations and New Capacity (K b/d, except as noted)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win

542 526 518 500 519 500 522 497 531 489 175 158 162 163 158 164 160 162 166 155

15 12 15 12 15 12 15 12 15 12 57 58 50 57 50 57 51 56 53 55 38 33 37 35 37 35 37 35 38 34

5555555555

5 55555555 83 62 73 67 77 68 78 67 81 66

124 122 104 116 120 116 120 115 125 113 65 59 62 61 65 94 65 93 65 91 8888 190 190 182 182 187 184 187 184 192 185

24 22 23 22 23 22 23 22 24 21 65 59 62 61 65 94 65 93 65 91

111 111 111 111 111 111 111 111 111 111

25 14 23 16 23 16 23 17 23 20

49 48 38 43 39 42 38 43 43 42

33353535 5 17 19 19 19

11 11 15

6666666666

5555555555 0.52 0.50 0.47 0.49 0.47 0.49 0.48 0.49 0.49 0.47 1,366 1,267 1,373 1,320 1,388 1,338 1,402 1,330 1,428 1,314

33 34 39 10 10 11 10 1 5 1 9 7 11 7 14 2 2 6 13 222

2555

73 73 73

182 166 177 172 173 173 175 171 186 164 71.7 71.2 69.1 71.0 68.8 71.2 68.9 70.9 67.3 70.9

6.7 39.9 13.9 35.7 16.6 38.5 15.7 32.7 13.1 23.4

7677777776 83 62 73 67 77 68 78 67 81 66 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0 116.0

27 25 26 25 26 26 26 25 27 25 249 232 238 234 242 239 244 237 251 231 18.3 17.0 17.5 17.3 17.8 17.6 17.9 17.5 18.5 17.0

October 14, 2011 Page 4 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-3:

Inputs/ Outputs
Crude Oil Other Inputs Isobutane Butane Butylene C5s Natural Gas Liquids Gasoline Blendstocks Straight Run Naphtha Kerosene Heavy Gas Oil Resid Ethanol -- RFG All Other Purchased Energy Electricity (MM Kwh/d) Natural Gas (K foeb/d)

Refined Products 1
Aromatics Ethane/Ethylene Propane Propylene Butanes/Butylenes C5s Aviation Gas Naphtha to PetroChem Special Naphthas Gasoline: Federal RFG Conventional Low RVP E85 Jet Fuel Diesel Fuel
EPA Diesel Ultra Low Sulfur Diesel Off road diesel/HH Oil Unf. Oil to PetroChem Residual Oil Asphalt Lubes & Waxes Coke Sulfur (s tons/d) Crude Oil Input per Bbl of Finished Gasoline Refinery Modeling Results -- PADD 1 Inputs and Outputs (K b/d)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win

1,195 972 1,125 1,011 1,128 1,010 1,135 1,000 1,148 987

163 198 243 220 243 221 243 242 243 270

10 13 13 13 13 13 13 13 13 13 16 17 18 17 17

11 25

88888 10 5 32 24 32 24 32 24 32 24

54 60 70 60 70 60 70 60 70 60 40 65 74 63 74 63 74 63 74 63 41 39 46 43 46 43 46 43 46 43

8 8 24 24 24 24 24 24 24 24

7.8 6.8 7.7 7.0 7.8 7.0 8.0 7.1 8.2 7.1 30 23 31 26 31 26 33 26 34 25 1,369 1,185 1,395 1,266 1,397 1,265 1,412 1,266 1,440 1,266

12.0 7.0 12.0 10.0 12.0 10.0 12.0 10.0 12.0 10.0

25 21 23 21 24 20 24 21 24 21 19 18 16 16 16 16 16 16 16 16 15 17 17 17 15

1 3 3 11 25

1111111111 655 617 693 668 693 668 693 668 693 668 413 394 455 431 455 431 455 431 455 431 242 223 209 237 209 237 209 237 238 237 29 29 29

88 81 84 84 84 84 84 84 84 84 392 326 375 344 375 344 375 344 375 344

2 1
267 197 250 213 250 213 250 213 250 213
123 128 125 131 125 131 125 131 125 131

72 51 70 53 71 53 71 53 73 53 74 48 82 54 82 54 82 54 82 54 14 15 16 15 16 15 16 15 16 15 6483838383 0.6 0.5 0.6 0.5 0.6 0.5 0.6 0.5 0.6 0.5

1.824 1.576 1.624 1.513 1.628 1.511 1.637 1.496 1.657 1.477

1 Total excludes coke and sulfur

October 14, 2011 Page 1 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-3:

Inputs/ Outputs
Crude Oil Other Inputs Isobutane Butane Butylene C5s Natural Gas Liquids Gasoline Blendstocks Straight Run Naphtha Kerosene Heavy Gas Oil Resid Ethanol -- RFG All Other Purchased Energy Electricity (MM Kwh/d) Natural Gas (K foeb/d)

Refined Products 1
Aromatics Ethane/Ethylene Propane Propylene Butanes/Butylenes C5s Aviation Gas Naphtha to PetroChem Special Naphthas Gasoline: Federal RFG Conventional Low RVP E85 Jet Fuel Diesel Fuel
EPA Diesel Ultra Low Sulfur Diesel Off road diesel/HH Oil Unf. Oil to PetroChem Residual Oil Asphalt Lubes & Waxes Coke Sulfur (s tons/d) Crude Oil Input per Bbl of Finished Gasoline Refinery Modeling Results -- PADD 2 Inputs and Outputs (K b/d)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win 3,285 3,171 3,209 3,067 3,218 3,074 3,243 3,053 3,287 3,043

195 254 216 337 216 342 216 364 216 410 48 43 46 41 46 41 46 41 46 41 83 83 88 110 115

20 46 32 42 115 42 115 42 115 42 115

7 7 29 20 58 38 58 38 58 38 58 38 23 22 21 13 21 13 21 13 21 13 12 17 16 13 16 13 16 13 16 13

31 30 33 34 33 34 33 34 33 34 90 93 168 171 168 164 168 165 168 154

27.2 27.0 26.9 25.5 27.6 26.4 27.7 26.1 27.6 26.3 132 135 142 137 146 140 147 140 146 138 3,570 3,532 3,609 3,584 3,617 3,589 3,640 3,588 3,684 3,589

15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0

72 70 66 62 68 67 69 66 68 67 36 39 31 33 31 33 31 33 31 33 53 2 40 44 67 72 20 3232323232 12 12 15 10 15 10 15 10 15 10

1,915 1,937 1,992 2,025 1,992 2,025 1,992 2,025 1,992 2,025

309 304 331 343 331 343 331 343 331 343 1,606 1,633 1,428 1,682 1,428 1,682 1,428 1,682 1,661 1,682 233 233 233

33333333 226 225 236 230 236 230 236 230 236 230 977 976 933 952 933 952 933 952 933 952

28 21
929 936 912 935 912 935 912 935 912 935
20 19 21 17 21 17 21 17 21 17 11 8 11 10 11 10 11 10 11 10 68 80 65 67 65 67 65 67 65 67 173 157 194 169 194 169 194 169 194 169

9999999999 95 92 85 86 86 86 87 85 89 84 3.3 3.2 3.1 3.0 3.1 3.0 3.1 3.0 3.2 3.0

1.715 1.637 1.611 1.515 1.616 1.518 1.628 1.508 1.650 1.503

1 Total excludes coke and sulfur

October 14, 2011 Page 2 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-3:

Inputs/ Outputs
Crude Oil Other Inputs Isobutane Butane Butylene C5s Natural Gas Liquids Gasoline Blendstocks Straight Run Naphtha Kerosene Heavy Gas Oil Resid Ethanol -- RFG All Other Purchased Energy Electricity (MM Kwh/d) Natural Gas (K foeb/d)

Refined Products 1
Aromatics Ethane/Ethylene Propane Propylene Butanes/Butylenes C5s Aviation Gas Naphtha to PetroChem Special Naphthas Gasoline: Federal RFG Conventional Low RVP E85 Jet Fuel Diesel Fuel
EPA Diesel Ultra Low Sulfur Diesel Off road diesel/HH Oil Unf. Oil to PetroChem Residual Oil Asphalt Lubes & Waxes Coke Sulfur (s tons/d) Crude Oil Input per Bbl of Finished Gasoline Refinery Modeling Results -- PADD 3 Inputs and Outputs (K b/d)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win 7,671 7,271 7,328 7,056 7,337 7,056 7,373 7,073 7,497 6,966

701 846 891 897 891 901 891 887 891 1,082

99 104 111 97 111 97 111 97 111 97 115 90 94 110 128

13 89 94 101 90 91 90 91 90 91 90 91

1 46 30 46 30 46 46 41 50 44 43 44 43 44 43 44 43 288 326 382 363 382 363 382 363 382 363

94 66 129 100 129 100 129 100 129 100 84 72 89 83 89 83 89 83 89 83 140 178 323 328 323 328 323 328 323 328

71.9 68.1 72.4 68.6 72.7 69.2 72.3 69.5 72.2 68.5 358 356 379 368 385 372 375 374 385 379 8,321 8,161 8,377 8,170 8,383 8,171 8,402 8,171 8,597 8,170 120.0 120.0 120.0 120.0 120.0 120.0 120.0 120.0 120.0 120.0 22 19 20 19 20 19 20 19 20 19 139 127 130 123 132 124 135 124 135 123 214 208 187 190 187 190 187 190 187 190

73 85 89 105 122 89 12 11 12 10 12 10 12 10 12 10 58 62 64 53 64 53 64 53 64 53 35 39 39 42 39 42 39 42 39 42 3,939 3,901 4,095 4,087 4,095 4,087 4,095 4,087 4,095 4,087

842 715 892 827 892 827 892 827 892 827 3,097 3,186 2,178 3,260 2,178 3,260 2,178 3,260 3,203 3,260 1,025 1,025 1,025 33333333 759 690 785 744 785 744 785 744 785 744 2,283 2,353 2,194 2,173 2,194 2,173 2,194 2,173 2,194 2,173

260 134 1,748 1,954 1,930 1,921 1,930 1,921 1,930 1,921 1,930 1,921

275 265 264 252 264 252 264 252 264 252 111 106 123 112 123 112 123 112 123 112 324 312 270 271 270 271 270 271 270 271

96 80 108 89 108 89 108 89 108 89 137 133 145 137 145 137 145 137 145 137 364 337 365 342 366 342 370 343 380 336 10.2 9.9 10.3 9.9 10.3 9.9 10.4 9.9 10.6 9.8

1.947 1.864 1.789 1.726 1.792 1.726 1.800 1.731 1.831 1.704

1 Total excludes coke and sulfur

October 14, 2011 Page 3 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-3:

Inputs/ Outputs
Crude Oil Other Inputs Isobutane Butane Butylene C5s Natural Gas Liquids Gasoline Blendstocks Straight Run Naphtha Kerosene Heavy Gas Oil Resid Ethanol -- RFG All Other Purchased Energy Electricity (MM Kwh/d) Natural Gas (K foeb/d)

Refined Products 1
Aromatics Ethane/Ethylene Propane Propylene Butanes/Butylenes C5s Aviation Gas Naphtha to PetroChem Special Naphthas Gasoline: Federal RFG Conventional Low RVP E85 Jet Fuel Diesel Fuel
EPA Diesel Ultra Low Sulfur Diesel Off road diesel/HH Oil Unf. Oil to PetroChem Residual Oil Asphalt Lubes & Waxes Coke Sulfur (s tons/d) Crude Oil Input per Bbl of Finished Gasoline Refinery Modeling Results -- PADD 4 Inputs and Outputs (K b/d)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win
542 526 518 500 519 500 522 497 531 489

17 23 21 31 21 31 21 34 21 48

7687878787 9 9 9 12 15

5 2433333333

1111

8 4 9 12 9 12 9 12 9 12

9 11 30 30 30 30 30 30 30 30

3.9 3.6 3.7 3.7 3.8 3.8 3.8 3.7 3.9 3.6 17 17 17 17 18 17 18 17 18 17

562 557 566 558 566 558 569 558 583 558

11 8 9 9 9 9 9 9 9 9

1111111111 32248 5

11 1 1 1 1

287 287 295 302 295 302 295 302 295 302

287 287 159 302 159 302 159 302 295 302 136 136 136

37 37 39 39 39 39 39 39 39 39 179 179 172 164 172 164 172 164 172 164

11 11
167 167 172 164 172 164 172 164 172 164

1 1

12 12 11 9 11 9 11 9 11 9 32 32 37 33 37 33 37 33 37 33

14 15 12 14 12 14 12 14 13 14 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

1.890 1.832 1.757 1.655 1.759 1.655 1.768 1.647 1.801 1.619

1 Total excludes coke and sulfur

October 14, 2011 Page 4 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-4:

Gasoline Volume & Properties
Pool RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
RFG RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
All Other RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2) Refinery Modeling Results -- PADD 1 Pool Gasoline Properties

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win
655 617 693 668 693 668 693 668 693 668 7.5 12.6 7.7 13.8 7.7 13.8 7.5 13.8 7.1 13.8 2.5 2.5 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 23.5 20.6 21.9 19.5 22.1 19.2 22.2 19.0 22.3 18.7 0.57 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 13.7 12.4 13.2 12.4 11.2 12.4 11.1 12.4 11.2 12.4 30.0 30.0 30.0 28.6 9.0 9.0 9.0 9.0 9.0 9.0

8.3 13.6 8.6 15.0 8.5 15.5 7.9 15.9 6.8 16.9 47.5 51.9 47.7 54.3 47.6 55.0 46.7 56.1 45.6 57.4 80.0 81.9 79.2 83.2 79.2 83.4 79.0 83.8 79.0 83.8 1173 1115 1181 1094 1181 1087 1191 1075 1203 1063 5.127 5.057 5.094 5.007 5.096 5.003 5.105 4.993 5.120 4.980

88.3 88.4 88.3 88.4 88.3 88.4 88.3 88.4 88.3 88.4
413 394 455 431 455 431 455 431 455 431 6.8 12.2 6.8 13.8 6.8 13.8 6.8 13.8 6.8 13.8 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 22.1 18.8 19.8 18.8 20.2 16.0 20.2 15.7 20.3 15.3 0.54 0.57 0.54 0.57 0.54 0.57 0.54 0.57 0.54 0.57 13.5 11.5 13.3 11.5 10.3 11.5 10.5 11.5 10.7 11.5

30 30 30 28 9 9 9 9 9 9 5.6 12.6 5.8 15.3 5.9 16.3 5.9 15.7 5.7 16.4 45.0 50.8 45.0 54.7 45.0 54.4 45.0 57.5 45.0 56.6 80.0 83.0 80.0 84.9 80.0 82.2 80.0 84.8 80.0 83.1 1208 1129 1207 1084 1207 1092 1207 1063 1208 1073 5.138 5.029 5.121 4.999 5.119 4.977 5.119 4.973 5.123 4.983

88.3 88.4 88.3 88.4 88.3 88.4 88.3 88.4 88.3 88.4
242 223 238 237 238 237 238 237 238 237 8.76 13.34 9.33 13.77 9.33 13.77 8.76 13.77 7.80 13.77

1.1 1.2 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 26.0 23.8 25.9 20.7 25.9 25.0 25.9 25.0 26.0 25.0 0.61 0.55 0.61 0.55 0.61 0.55 0.61 0.55 0.61 0.55 14.0 14.0 13.1 14.0 13.1 14.0 12.2 14.0 12.0 14.0

30 30 30 30 9 9 9 9 9 9 13.0 15.4 13.9 14.6 13.6 14.0 11.5 16.3 9.1 17.9 51.9 53.9 52.7 53.4 52.6 56.1 49.8 53.6 46.7 58.7 80.0 80.0 77.7 80.0 77.7 85.6 77.1 82.1 77.0 84.9 1114 1092 1129 1113 1132 1077 1161 1098 1193 1046 5.109 5.106 5.042 5.023 5.052 5.050 5.079 5.030 5.114 4.975

88.4 88.4 88.4 88.4 88.4 88.4 88.4 88.4 88.4 88.4

1 ASTM Driveability Index: calculated by formula using modeling results for E130, E200, & E300 plus an ethanol adjustment (2.403 for each percent of ethanol in the finished blend) for all other gasoline. 2 Million Btu per barrel.

October 14, 2011 Page 1 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-4:

Gasoline Volume & Properties
Pool RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
RFG RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
All Other RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2) Refinery Modeling Results -- PADD 2 Pool Gasoline Properties

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win

1915 1937 1992 2025 1992 2025 1992 2025 1992 2025

8.7 13.5 9.1 13.7 9.1 13.7 8.5 13.7 7.7 13.7 2.1 2.1 3.3 3.3 3.3 3.2 3.3 3.2 3.3 3.0 24.5 21.7 21.4 19.6 21.3 19.0 21.9 18.8 23.5 19.0 1.13 0.82 0.78 0.62 0.62 0.62 0.62 0.62 0.62 0.62 9.0 9.8 8.6 9.4 7.1 7.9 7.1 7.1 7.1 7.2 30.0 30.3 29.8 29.7 9.0 9.0 9.0 9.0 9.0 9.0

8.6 15.6 9.5 15.5 9.5 15.5 8.9 15.7 7.8 15.9 53.1 59.5 54.8 60.4 54.3 61.1 53.6 61.2 52.2 61.4 82.3 86.2 83.4 85.5 83.3 87.4 82.7 87.5 81.3 87.7 1122 1036 1112 1042 1115 1029 1125 1027 1145 1023 5.110 5.031 5.049 4.956 5.053 4.950 5.066 4.947 5.092 4.949

88.7 89.1 88.7 89.1 88.7 89.1 88.7 89.1 88.7 89.1
309 304 331 343 331 343 331 343 331 343 7.0 13.4 7.0 13.4 7.0 13.4 7.0 13.4 7.0 13.4 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 20.4 20.4 18.7 17.2 19.9 20.4 20.5 20.4 20.5 20.4 0.74 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62

8.3 6.0 6.7 6.0 1.8 6.0 2.3 6.0 3.1 6.0 30 32 30 28 9 9 9 9 9 9 5.3 14.8 6.5 14.5 6.1 14.6 5.4 14.8 5.9 14.8 49.4 53.6 49.4 56.1 49.4 56.8 49.4 57.3 49.4 55.4 83.6 85.9 83.6 92.4 87.5 86.2 83.6 81.8 83.6 83.8 1165 1090 1161 1051 1148 1068 1165 1079 1163 1085 5.098 4.958 5.091 4.871 5.075 4.919 5.089 4.978 5.103 4.918

88.5 88.6 88.5 88.6 88.5 88.6 88.5 88.6 88.5 88.6
1606 1633 1661 1682 1661 1682 1661 1682 1661 1682 9.05 13.48 9.52 13.77 9.52 13.75 8.76 13.75 7.80 13.70

1.9 1.9 3.3 3.3 3.3 3.2 3.3 3.2 3.3 3.0 25.3 21.9 22.0 20.1 21.6 18.7 22.2 18.4 24.1 18.7 1.20 0.86 0.81 0.62 0.62 0.62 0.62 0.62 0.62 0.62 9.1 10.5 9.0 10.1 8.1 8.3 8.1 7.4 7.9 7.5 30 30 30 30 9 9 9 9 9 9 9.2 15.7 10.1 15.7 10.2 15.7 9.6 15.8 8.1 16.2 53.9 60.7 55.9 61.2 55.3 62.0 54.4 62.0 52.7 62.6 82.1 86.3 83.3 84.0 82.5 87.7 82.5 88.6 80.8 88.4 1114 1025 1102 1040 1109 1021 1117 1017 1142 1010 5.112 5.044 5.040 4.973 5.049 4.956 5.062 4.940 5.090 4.956

88.7 89.2 88.7 89.2 88.7 89.2 88.7 89.2 88.7 89.2

1 ASTM Driveability Index: calculated by formula using modeling results for E130, E200, & E300 plus an ethanol adjustment (2.403 for each percent of ethanol in the finished blend) for all other gasoline. 2 Million Btu per barrel.

October 14, 2011 Page 2 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-4:

Gasoline Volume & Properties
Pool RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
RFG RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
All Other RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2) Refinery Modeling Results -- PADD 3 Pool Gasoline Properties

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win

3939 3901 4095 4087 4095 4087 4095 4087 4095 4087

8.2 12.6 8.7 12.8 8.7 12.8 8.2 12.8 7.6 12.8 1.9 2.1 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 23.3 20.3 20.5 18.1 20.7 17.9 20.8 17.4 21.6 17.3 0.77 1.00 0.59 0.72 0.59 0.72 0.59 0.72 0.59 0.72

9.6 9.9 9.6 10.4 8.2 9.4 8.1 9.3 7.6 8.4 29.6 30.0 29.1 30.0 9.0 9.0 9.0 9.0 9.0 9.0

8.7 14.2 9.3 14.5 9.0 14.5 9.3 14.6 7.3 15.4 52.2 58.0 53.4 60.3 53.4 60.5 53.1 60.5 49.3 61.4 82.6 87.0 84.8 87.9 84.5 88.2 82.6 89.0 81.2 89.3 1126 1050 1117 1037 1120 1035 1127 1031 1167 1021 5.120 5.030 5.045 4.974 5.044 4.972 5.064 4.966 5.099 4.952

87.8 87.8 88.2 88.2 88.2 88.2 88.2 88.2 88.2 88.2
842 715 892 827 892 827 892 827 892 827 6.9 12.8 6.9 12.8 6.9 12.8 6.9 12.8 6.9 12.8 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 11.3 26.3 9.5 26.3 18.9 26.3 18.5 24.7 19.3 23.6 0.50 1.12 0.50 1.12 0.50 1.12 0.50 1.12 0.50 1.12

7.9 6.9 9.7 7.6 4.1 11.0 4.3 9.0 2.5 7.3 28 30 28 30 9 9 9 9 9 9 6.0 13.8 6.3 13.4 6.4 12.2 5.0 13.1 5.5 15.6 48.4 56.5 47.8 58.7 47.8 57.5 52.6 59.5 47.8 62.3 85.0 80.0 86.8 82.2 83.3 80.0 83.3 95.7 89.0 80.0 1164 1096 1161 1074 1173 1095 1146 1020 1156 1048 5.052 5.057 5.043 5.044 5.090 5.052 5.086 5.000 5.087 5.000

88.2 88.0 88.2 88.0 88.2 88.0 88.2 88.0 88.2 88.0
3097 3186 3203 3260 3203 3260 3203 3260 3203 3260 8.57 12.51 9.17 12.84 9.17 12.84 8.56 12.84 7.80 12.84

1.5 1.8 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 26.6 18.9 23.5 16.0 21.2 15.8 21.4 15.6 22.3 15.7 0.84 0.97 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 10.1 10.6 9.6 11.2 9.3 9.0 9.1 9.3 9.0 8.6

30 30 29 30 9 9 9 9 9 9 9.4 14.2 10.2 14.8 9.7 15.1 10.5 15.0 7.8 15.4 53.2 58.3 54.9 60.7 55.0 61.2 53.2 60.8 49.7 61.1 82.0 88.5 84.3 89.3 84.8 90.3 82.4 87.3 79.0 91.7 1115 1039 1105 1028 1105 1020 1122 1034 1170 1014 5.138 5.024 5.046 4.956 5.032 4.952 5.059 4.958 5.102 4.939

87.8 87.8 88.3 88.3 88.3 88.3 88.3 88.3 88.3 88.3

1 ASTM Driveability Index: calculated by formula using modeling results for E130, E200, & E300 plus an ethanol adjustment (2.403 for each percent of ethanol in the finished blend) for all other gasoline. 2 Million Btu per barrel.

October 14, 2011 Page 3 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-4:

Gasoline Volume & Properties
Pool RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
RFG RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2)
All Other RVP (psi) Oxygen (wt%) Aromatics (vol%) Benzene (vol%) Olefins (vol%) Sulfur (ppm) E130 (vol% off) E200 (vol% off) E300 (vol% off) Estimated DI 1 Energy Density 2 Octane ((R+M)/2) Refinery Modeling Results -- PADD 4 Pool Gasoline Properties

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win
287 287 295 302 295 302 295 302 295 302 8.5 12.6 9.2 13.1 9.2 13.1 8.7 13.1 7.8 13.1 1.0 1.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 24.7 17.4 19.1 18.2 19.5 18.0 19.8 17.8 20.5 17.5 1.10 0.84 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 10.6 12.8 9.5 12.1 8.2 10.8 8.2 10.2 8.4 9.0 30.0 30.0 30.0 30.0 9.0 9.0 9.0 9.0 9.0 9.0

8.3 14.0 9.7 14.9 9.7 14.9 9.0 15.1 7.7 15.9 52.6 59.0 55.8 61.9 55.8 60.7 55.3 60.6 53.6 61.1 82.5 83.9 84.1 86.3 84.0 86.6 83.8 86.7 82.8 87.2 1119 1048 1102 1030 1102 1037 1109 1037 1129 1029 5.178 5.086 5.059 5.003 5.061 5.001 5.069 5.000 5.094 4.982

87.1 84.1 87.6 87.7 87.6 87.7 87.6 87.7 87.6 87.7
0000000000

287 287 295 302 295 302 295 302 295 302 8.53 12.64 9.18 13.09 9.18 13.09 8.70 13.09 7.80 13.09

1.0 1.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 24.7 17.4 19.1 18.2 19.5 18.0 19.8 17.8 20.5 17.5 1.10 0.84 0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62 10.6 12.8 9.5 12.1 8.2 10.8 8.2 10.2 8.4 9.0

30 30 30 30 9 9 9 9 9 9 8.3 14.0 9.7 14.9 9.7 14.9 9.0 15.1 7.7 15.9 52.6 59.0 55.8 61.9 55.8 60.7 55.3 60.6 53.6 61.1 82.5 83.9 84.1 86.3 84.0 86.6 83.8 86.7 82.8 87.2 1119 1048 1102 1030 1102 1037 1109 1037 1129 1029 5.178 5.086 5.059 5.003 5.061 5.001 5.069 5.000 5.094 4.982

87.1 84.1 87.6 87.7 87.6 87.7 87.6 87.7 87.6 87.7

1 ASTM Driveability Index: calculated by formula using modeling results for E130, E200, & E300 plus an ethanol adjustment (2.403 for each percent of ethanol in the finished blend) for all other gasoline. 2 Million Btu per barrel.

October 14, 2011 Page 4 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-5:

Gasoline Blendstock Total (%) C4s Natural Gas Liquids C5s & Isomerate Raffinate Naphthas (C5-250°) Hydrocrackate Alkylate Poly Gas FCC Naphtha Reformate Ethanol
V olume (K b/d) Refinery Modeling Results -- PADD 1 Gasoline Composition (Vol. %)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win
100 100 100 100 100 100 100 100 100 100 0.7 8.4 0.7 9.5 0.7 10.2 0.6 9.6 0.5 9.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.7 2.7 7.1 2.7 7.0 2.7 5.7 4.5 4.0 6.7 0.9 0.6 0.9 0.6 0.9 0.6 0.8 0.6 0.7 0.6 7.8 8.2 6.7 8.1 6.7 8.2 6.8 8.2 7.0 8.1 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.2 0.3 0.2 11.8 11.0 11.0 9.3 11.0 9.4 11.5 10.5 12.2 10.9 2.0 0.0 1.9 0.0 1.9 0.0 1.9 0.0 1.9 0.0 42.4 43.3 41.0 41.9 41.2 41.3 41.8 39.7 42.7 38.0 18.9 17.8 20.5 17.7 20.5 17.4 20.6 16.7 20.8 16.0 7.5 7.7 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0
655 617 693 617 693 617 693 617 693 617

October 14, 2011 Page 1 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-5:

Gasoline Blendstock Total (%) C4s Natural Gas Liquids C5s & Isomerate Raffinate Naphthas (C5-250°) Hydrocrackate Alkylate Poly Gas FCC Naphtha Reformate Ethanol
V olume (K b/d) Refinery Modeling Results -- PADD 2 Gasoline Composition (Vol. %)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win
100 100 100 100 100 100 100 100 100 100 2.7 10.7 2.7 9.8 2.6 9.7 1.5 9.9 0.7 9.8 2.4 1.3 1.2 5.4 0.0 5.7 0.0 5.6 0.0 5.6 9.4 9.3 9.1 8.1 9.1 8.1 9.9 8.1 9.3 9.1 0.1 0.1 0.1 1.0 0.4 1.0 0.4 1.0 0.1 1.0 5.7 5.9 6.1 4.0 6.5 3.5 5.3 3.5 6.3 3.6 3.4 3.5 3.5 2.5 3.9 3.1 3.8 3.2 2.5 3.0 12.4 11.6 11.7 10.0 11.9 10.7 11.9 10.7 12.0 11.4 0.3 0.1 0.3 0.3 0.3 0.3 0.3 0.3 0.1 0.3 33.5 29.5 31.6 29.3 29.8 26.0 31.4 25.9 33.2 25.8 23.9 21.6 23.8 19.6 25.6 22.2 25.6 22.0 25.8 21.2

6.3 6.4 10.0 10.0 10.0 9.7 10.0 9.7 10.0 9.2
1915 1937 1992 2025 1992 2025 1992 2025 1992 2025

October 14, 2011 Page 2 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-5:

Gasoline Blendstock Total (%) C4s Natural Gas Liquids C5s & Isomerate Raffinate Naphthas (C5-250°) Hydrocrackate Alkylate Poly Gas FCC Naphtha Reformate Ethanol
V olume (K b/d) Refinery Modeling Results -- PADD 3 Gasoline Composition (Vol. %)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win
100 100 100 100 100 100 100 100 100 100 1.8 8.4 1.3 8.0 1.3 8.0 0.9 8.0 0.7 7.6 2.4 2.6 1.5 2.2 2.2 2.2 0.0 2.2 0.0 2.2 7.6 6.5 7.4 5.1 6.5 5.1 7.9 5.1 5.1 7.3 0.2 0.9 1.3 0.7 1.5 0.9 0.5 0.9 0.3 1.2 7.5 7.4 5.8 7.7 6.2 7.7 6.9 7.7 7.5 7.1 4.3 4.5 4.2 4.3 4.2 4.3 4.2 4.3 4.0 4.4 14.6 12.4 14.0 11.5 14.0 11.7 14.0 12.0 14.7 11.9 0.2 0.2 0.7 0.2 0.7 0.2 0.7 0.2 0.7 0.2 33.3 27.9 31.7 29.4 31.2 28.9 32.5 28.4 33.2 27.2 22.5 22.9 22.2 20.8 22.2 21.0 22.4 21.1 23.8 20.8

5.7 6.4 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0
3939 3901 4095 4087 4095 4087 4095 4087 4095 4087

October 14, 2011 Page 3 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-5:

Gasoline Blendstock Total (%) C4s Natural Gas Liquids C5s & Isomerate Raffinate Naphthas (C5-250°) Hydrocrackate Alkylate Poly Gas FCC Naphtha Reformate Ethanol
V olume (K b/d) Refinery Modeling Results -- PADD 4 Gasoline Composition (Vol. %)

2015 2010 RVP Standards Calibration Reference 10 ppm Sulfur 9.0 RVP 8.0 RVP Sum Win Sum Win Sum Win Sum Win Sum Win
100 100 100 100 100 100 100 100 100 100 3.3 9.8 2.9 9.1 2.9 9.1 2.1 9.2 1.0 9.1 0.7 1.4 0.0 0.0 0.0 0.4 0.0 0.0 0.0 1.0 1.7 0.0 1.7 1.6 1.7 1.6 1.7 1.6 1.7 3.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 16.2 18.3 15.0 14.9 15.0 14.3 15.0 14.8 13.9 13.5

1.6 1.9 1.3 1.0 1.5 1.0 1.5 1.0 1.5 1.0 12.9 10.5 12.2 10.7 12.2 10.9 12.3 11.0 12.5 11.0

1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 35.8 30.5 32.3 30.3 31.4 29.8 31.9 29.8 33.3 28.8 22.9 22.0 22.9 20.8 23.5 21.1 23.9 20.9 24.5 20.5

3.1 3.8 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0
287 287 295 302 295 302 295 302 295 302

October 14, 2011 Page 4 of 4 Math ProLow Sulfur/Low RVP Gasoline

Exhibit A-6: Crude Oil Acquisition Costs and Natural Gas Prices

2010 2015 Gasoline Calibration All Cases Blendstock Sum Win Sum Win
PADD 1 Crude Oil ($/b) 74.72 87.69 94.35 94.35 Natural Gas ($/mcf) 9.82 9.82 6.90 6.90
PADD 2 Crude Oil ($/b) 78.70 96.59 89.71 89.71 Natural Gas ($/mcf) 7.51 7.51 5.94 5.94
PADD 3 Crude Oil ($/b) 74.28 83.03 89.00 89.00 Natural Gas ($/mcf) 4.64 4.64 4.12 4.12
PADD 4 Crude Oil ($/b) 74.46 88.61 86.62 86.62 Natural Gas ($/mcf) 6.36 6.36 5.12 5.12 U.S. Averag e Crude Oil ($/b) 76.16 87.07 90.00 90.00 Natural Gas ($/mcf) 6.37 6.37 5.10 5.10

Source: Derived from EIA data and projections.

October 14, 2011 

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