Small Refinery Exemption Study

An Investigation into

Disproportionate Economic Hardship 

Office of Policy and International Affairs

U.S. Department of Energy

March 2011
 i

For Further Information

This study was prepared by the Office of Policy and International Affairs under the direction of

Carmine Difiglio, Deputy Assistant Secretary for Policy Analysis. 

Specific questions about information in this study may be directed to Peter Whitman, Senior 

Policy Analyst (peter.whitman@hq.doe.gov) or Tom White, Senior Policy Analyst

(thomas.white@hq.doe.gov). 

Contributors include Diwakar Vashishat of DOE; Mindi Farber-DeAnda, William Keene, Gary 

Brush, Matthew Cleaver, and Conor Hackett of SAIC; and David Hackett, David Bulfin, Barry 

Schaps, and Susan Grissom of Stillwater Associates.
 ii

Table of Contents

Executive Summary...........................................................................................vi

I. Study Objectives....................................................................................................................... 1

II. RFS Regulations ....................................................................................................................... 3

III. RINs.......................................................................................................................................... 6

How RINs Are Used to Ensure Compliance with the Renewable Fuel Standard ...................... 6

Renewable Fuel Standard Volume Requirements and RIN Values Obligated Parties............... 8

Calculation Issues ....................................................................................................................... 8

The Value of RINs.................................................................................................................... 10

IV. The Blend Wall....................................................................................................................... 13

Contributing Factors to Reaching the Blend Wall.................................................................... 14

How Close is the Blend Wall.................................................................................................... 16

Consequences of Reaching the Blend Wall.............................................................................. 17

E15 and the Blend Wall ............................................................................................................ 17

V. Evaluating the RIN and Ethanol Markets............................................................................... 19

VI. Determining Compliance Cost................................................................................................ 21

VII. Refinery Classification.......................................................................................................... 23

Refiner-Blender Integration...................................................................................................... 24

VIII.Small Refinery Exemption.................................................................................................... 24

IX. PI-588 Survey ......................................................................................................................... 25

X. Refinery Viability ................................................................................................................... 27

XI. Disproportionate Economic Hardship..................................................................................... 31

Assessing Disproportionate Economic Hardship...................................................................... 32
 iii

Disproportionate Impacts Index Analysis................................................................................. 33

Viability Index Analysis........................................................................................................... 36

Recommendation for Exemption Extension ............................................................................. 37

XII. Findings and Conclusion....................................................................................................... 37

Appendices 

Appendix A. Glossary

Appendix B. RFS Market Operations, RINs and the Fuel Supply Chain

Appendix C. DOE Ethanol Model Description

Appendix D. PI-588 Survey Form

Appendix E. PI-588 Survey Response

Appendix F. Refinery Profiles

Appendix G. Analysis of Refinery Shutdowns

Appendix H. Disproportionate Economic Hardship

Table of Figures

Figure 1. Comparison of RFS1 and RFS2 Volume Requirements................................................. 5

Figure 2. Historical Renewable and Biodiesel RIN Prices........................................................... 11

Figure 3. Carry-Over and Current-Year RIN Prices..................................................................... 12

Figure 4. RINs Prices Track the Ethanol-RBOB Spread.............................................................. 13

Figure 5. RFS2 and U.S. Motor Gasoline Demand ...................................................................... 17

Figure 6. Small Refineries Receiving the PI-588 Survey............................................................. 26

Figure 7. U.S. Refining Margins and Shutdowns, 1990-2010...................................................... 28
 iv

Figure 8. Sample Refining Margins for Large and Small Refiners 2004 – 2009 ......................... 29

Figure 9. U.S. Refined Product Environmental Regulations 1990-2010..................................... 30

Figure 10. Crack Spread Differentials.......................................................................................... 32

Figure 11. Refinery Rankings by PADD ...................................................................................... 37

Table of Tables

Table 1. RR Code Definitions......................................................................................................... 7

Table 2. D Code Definitions........................................................................................................... 7

Table 3. RFS2 Annual Volumetric Requirements (Billion Gallons).............................................. 9

Table 4. Standards for 2011............................................................................................................ 9

Table 5. Blend Wall Contributing Factors.................................................................................... 15

Table 6. RIN Scenarios Description ............................................................................................ 20

Table 7. RIN Price Scenario Results for 2011 and 2012 (2009 $) .............................................. 20

Table 8. Sample Obligated Party RINs Costs for 2010 ................................................................ 21

Table 9. Refinery Survey Responses by PADD and Ownership [CBI] used in Disproportionate 

Economic Hardship Analysis........................................................................................................ 27

Table 10. Disproportionate Structural Impact Metrics................................................................. 34

Table 11. Viability Metrics........................................................................................................... 36
 v

Acronym List

CAA Clean Air Act Amendments of 1990

DOE U.S. Department of Energy

EIA Energy Information Administration

EISA 2007 Energy Independence and Security Act of 2007

EMTS EPA Moderated Transaction System

EPA Environmental Protection Agency

EPAct 2005 Energy Policy Act of 2005

GHG Greenhouse gases

PADD Petroleum Administration for Defense District 

RFS Renewable Fuel Standard program

RFS1 Renewable Fuel Standard under EPAct 2005

RFS2 Renewable Fuel Standard as amended by EISA

RIN Renewable Identification Numbers

RVO Renewable Volume Obligation

SBRFA Small Business Regulatory Enforcement Fairness Act of 

1996
 vi

Executive Summary

The Energy Policy Act of 2005 (EPAct 2005) established the Renewable Fuel Standard (RFS)

program under Section 211 (o) of the Clean Air Act (CAA) mandating gasoline sold in the 

United States contain a minimum amount of renewable fuel content determined on an annual 

production volume basis (original RFS program denoted as RFS1). The Energy Independence 

and Security Act of 2007 (EISA 2007) amended the original program by increasing the 

renewable fuels mandate from 7.5 billion gallons to 15.2 billion gallons in 2012, and extending it

to 36 billion gallons of renewable fuel to be blended in 2022. The revised program is referred to 

as RFS21. 

EPAct 2005 exempted small refineries from compliance with the RFS from 2007 through 20102.

EPAct 2005, through its establishment of section 211(o)(9)(A)(ii) of the CAA, required that the

U.S. Department of Energy (DOE) conduct a study for the Administrator of the Environmental 

Protection Agency (EPA) assessing whether the RFS would impose a “disproportionate 

economic hardship” on small refineries, defined as those facilities with aggregate crude oil 

throughput that does not exceed 75,000 barrels per calendar day3. Small refineries may face 

challenges complying with the RFS program. For instance small refineries may have less 

integration with upstream and downstream operations, providing limited access to capital.

On February 24, 2009, DOE transmitted its study with recommendations to EPA. The study 

concluded that the market for credits (Renewable Identification Numbers, or RINs

4

) was 

competitive, and found no reason to believe that a competitive market would disproportionately 

disadvantage participants who purchase credits rather than generating them through blending 

renewable fuels into their products. Therefore, the study concluded that the exemption for small 

refineries should not be extended for the RFS2. The analysis did not evaluate the specific 

circumstances of each small refinery and noted that, should market conditions change, small 

refineries maintained the right under Section 211(o)(9)(B) of the CAA to individually petition 

EPA for an extension of their exemption. 

In October 2009, Congress directed DOE to revisit the issue of disproportionate economic 

hardship for small refineries and report its findings. This study reflects the directions of 

Congress to:

 

1 Many elements from EPAct 2005 remained intact under EISA 2007; RFS refers to those provisions that remained 

unchanged. 

2 EPA chose to exempt small refiners, defined as refiners producing gasoline from crude oil with fewer than 1,500 

employees and less than 155,000 barrels per day crude processing capability, as well as small refineries defined in 

Section 211(o)(1)(K) as those facilities with aggregate crude oil throughput that does not exceed 75,000 barrels per

calendar day. Subsequently, EPA has concluded that it did not have the authority to extend the duration of the 

exemption period for all of the small refiners as defined under the original RFS rulemaking, but only those 

statutorily defined in EPAct 2005.

3 The DOE report only analyses the statutorily defined small refineries. 

4 RINs are marketable credits that obligated parties must register with EPA to demonstrate compliance with the RFS 

renewable fuel volumetric obligation requirements.
 vii

Seek comment from owners of small refineries on the reasons why they may believe that 

they would experience disproportionate economic hardship if the small refinery exemption 

were not extended.

Assess RFS2 compliance impacts on small refinery utilization rates and profitability.

Evaluate the financial ability of individual small refineries to meet RFS2 requirements.

Estimate small refinery impacts by region.

Reassess whether small refinery compliance costs through the purchase of RINs is similar to 

the cost of compliance by purchasing and blending renewable fuels.

Undertake an estimate of the economic impact of RFS2 on small refineries on a regional 

basis.

Disproportionate economic hardship for small refineries was characterized by increased cost of 

compliance to the point that the current or future viability of the refinery is impacted. In the 

current lower refining margin environment, the cost of RFS2 regulations could have a material 

effect on small refinery profitability

Existing refinery specific survey data collected by Energy Information Administration alone 

could not provide DOE with the necessary information to make an informed decision regarding 

which small refineries suffered disproportionate economic hardship and merited an extension of 

their exemptions. Instead, available public and commercial data sources were consulted and a

survey of small refineries was initiated. Before issuing this survey, conference calls were held 

with operators of several small refineries to ensure that the survey would acquire all of the 

relevant information with which to evaluate disproportionate economic hardship. The survey

was sent on September 22, 2010 to the 59 refineries that qualified for an exemption in the initial 

RFS2 program. Completed surveys were received for eighteen small refineries that met the 

statutory requirements for inclusion in the small refinery exemption study. Several of the 

refineries that were exempt from the initial RFS program under the small refinery provision are 

part of large integrated oil companies or large geographically diverse refiners. Some of these 

large refiners notified DOE that they were not going to respond to the survey because they did 

not believe they faced disproportionate economic hardship. 

Small refineries can suffer disproportionate economic hardship from compliance with the RFS 

program if blending renewable fuel into their transportation fuel or purchasing RINs increases 

their cost of products relative to competitors to the point that they are not viable, either due to 

loss of market share or lack of working capital to cover the costs of purchasing RINs. Since 

certain small refineries may have to rely on RIN purchases instead of blending as a RFS 

compliance strategy, scenarios where RIN prices might be substantially higher than their 

historical value or the cost of blending renewable fuels were evaluated. Profiles were developed 

of the small refineries to categorize profitability and financial health. Regional and local factors 

that could affect the ability to comply with the RFS were considered in the analysis. Through 

these factors, metrics were developed to evaluate whether each of the eighteen refineries that 

responded to the survey and fall within the scope of the study would suffer an economic hardship 

relative to an industry standard.
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Based on the developed metrics and analysis, thirteen of the eighteen refineries analyzed are 

recommended to receive an extension of their exemption. The refineries recommended are 

geographically diverse: [Redacted]. Of the five small refineries that did not receive the 

exemption, [Redacted]. The refineries recommended for the exemption are:

[Redacted]
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I. Study Objectives

The Energy Policy Act of 2005 (EPAct 2005) established the Renewable Fuel Standard (RFS)

program under section 211 (o) of the Clean Air Act (CAA) mandating gasoline sold in the 

United States contain a minimum amount of renewable fuel content determined on an annual 

production volume basis. The Energy Independence and Security Act of 2007 (EISA 2007) 

amended the RFS program by increasing the renewable fuels mandate from 7.5 billion gallons to 

15.2 billion gallons in 2012, and extending it to 36 billion gallons of renewable fuel to be 

blended in 20225. 

EPAct 2005 exempted certain small refineries from compliance with the RFS from 2007 through 

20106. EPAct 2005, through its establishment of section 211(o)(9)(A)(ii) of the CAA, required

that the U.S. Department of Energy (DOE) conduct a study for the Administrator of the 

Environmental Protection Agency (EPA) assessing whether RFS2 would impose a 

“disproportionate economic hardship” on small refineries, defined as those facilities with 

aggregate crude oil throughput that does not exceed 75,000 barrels per calendar day7. Based on 

the results of the study, EPA may be obligated to extend the RFS1 exemption to small refineries 

for at least two additional years beyond its current expiration date of 2010.

On February 24, 2009, DOE transmitted its study with recommendations to EPA. The study 

concluded that the market for credits (Renewable Identification Numbers, or RINs) was currently 

competitive, and found no reason to believe that a competitive market would disproportionately 

disadvantage participants who purchase credits rather than generating them through blending 

renewable fuels into their products. Therefore, the study concluded that the exemption for small 

refineries should not be extended beyond 2010. It was noted that, should market conditions 

change or if individual small refineries were experiencing economic hardship, small refineries 

maintained the right under Section 211(o)(9)(B) of the CAA EPAct 2005 to individually petition 

EPA for an extension of their exemption. 

Subsequent events required that the study be revisited. First, the economic downturn reduced the 

profitability of the refining industry, which has disproportionately impacted some small refiners. 

Second, the expiration of the biodiesel production credit reduced production and has caused the 

price of biomass-based diesel RINs to increase. Even though the credit was retroactively restored 

for 2010, these RINs remain relatively expensive. Finally, in order capture the unique factors 

 

5

The EPAct 2005 RFS program is abbreviated RFS1 and the EISA 2007 revisions to the RFS1 program is 

abbreviated RFS2 in the rest of this document. A glossary of relevant terms is provided in Appendix A.

6 EPA chose to exempt small refiners, defined as refiners producing gasoline from crude oil with fewer than 1,500 

employees and less than 155,000 barrels per day crude processing capability, as well as small refineries defined in 

Section 211(o)(1)(K) as those facilities with aggregate crude oil throughput that does not exceed 75,000 barrels per

calendar day Subsequently, EPA has concluded that it did not have the authority to extend the duration of the 

exemption period for all of the small refiners as defined under the original RFS rulemaking , but only those 

statutorily defined in EPAct 2005.

7 As defined in Section 211(o)(1)(K).
 2

contributing to disproportionate economic hardship, additional consultation with individual 

refiners was necessary.

On a parallel track to the changed market conditions, Congress directed DOE to revisit the issue 

of disproportionate economic hardship for small refineries and report its findings8. This study

addresses the concerns of Congress in directing DOE to:

Seek comments from owners of small refineries on the reasons why they may believe that 

they would experience disproportionate economic hardship if the small refinery exemption 

were not extended.

Assess RFS compliance impacts on small refinery utilization rates and profitability.

Evaluate the financial ability of individual small refineries to meet RFS requirements.

Estimate small refinery impacts by region.

Reassess whether small refinery compliance costs through the purchase of RINs is similar to 

the cost of compliance by purchasing and blending renewable fuels.

Estimate the economic impact of RFS on small refineries on a regional basis.

Given this Congressional direction, this study needed to consider the unique factors contributing 

to disproportionate economic hardship for individual small refineries in the study. Consequently, 

a survey of small refineries was necessary, something not included in the previous DOE study.

In order to evaluate disproportionate economic hardship caused by the impact of compliance 

with the RFS on small refineries, these compliance strategies had to be characterized and their 

varying impact on refineries investigated. There is a direct cost associated with participation in 

the program. The RFS program is based on a national mandate for renewable fuels, enforced 

through obligated parties who are responsible to EPA for their pro-rata share of the renewable 

fuel mandate. However, the program incorporates a market solution to the process of fulfilling 

the mandates, allowing trading between the obligated parties from those who over-comply to 

those who find it less advantageous to blend renewable fuels into the transportation fuel mix. 

Transfer of the obligation is formally accomplished through the market for RINs.

The absolute cost of compliance is one of the key factors in determining disproportionate 

economic hardship from compliance with RFS2. There are two major pathways that may be 

followed for compliance. One compliance pathway is blending renewable fuels with gasoline, 

which may require capital expenditures for equipment. The second pathway is purchasing and 

maintaining a portfolio of RINs. If certain small refineries must purchase RINs that are far more 

expensive than those that may be generated through blending, this will lead to disproportionate 

economic hardship for those effected entities. Economic theory suggests that the price of RINs 

would reflect the marginal cost of compliance with the RFS, that is, the most expensive cost of 

 

8 The Senate Report (Senate Report 111- 45) accompanying the FY2010 Energy and Water Development 

Appropriations Bill included language directing DOE to re-open the study and revisit the issue in greater detail 

completing the revised study by June 30, 2010. The Appropriations Bill directed DOE to collect data on small 

refineries and quantify the economic impact of RFS compliance. In addition, the Appropriations Conference Report 

(House Report 111-278) included language supporting the Senate Appropriations Report request.
 3

blending renewable fuels. The average cost of compliance may be much lower than the marginal 

cost. If the economics of blending ethanol are favorable, that is, ethanol is less expensive than 

the gasoline components it replaces, the compliance cost may be essentially zero for refiners that 

fulfill their obligation through blending renewable fuels. Such refiners would have blended even 

without the mandate. While current RIN prices for ethanol are moderate (adding less than 2 cents 

per gallon of renewable fuel), there are numerous circumstances when RIN prices could rise, 

increasing the cost of compliance and perhaps increasing the cost of compliance more for 

refineries that rely on RINs for compliance compared to those that do not. These circumstances

include both increases in the costs of renewable fuels and the inability to blend all of the 

mandated renewable fuel into conventional transportation fuels (the so-called blend wall).

Small refineries could have particular obstacles that would make compliance more costly than 

those of large integrated companies. Compliance costs and characteristics of small refineries that 

make them more vulnerable to financial distress may be unique to each small refinery. Since 

much of the information is not publicly available, the small refineries were surveyed to make a 

determination of disproportionate economic hardship. This information was supplemented by 

publicly available data, which also yielded the baseline from which disproportionate economic 

impact may be discerned. Given the unique nature of each refinery, it is not possible to make a 

recommendation on any refinery that did not submit a survey.

Disproportionate economic hardship must encompass two broad components: a high cost of 

compliance relative to the industry average, and an effect sufficient to cause a significant 

impairment of the refinery operations. The individual metrics for each refinery were grouped into 

two general categories: eight metrics representing disproportionate impacts on the refinery and 

three metrics representing the effect of compliance on the viability of the firm.

II. RFS Regulations

The first RFS regulation, referenced as RSF1 in this study, was specified in Section 1501 of 

EPAct 2005. This section added paragraph 211(o) to the CAA, requiring the EPA to promulgate 

regulations implementing a renewable fuels program. EPAct 2005 specified that the regulations 

ensure a specified volume of renewable fuel be blended into gasoline sold in the United States

each year, with the total volume increasing over time. The goals of the program included

reducing the Nation’s dependence on foreign sources of petroleum, increasing domestic sources 

of energy, and assisting in the transition to alternative fuels from petroleum in the transportation 

sector. 

The final RFS1 program rule was published on May 1, 2007, and the program began on 

September 1, 2007.

9

 RFS1 created a specific annual level for minimum renewable fuel use that 

increases over time – resulting in a requirement that 7.5 billion gallons of renewable fuel be 

blended into gasoline (for highway use only) by 2012. 

 

9 During 2006 an RFS was established using the default compliance criteria as specified by EPAct 2005.
 4

Under the RFS1 program, compliance is based on obligated parties meeting their annual 

Renewable Volume Obligation (RVO), which is published annually in the Federal Register by 

EPA. Obligated parties include refiners, blenders and importers of gasoline. The RVO is 

expressed as a percentage of total non-renewable gasoline sold by the obligated party in the 

specified calendar year. Compliance is demonstrated through the use of transferable credits 

called RINs, which are assigned to each batch of renewable fuel produced. For obligated parties

to show compliance, RINs must be acquired either by blending renewable fuel into gasoline or 

diesel, or by acquisition of RINs from other parties that have exceeded their RVO. 

Provisions of EISA 2007 significantly increased the volume of renewable fuel mandated under

the RFS. The required volume of renewable transportation fuel increased from nine billion 

gallons in 2008 to 36 billion gallons in 2022.

10

 RFS2 also established required volumes of 

cellulosic biofuel, biomass-based diesel fuel, total advanced biofuel, and total renewable fuel to 

be used each year.11 As with RFS1, the responsibility for enforcing the annual renewable fuel 

targets falls to EPA. In addition, the EPA is responsible for assessing domestic supply and 

setting appropriate percentage standards each year. Figure 1 compares the requirements of RFS1 

and RFS2.

 

10 http://www.epa.gov/otaq/fuels/renewablefuels/index.htm, accessed 12 20 2010.

11 The additional RFS2 biofuel requirements for cellulosic biofuels and biomass-based dieel fuel are “nested” 

requirements within the category of “advanced biofuels.” Likewise, “advanced biofuels” is a nested requirement 

within the category of “total renewable fuels.” 
 5

Figure 1. Comparison of RFS1 and RFS2 Volume Requirements

Note: Bio-mass based diesel yields 1.5 credits per gallon for the purpose of compliance with the Advanced and 

Renewable Standards. Aggregate bars represent the RFS2 requirements; line represents RFS1.

Rather than a complete departure from the earlier program, RFS2 represents an evolutionary 

development that both expands and extends the scope of the renewable fuels agenda, while 

carrying over to the new standard much of the structure and terminology from RFS1. 

RFS2 expands the fuel requirements to 36 billion gallons by 2022 and also expands the fuel 

types from on-road gasoline only to gasoline and diesel fuel for both on-road and off-road 

and to railroad locomotive and domestic marine fuels as well. 

Under RFS1, to ensure compliance, EPA devised a tracking system using RINs to meet a 

single RVO for renewable fuel. RFS2 retains the concept of the RVO, but expands it to 

include four distinct RVOs, one for each of the new types of fuels (Cellulosic Biofuels, 

Biomass-Based Diesel, Other Advanced Biofuels, and Cellulosic Diesel) resulting in four 

types of RINs. 

EPA established a new system, the EPA-Moderated Transaction System (EMTS), for the 

generation, trading and tracking of RINs. The effective date for RFS2 is July 1, 2010, and 

the regulation applies to all renewable fuel produced on or after that date. Because of the 

mid-year start date and carry-over ability of RINs, both RFS1 and RFS2 versions of RINs 

will be in force in 2010 and beyond.

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Bio-mass Based Diesel 

(Advanced) 0.5 0.65 0.8 1 1 1 1 1 1 1 1 1 1 1

Other Biofuels 

(Advanced) 0 0 0 0 0.25 0.5 1 1.5 2 2.5 3 3 3 3.5

Cellulosic (Advanced) 0.1 0.25 0.5 1 1.75 3 4.25 5.5 7 8.5 10.5 13.5 16

Conventional Biofuels 4 4.7 9 10.4 12 12.4 13.2 13.8 14.4 15 15 15 15 15 15 15 15

RFS1 4 4.7 5.4 6.1 6.8 7.4 7.5 7.6 7.7 7.8 7.9 8.1 8.2 8.3 8.4 8.5 8.6

0

5

10

15

20

25

30

35

40 Billion Gallons 
 6

RFS2 changes the definition of qualified renewable fuels to include minimum lifecycle 

greenhouse gas (GHG) emission reduction thresholds for each of the renewable fuel types as 

measured against the performance of gasoline or diesel derived from conventional production 

techniques. The reduction requirements must be at least: 

o 60 percent for Cellulosic Biofuels (including Cellulosic Diesel)

o 50 percent for Biomass-Based Diesel and Other Advanced Biofuels

o 20 percent for other Renewable fuels such as corn ethanol from plants built after 

December 19, 2007. 

The minimum GHG reduction requirements must include consideration of the complete lifecycle of the fuel, including the planting, growing and harvesting of the feedstock and

production and distribution of the resulting fuel. In addition, the indirect land use impacts 

brought about through increased use of biofuels are included. There are also restrictions on

the types of feedstocks used to make renewable fuel and the types of land used to grow and 

harvest feedstock.

RFS2 also provides for specific types of waivers and a system of credits for cellulosic and 

biomass-based diesel biofuels.

III. RINs

How RINs Are Used to Ensure Compliance with the 

Renewable Fuel Standard

For the RFS1 program, the EPA established a very specific method of tracking the production 

and ownership of the renewable fuels using a 38-character RIN. With the introduction of the

EMTS, the concept of the RIN has been retained, but modified, for the RFS2 program. The

EMTS is a central automated registry run by EPA that serves as the focal point for recording and 

tracking the various credits, trades, and the compliance of obligated parties and renewable fuel 

exporters. The EMTS records the generation and transfer of RINs, the central identifier that 

enables the obligated parties to demonstrate compliance, as well as track the volumes of 

renewable fuels. The RIN is generated by the producer or importer of renewable fuel and is 

assigned to batches of renewable fuel. The RIN is transferred with the physical volume of 

ethanol, representing the gallons produced through subsequent changes of ownership. 

On December 14, 2010, the EPA issued a clarification of its earlier Final Rule implementing the 

RFS2 program. Although the Final Rule gave an illustration of the 38-digit RIN code, the 

intention was only to use it as an example. Under RFS2 and the EMTS, RINs are not identified

by a 38-digit code, even though most of the information continues to be entered into EMTS. The 

main difference is that the “SSSSSSSS” and “EEEEEEEE” components for the batch “start” and 

“end” numbers are eliminated. The 38-digit code proved to be far too error prone to be retained 

as the mechanism for recording RIN transactions. In addition, because of changes in RFS2, there 

are also important differences with respect to the RR (Equivalence Value) and D codes 

(Renewable Fuel Type) in the RIN. 
 7

The Equivalence Values (RR in Table 1) are used to determine the number of gallon-RINs 

generated for a batch of renewable fuel. The intent is to reflect the specific energy content of 

each fuel relative to ethanol, which is defined to have an equivalence value of 1.0. The use of 

equivalence values in RFS2 will continue from RFS1 and non-ester renewable diesel will be 

required to have a minimum lower energy value of at least 123,500 Btu/gal in order to qualify for 

an equivalence value of 1.7 (see Table 1). In Table 1, if a company produces a 1,000 gallon 

batch of biodiesel, 1,000 Biomass-Based Diesel RINs would be generated, which could be 

converted to 1,500 corn ethanol RINs.

Table 1. RR Code Definitions

Renewable Fuel Equivalence Value RR Code

Ethanol 1.0 10

Biodiesel 1.5 15

Butanol 1.3 13

Non-ester Renewable Diesel 1.7 17

The D Codes, which identify the Renewable Fuel Category, embody another change in the RIN 

from RFS1 to RFS2. Under RFS1, there were only two fuel types. With RFS2, there are five 

codes applicable to four categories of renewable fuels: Cellulosic Biofuel, Cellulosic Diesel, 

Biomass-Based Diesel, Other Advanced Biofuel, and total renewable fuel (see Table 2). D code 

1 from RFS1 has been replaced with D code 3 in RFS2, and D code 2 from RFS1 has been 

replaced with D code 6 in RFS2. Cellulosic biodiesel is unique in that it may qualify for either 

the biomass-based diesel mandate or the cellulosic biofuel mandate, but not both. To distinguish 

it from fuel that may only fulfill the biomass based diesel mandate, it is assigned a separate D 

code of 7, which may be considered a subset of D code 3. 

Table 2. D Code Definitions

RFS1 RFS2

D Value Meaning D Value Meaning

1 Cellulosic biomass ethanol = 3 Cellulosic Biofuel

7 Cellulosic Diesel 

4 Biomass-Based Diesel

5 Other Advanced Biofuel

2

Renewable fuel not cellulosic 

biomass ethanol = 6 Renewable Fuel, corn ethanol

Currently, the marketplace is actively trading four types of RINs: Corn ethanol RINs (D6), 

cellulosic ethanol RINs (D3), biodiesel RINs (D4) and other advanced biofuels (D5, e.g., cane 

ethanol). It should be noted that the market also refers to these categories of RINs as Type C (for 

Cellulosic Biofuel), Type B (for Biomass-Based Diesel), Type A (for Other Advanced Biofuel), 

and Type R (for Renewable Fuel). This terminology is used interchangeably with their 

associated D codes, e.g., Types C, B, A, R are interchangeable with D Codes 3, 4, 5, and 6, 

respectively.
 8

Renewable Fuel Standard Volume Requirements and RIN 

Values Obligated Parties

Obligated parties required to comply with RFS2 include domestic refiners and blenders dealing 

with transportation fuels. Importers and foreign producers of transportation fuel used in the 

United States are also specified as obligated parties. While the scope of obligated parties has 

been expanded, the RFS2 program continued to provide exemptions for small refineries (and 

certain small refiners) until the end of 2010. The final RFS2 rule became effective July 1, 2010, 

and the percentage standards apply to all gasoline and diesel fuel produced or imported for the 

full year 2010. However, RINs generated under RFS1 (including those in 2010 before the Rule 

became final) and certain carryover RINs from 2008 and 2009 will be credited toward the 2010

RVO. 

For each gallon of renewable fuel produced, a single credit (or multiple credits in the case of an 

equivalence value greater than one) is generated. These RIN credits are then moved from one 

party to the next, as they pass through the supply chain, until they eventually find their way to an 

obligated party. RINs accompany the physical volume of renewable fuel until the renewable fuel 

is blended with petroleum, at which point it may be separated from the resulting finished 

transportation fuel. When a RIN is separated from the physical batch of fuel, the first digit of the 

RIN is changed from a 1 to a 2. An obligated party can obtain RINs either through the purchase 

and blending of renewable fuel with their petroleum product, or, through acquisition of separated 

RINs from blenders (those non-obligated parties and those who have exceeded their mandated 

volumes). Obligated parties must demonstrate compliance with the program at the end of each 

year by submitting a sufficient number of RIN credits to satisfy their pro-rata share of the overall 

mandate.

Calculation Issues

The following tables summarize the volume requirements for each main category of renewable 

fuel by year. The RFS2 regulations require progressively greater blending of renewable fuels 

each year. Table 3 shows the mandated volume for each of the categories of renewable fuel 

through 2022. 
 9

Table 3. RFS2 Annual Volumetric Requirements (Billion Gallons)

Year Conventional 

Biofuels

Advanced Biofuels Total 

Conventional & 

Advanced 

Renewable Fuel

Cellulosic 

Biofuel

BiomassBased Diesel

Other Advanced 

Biofuel to 

Balance

Total 

Advanced 

Biofuel

2009 10.5 0.5 0.1 0.6 11.1

2010 12 0.1 0.65 0.2 0.95 12.95

2010a 12 0.0065 1.15* 0.95** 12.95

2011 12.6 0.006 0.8 0.1 1.35 13.95

2012 13.2 0.5 1 0.0 2 15.2

2013 13.8 1 ≥1.0 0.25 2.75 16.55

2014 14.4 1.75 ≥1.0 0.5 3.75 18.15

2015 15 3 ≥1.0 1.0 5.5 20.5

2016 15 4.25 ≥1.0 1.5 7.25 22.25

2017 15 5.5 ≥1.0 2.0 9 24

2018 15 7 ≥1.0 2.5 11 26

2019 15 8.5 ≥1.0 3.0 13 28

2020 15 10.5 ≥1.0 3.0 15 30

2021 15 13.5 ≥1.0 3.0 18 33

2022 15 16 ≥1.0 3.5 21 36

* Combined 2009/2010 Biomass-Based Diesel volumes applied in 2010

** While Biomass-Based Diesel volume was increased to 1.15 billion gallons, Total Advanced Biofuels 

remained at 0.95 billion gallons for 2010.

Sources: EISA 2007, Public Law 110-140, pages 1522-1523 as amended by EPA 40 CFR Part 80 

Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program; Final Rule 

published March 26, 2010.

Each year, EPA uses these volumes and the U.S. Energy Information Administration (EIA)

estimate of transportation fuel demand for the next year to derive the RVO percentage for each 

biofuel type. These derived values for 2011 are shown in Table 4. The biofuel percentage 

multiplied by the actual volume of petroleum fuel imported or produced by the obligated party 

determines the number of RINs of each type that must be surrendered to EPA to meet the RFS2 

requirements. 

Table 4. Standards for 2011

Fuel Category

% of Fuel Required 

to be Renewable

Volume of Renewable Fuel 

(Billion Gallons)

Cellulosic biofuels 0.003% 0.0066

Biomass-based diesel 0.690% 0.80

Total Advanced biofuels 0.780% 1.35

Renewable fuel 8.010% 13.95

Source: Federal Register Vol. 75, No. 236 Thursday, December 9, 2010 pg 76793
 10

One of the possible sources of confusion with RFS2 is the way the RVO percentage 

requirements are calculated. Under RFS1, the percentage requirements applied only to one 

biofuel standard.12 The correct interpretation, due to the “nesting concept,” is that the total RVO 

percentage is 8.010 percent. The other (incorrect) interpretation is that the total RVO percentage 

is 9.483 percent, derived from the sum of 0.003, 0.69, 0.78 and 8.01 percent. 

EPA has the authority to adjust the mandated volume for Cellulosic Biofuel, Biomass-Based 

Diesel and, if necessary, for Total Advanced Biofuel if it appears there will be a shortfall in 

supply. As part of the RFS2 final rule, EPA reduced the 2010 Cellulosic Biofuel mandate from 

100 million gallons to 6.5 million ethanol-equivalent gallons. Each year during the summer, 

EPA is required to announce in the Federal Register the proposed requirements for the following 

year. EPA must publish the final rule for the following year volumetric requirements by 

November 3013.

The Value of RINs

Until mid-2010, the RIN market was almost exclusively corn ethanol from the RFS1 program. 

Since then, the RIN market expanded to include three advanced biofuels: cellulosic ethanol, 

biodiesel and cane ethanol. Today, there are four types of RINs traded: corn ethanol, cellulosic 

ethanol, biodiesel and advanced (usually sugar cane) ethanol.

Depending upon the relative price of gasoline and corn ethanol, blending corn ethanol may be 

economically attractive aside from the mandate. If so, the price of corn ethanol RINs will reflect 

their transaction costs. As the economics become less favorable for corn ethanol, blending 

decreases and the amount of corn ethanol consumed is reduced. Once the corn ethanol 

consumption starts to fall below the mandated level, RIN prices will rise. In equilibrium, RIN 

prices will rise to increase demand for corn ethanol to the mandated level.

Figure 2 shows the history of RIN prices since program inception and illustrates the significant 

challenges faced by the biodiesel and cellulosic ethanol segments. Biodiesel and cellulosic RINs 

have traded at a substantial premium to corn ethanol RINs. This is a result of supply-side 

pressures associated with the limited production of biodiesel and cellulosic ethanol compared to 

corn ethanol. Biodiesel RINs have continued their upward trajectory, reaching over $1.10 per 

RIN in March, 2011. Renewable RINs have remained at historically low levels of $0.02 -$0.03 

per RIN through February, 2011

 

12 RFS1 specified different compliance values for certain types of biofuels (e.g., a gallon of biodiesel fuel had a 

higher compliance value than ethanol). These compliance values would be used to calculate an obligated party’s 

compliance volume but that volume would only be measured against one RVO.

13 More information on RIN market operations and compliance costs may be found in Appendix B.
 11

Figure 2. Historical Renewable and Biodiesel RIN Prices 

Source: OPIS for 04/02/2008 - 08/09/2010.

Approximately 75 to 80 percent of all U.S. biodiesel production capacity is currently idle due to 

the high cost of raw materials (soy bean oil, other vegetable oils, fats, and greases) relative to the 

value of the recipient petroleum diesel. Through December 2009, the biodiesel industry was 

supported by a federal tax credit of $1.00 per gallon for virgin feedstocks, and to a lesser extent, 

a European import tax credit that provided a market for biodiesel exports to Europe. While the 

biodiesel credit was reinstated retroactively at the end of 2010, its impact on supply has not yet 

been felt.

Cellulosic RINs are expensive because of the lack of Cellulosic Biofuel production. The 

technology for cellulosic ethanol production is still in the development stage and could be 

several years from commercial-scale production. If EPA determines that insufficient cellulosic 

production capacity exists, it may lower the cellulosic mandate and offer cellulosic RINs up to 

the total revised mandated level at a statutory price. In 2010 and 2011, EPA lowered the mandate 

for cellulosic ethanol to 6.5 and 6.6 million ethanol-equivalent gallons, respectively. The price 

was set at $1.56 per RIN for 2010 and $1.13 for 2011.

RINs have a two-year shelf life: the current year (year generated) and the subsequent year. 

Twenty percent of current-year RINs can be carried over to the subsequent year. For the last 

several years, there has been a large discount of previous-year RINs versus current-year RINs 

because of the success in the overall satisfaction of the current-year RVO. Figure 3 illustrates

the relative values of current-year and previous-year RINs since inception. 

0

10

20

30

40

50

60

70

Apr-08 Jul-08 Oct-08 Jan-09 Apr-0 9 Jul-09 Oct-0 9 Jan-10 Apr-10 Jul-10

¢/gallon

Ethanol RIN Biodiesel RIN Cellulosic RIN

Figure 1. Tight Supplies of Biodiesel and Cellulosic Ethanol RINs 

Source: OPIS, Refined Spot Prices for 04/02/2008 - 08/09/2010
 12

Figure 3. Carry-Over and Current-Year RIN Prices 

Source: OPIS for 04/02/2008 - 08/09/2010.

Ethanol serves to displace other blending components of gasoline. When ethanol is expensive, 

higher RIN prices provide an incentive for blenders to continue to use ethanol up to the 

statutorily-mandated level. Historically, there has been a close correlation between the value of 

corn ethanol RINs and the price of corn ethanol relative to gasoline. Figure 4 compares corn 

ethanol RIN prices with the corn ethanol-versus-RBOB14 price spread for four major U.S.

petroleum product markets; NY Harbor, US Gulf Coast, US West Coast (LA) and Chicago.

When corn ethanol prices are high relative to gasoline, corn ethanol RIN prices also tend to be 

high. When corn ethanol prices are low relative to gasoline, corn ethanol RIN prices tend to be 

low as well. For most of 2010, corn ethanol traded at prices below the price of gasoline, creating 

a substantial financial incentive for corn ethanol blending. As a result, as of February, 2011 corn 

ethanol RIN prices are still at historic lows, hovering around $0.02-$0.03 /gallon.

Obligated parties typically keep close track of their RIN balances, estimating whether they will 

be long or short at the end of each quarterly reporting period. Manufacturing upsets, shifts in 

gasoline blending and changes to the supply/demand balance for products can cause unexpected 

changes to a company’s RFS compliance. Generally accepted accounting principles require a 

company to accrue a liability on its books at the end of a financial quarter when they are in a 

short position and need to purchase RINs. 

 

14 Reformulated blending oxygenated blendstock 

0

2

4

6

8

1 0

1 2

1 4

1 6

1 8

2 0

Apr-08 Jul-0 8 Oct-0 8 Jan-0 9 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10

¢/gallon

Current Year

Previous Year

Figure 2. Carry-Over and Current-Year Ethanol RIN Prices 

Source: OPIS, Refined Spot Prices for 04/02/2008 - 08/09/2010
 13

Figure 4. RINs Prices Track the Ethanol-RBOB Spread

Source: Derived from OPIS, Refined Spot Prices for 04/02/2008 - 08/09/2010.

As shown in Figure 4, there were occasional end-of-quarter spikes of RINs which were likely 

caused by the mandated quarterly settlement and reporting process. Firms unable to meet their 

obligation needed to “pay up,” thus causing the apparent lag in RIN prices. The RIN market lag

appears to be about two months. 

IV. The Blend Wall

There has been considerable discussion among industry and government policy makers about the 

looming “blend wall” and the impact this blend wall will have on ethanol producers, refiners and 

blenders, and, in particular, small refiners. There also has been concern about the how the blend 

wall will impact the industry’s ability to comply with RFS2, specifically to meet the renewable 

fuel volumes mandated by EISA 2007. 

A blend wall is the aggregate limit to which a renewable fuel can be blended into its recipient 

motor fuel. The blend wall reflects both physical limitations and regulatory restrictions on the 

ability of the vehicle/fuel system to absorb renewable fuels. As a result, a blend wall is specific 

to a particular renewable fuel and specific to a particular motor fuel. There are two primary 
 14

blend walls of concern: one encompasses ethanol blending in motor gasoline and another blend 

wall exists for biodiesel blends in diesel fuel. Since the latter mandate is so much smaller than 

the former, the ethanol blend wall is of the most concern. 

Implementation of ethanol blending requires changes in infrastructure and regulations. At times, 

the ethanol production capacity has exceeded the market’s ability to profitably execute ethanol 

blending, causing periods when the blend wall actively constrains the market. Continued 

infrastructure build-out has expanded the fraction of gasoline containing ethanol. However, EIA 

data has shown that ethanol blending has expanded to almost the entire gasoline pool. At this 

point, the blend wall cannot be alleviated through increased low-level blends such as E10 alone.

The blend wall is a function of a multitude of contributing factors occurring together or singly. 

Each of these factors plays a part in determining the maximum amount of ethanol blended into 

gasoline, and thus, each contributes to the timing of when the blend wall could be reached. 

Contributing Factors to Reaching the Blend Wall

The timing of when the blend wall occurs is a function of many contributing factors, including: 

1. Motor fuel demand. Ethanol is one of many components of gasoline. With minor 

exceptions, gasoline is either “neat” (without ethanol) or blended at a fixed proportion to 

gasoline. Therefore, the overall consumption of ethanol is proportional to demand for 

gasoline. Since the demand for gasoline is relatively inelastic relative to price, and 

ethanol has very little impact on the price of gasoline, overall consumption is directly 

proportional to the demand. Exogenous factors such as unemployment, fuel economy 

standards and the price of oil play an important role in the ability of the transportation 

fuel pool to absorb ethanol.

2. Federal, State and Local regulations/mandates/incentives. Not all gasoline contains 

ethanol. Numerous incentives exist for the production and consumption of ethanol. At the 

national level, these include the Volumetric Ethanol Excise Tax Credit (VEETC) and the 

small ethanol producer’s credit. Furthermore, numerous states have incentives and 

mandates for renewable fuels. California has a requirement for 10 percent ethanol in 

gasoline. Such incentives have encouraged infrastructure changes accelerating blending 

in almost all available gasoline pools.

Federal and State regulations have a significant impact on ethanol blending penetration 

and economics. Under Title I, the CAA puts the regulatory burden of compliance for 

criteria pollutants on the States, which develop regulations based on their local 

conditions. Because any change in the proportion of components of gasoline will have a 

significant impact on vehicle emissions, States must develop such strategies including 

ethanol blending limits in conjunction with EPA. The limit on blending has increased as 

more states have incorporated ethanol in their compliance strategies.

Biodiesel represents an alternative renewable fuel that does not impact the ethanol blend 

wall. Currently biodiesel receives a $1 per gallon tax incentive. Both Pennsylvania and 
 15

Minnesota have mandates for biodiesel consumption. Even with these incentives, 

biodiesel production costs are so high and acceptance so low that it is unlikely to be 

consumed in any greater than the minimum volume mandated by EISA 2007. 

3. Mid-level blends. If ethanol concentrations greater than 10 percent are allowed, this will 

increase the total quantity of ethanol consumed in transportation fuel and will raise the 

effective blend wall. However, there are numerous regulatory and logistical hurdles that 

must be overcome before the use of mid-level blends becomes widespread. Implications 

of mid-level blends are discussed in the section “E15 and the Blend Wall” on page 18.

4. E85 infrastructure. E85 is a mixture of approximately 85 percent ethanol and 15 percent 

gasoline. E85 use requires specialized (flex-fuel) vehicles. E85 does provide another 

outlet for ethanol. However, given the small number of flex-fuel vehicles currently in use, 

about 7.3 million according to EPA estimates, the opportunity to increase the blend wall 

through increased use of E85 is limited. In addition, the E85 delivery system is not well 

developed. Industry observers have estimated that there are currently only about 2,000 

E85 pumps in the US. For the E85 market to absorb significant additional quantities of 

ethanol, massive demand growth supported by infrastructure improvements would be 

necessary15.

E85 is a complement rather than a replacement for conventional fuels for flex-fuel 

vehicles. As such it must compete effectively on a per-mile basis. Therefore, ethanol 

must be sold at its energy content value, which is roughly 2/3 of that of gasoline. 

 These factors are summarized in Table 5 below.

Table 5: Blend Wall Contributing Factors

 

15 EPA-420-R-10-006, “Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis”, February 2010

Primary Factor Specific Factors

Motor fuel demand Sets limit for maximum ethanol in low level blends

 Incentives for expanding blending infrastructure through 

mandates and ethanol subsidies 

Legal restrictions on blending through CAA;State regulations 

on blending

Vehicle technology and warranties

 Allocation of underground storage tanks 

Dispenser certifications

Certification of blender pumps and dual fuel limitations

 E85 delivery system

 Limit on fraction of fleet using fuel

Limits on increased of mid-level 

blends

Federal, State and Local 

regulations/mandates/incentives

E85 market dynamics
 16

How Close is the Blend Wall

Some ethanol industry trade organizations have stated that the blend wall has already been 

reached because ethanol production has at times exceeded 10 percent of gasoline consumption. 

This percentage is often used as a proxy for the total amount of ethanol that can be blended into 

gasoline because 10 percent is the federally-mandated maximum ethanol content of gasoline 

consumed in National Ambient Air Quality non-attainment areas as defined in the CAA.16

EIA stated in July 2010 that while they were projecting that daily ethanol supply would briefly 

exceed 10 percent of daily motor gasoline demand in early 2011, they were also projecting that 

increasing daily demand of gasoline over the balance of the year would absorb the full year 

ethanol production. EIA’s statement makes an important point about the blend wall: the volume 

associated with the blend wall is more accurately discussed as an annual volume rather than a 

monthly volume.

Figure 5 shows EIA’s projection of the compliance pathway for the RFS2 program through 

2022. The line reflects the maximum amount of ethanol that may be blended into gasoline as 

E10. Any volumes above the line must be a high-level blend such as E85, or a non-ethanol 

renewable fuel. The difference between the yellow bar and the line represents the level of corn 

ethanol alone that cannot be absorbed into the transportation fuel pool. The physical limit to 

ethanol blending could be reached in 2012. However, RFS2 does not explicitly mandate an 

RVO greater than this physical limit until 2014, when the RVO is over 16 billion gallons of 

ethanol. 

A surplus inventory of RINs could delay the date when the RVO cannot be met if the physical 

blending limit has been reached. While RINs are generate by blending renewable fuel, surplus 

RINs from one year may be carried over for use in the compliance in the next. Based on 

consumption of ethanol over the last few years, it is estimate that approximately 1 – 2 billion 

RINs may be available. Such carryover RINs may influence the timing of when the blend is 

reached.

 

16 It is important to note, however, that 10 percent of gasoline demand is only a theoretical blend wall value and as a 

result provides only an estimate of the volume associated with the corn ethanol blend wall. Ten percent is a blend 

limit only in the absence of ethanol feedstock shortages, changes to federal regulations, imports/exports or a larger 

market for E15/E85, etc.
 17

Figure 5. RFS2 and U.S. Motor Gasoline Demand

Source: EIA data as of 9/6/10. 

Note: These calculations do not reflect the recent EPA decision to grant a partial waiver for E15 use in 

MY2001-2006 vehicles on January 21, 2011 and MY2007-Current vehicles on October 13, 2010

Consequences of Reaching the Blend Wall

When the blend wall is reached, there could be significant economic consequences for obligated 

parties such as refiners and ethanol suppliers. There will also likely be downward pressure on 

ethanol prices given that ethanol production capacity is still increasing while the ability to 

incorporate ethanol in the transportation fuel system is constrained. This may have a negative 

impact on ethanol producers.

As the blending opportunities become scarce, more expensive blending opportunities will be 

pursued. Current options include an increase in biodiesel and an increase in consumption of midor high-level ethanol blends. However, biodiesel is limited by limited feedstock supply, high

production costs and limited market acceptance. Mid- and high-level ethanol blends, such as 

E15 and E85, face current physical limits on distribution and vehicles that can use the fuel in 

additional to other market acceptance factors. These actions provide limited additional blending 

opportunities in the near term.

RIN prices should rise to reflect the most expensive blending opportunity taken. As the RFS 

mandate increases, obligated parties will demand more RINs, adding upward price pressure. As 

0.0

2.0

4.0

6.0

8.0

10.0

12.0

2008 2012 2016 2020 Million Barrels/Day

RFS-2 and U.S. Motor Gasoline Demand

Motor Gasoline Demand - EIA RFS2 Conventional Biofuels Cellulosic Biofuels

Renewable Fuel Mandate E10 Blendwall (Mogas*1.1)
 18

the mandate increases, increasing the supply of RINs becomes difficult or nearly impossible. In 

anticipation of the blend wall, obligated parties may stockpile RINs through discretionary 

blending in anticipation of a shortage of blending opportunities. Those parties that are short, i.e. 

cannot generate enough RINs through their own facilities to meet their RVO, will need to 

purchase RINs and could suffer significant economic hardship.

Declining ethanol prices would probably be favorable to refiners/blenders that predominately 

blend ethanol rather than purchase RINs for blending. Many small refiners do not retain control 

over the blending of their products, and must purchase additional RINs. Obligated parties that 

rely on purchasing RINs would be adversely affected when the blend wall is reached and their

RINs inventory has been depleted. 

The next section investigates the impact of the approaching blend wall on RIN prices through an 

econometric relationship developed between discretionary blending, corn ethanol prices and RIN 

prices.

E15 and the Blend Wall

On October 13, 2010 EPA granted a waiver for fuels containing up to 15 percent ethanol for 

vehicles of Model Year 2007 and later. On January 21, 2011 this waiver was extended to Model 

Years 2001 – 2006 vehicles. This waiver covers approximately 2/3 of the light duty vehicle 

fleet. While it may appear that these E15 waivers substantially increased the amount of ethanol 

that could be blended into gasoline before the blend wall is approached, there are several reasons 

why this may not be the case. In particular, there are numerous obstacles to overcome before 

E15 blends become viable in the marketplace. 

Current pumps are not certified for blends above 10% ethanol. While it is likely that E15 

would not harm conventional pumps, liability concerns would no doubt limit the 

distribution of the new fuel. Replacing pumps would cost anywhere from $750 per pump 

if only the hanging hardware needs replacing up to approximately $11,000 per pump if 

interior components also need to be replaced17.

Many refueling stations have only two tanks for gasoline, usually one for premium and 

one for regular gasoline. Mid-grade gasoline is a blend from each tank. Gasoline stations 

could be unwilling to switch to a fuel that only a portion of their customer base would be 

able to purchase. 

While EPA has certified the mid-level blends, automobile manufacturers have not 

followed suit by explicitly modifying their warranties to include E15. It is unclear 

whether consumers would purchase a fuel that is not covered by their vehicle 

manufacturer’s warranty.

Various regulatory requirements would need to be adjusted. For instance, conventional 

gasoline that is sold as E10 is currently granted a 1-lb waiver on its summer Reid Vapor 

Pressure (RVP) specification. Either a new rulemaking would be required for E15 or 

 

17 EPA-420-R-10-006, “Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis”, February 2010, pg 

800.
 19

refiners would have to develop a special low RVP blendstock. Similarly, EPA has 

developed specifications for Reformulated Gasoline (RFG), a clean-burning fuel required 

to be used by certain areas under the Clean Air Act. The RFG specification would also 

need to be changed in order to accommodate ethanol blending over ten percent. Changes 

for both conventional and reformulated gasoline would require a new EPA rulemaking, 

which would necessarily take anywhere from months to over a year.

For all of the above reasons, it is unlikely that E15 will play a significant role in the 

transportation fuel market over the next few years. Therefore, this analysis did not analyze the 

impact of E15 on the gasoline and ethanol markets.

V. Evaluating the RIN and Ethanol Markets

A simultaneous multi-equation model of the ethanol fuels market was developed to evaluate how 

precipitation, crude oil prices and the RFS requirements affect corn and ethanol prices, RIN 

prices and the overall market equilibrium for ethanol. Appendix C describes the model structure, 

data and parameters, and provides a detailed analysis of the scenarios discussed below.

The model was used to identify conditions conducive to generating high corn ethanol RIN prices, 

such as drought or flooding, or increased discretionary blending of corn ethanol by obligated 

parties in order to stockpile RINs against potential shortages due to the blend wall. Scenarios 

were developed for 2011 and 2012, where the model derived ethanol demand and corn, ethanol, 

and gasoline prices using assumed values for crude oil, rainfall and the mandated level of ethanol 

consumption. Under optimal rainfall conditions and crude oil prices of $90-$92 per barrel, corn 

ethanol production will exceed the mandated levels in 2011 and 2012, and the ethanol is 

expected to be blended into the motor gasoline pool so that the number of RINs generated will 

likely exceed the RVO. Therefore, in the case where blending is economic, in a competitive 

market the price of corn ethanol RINs should reflect no more than their transaction cost. 

However, it is possible that obligated parties may increase blending relative to the mandated RFS 

level in anticipation of a shortage of blending opportunities due to the approaching blend wall. If 

market and meteorological conditions worsen, the combination of higher corn ethanol production 

costs and increased blending would likely lead to a sharp increase in RIN prices. Several such 

scenarios are explored below. 

The four scenarios described in Table 6 were used to project RIN prices (shown in Table 7) in 

2011 and 2012 for varying meteorological conditions, crude oil prices, and obligated party 

blending levels of corn ethanol.

18

 Scenario A represents a “Best Case Scenario” where optimal 

rainfall creates conditions for low ethanol prices due to a high corn yield. Scenario B dampens 

the expectations of a high corn yield by introducing poor rainfall conditions, which causes corn 

prices to increase and corn ethanol production to drop below mandated levels. In contrast, 

scenario C forces blending up to the RVO, which causes corn ethanol RIN prices to reach $0.38

and $0.64 per gallon of corn ethanol blended in 2011 and 2012, respectively. RIN prices 

 

18 Full description of the model can be found in Appendix C.
 20

increase to $0.92 and $0.95 in 2011 and 2012 under Scenario D due to over-blending by the 

obligated parties (under poor rainfall conditions). 

Table 6. RIN Scenarios Description

Scenario Precipitation

(Inches/Month) Blending Level

A Optimal (2.91) Unconstrained 

B Poor Rainfall (2.07) Unconstrained

C Poor Rainfall (2.07) Constrained (12.6 in 2011 and 13.2 in 2012) 

D Poor Rainfall (2.07) Constrained (13.2 in 2011 and 13.6 in 2012)

Table 7. RIN Price Scenario Results for 2011 and 2012 (2009 $)

 

19 EIA AEO2011 Rainfall VEETC

RIN Price

Ethanol 

Mandate

Mogas 

Use19

Crude Oil 

Price

Ethanol 

Productio

n

Ethanol % 

in MoGas

Ethanol 

Price

Corn Price

Wholesale 

Gasoline 

Price

Inches/ 

Month

$/ 

Gallon

$/ 

Gallon

Billion 

Gallons/ 

Year

Billion 

Gallons/ 

Year

$/Barrel

Billion 

Gallons/ 

Year

Percent

$/ 

Gallon

$/ 

Bushel

$/Gallon

2011

A 2.91 $0.44 $0.00 12.6 139.3 90 13.57 9.7% $2.94 $4.40 $2.60

B 2.07 $0.44 $0.00 12.6 139.3 90 12.17 8.7% $3.58 $6.83 $2.73

C 2.07 $0.44 $0.38 12.6 139.3 90 12.60 9.0% $3.75 $6.95 $2.76

D 2.07 $0.44 $0.92 12.6 139.3 90 13.23 9.5% $4.02 $7.12 $2.80

2012

A 2.91 $0.43 $0.00 13.2 143.0 92 14.02 9.8% $3.05 $4.42 $2.61

B 2.07 $0.43 $0.00 13.2 143.0 92 12.46 8.7% $3.69 $6.87 $2.73

C 2.07 $0.43 $0.64 13.2 143.0 92 13.20 9.2% $4.00 $7.08 $2.78

D 2.07 $0.43 $0.95 13.2 143.3 92 13.59 9.5% $4.14 $7.18 $2.80
 21

The scenarios considered are indicative of the types of events that could cause a significant 

increase in RIN prices, but are not designed to be exhaustive. For instance, a continued draw on 

U.S. corn reserves due to foreign demand would have a similar effect of a domestic reduction in 

production. The point of these scenarios is to demonstrate that relatively minor changes could 

dramatically raise the RIN prices from their current level. Such a scenario would have a 

significant impact on any small refinery that either physically did not blend or was not 

contractually obligated to receive the RINs generated when the purchaser blended the fuel.

VI. Determining Compliance Cost

Compliance cost information was compiled through interviews with several industry 

participants, including two refiners, three importers, a fuel marketer, and a corn ethanol 

marketer. Generally, companies who incur an RFS2 compliance cost are obligated parties who 

must buy RINs to meet their RVO, instead of blending renewable fuels. Many companies 

identify blending as a profit opportunity, as historically the price of gasoline of has generally 

exceeded that of ethanol. These companies reported that the market for RINs has thus far been

liquid, implying that RINs are generally available for purchase and no single participant is 

setting prices. Obligated parties who could do so generally blended corn ethanol beyond their 

RVO because corn ethanol was inexpensive relative to BOB (Blendstock for Oxygenate 

Blending) prices up until August 2010. Blending corn ethanol beyond their RVO creates surplus 

RINs, which in mid-September 2010 sold for around $0.04 per gallon. Biodiesel RINs have thus 

far been available, although have been an order of magnitude more expensive, at about $0.05 per 

gallon20. RIN sellers also include some blenders who do not have an RVO because they are 

typically gasoline marketers who buy ethanol and gasoline for blending and final sale. 

Obligated parties have a weighted average RIN obligation based on the percentages of the four 

types of renewable fuels. At current prices, this obligation is about 0.85 cents per gallon for each 

gallon produced or imported that is not blended with renewable fuel. Table 8 shows a sample 

calculation where the production volume is 1 million gallons and RINs are priced at midSeptember 2010 market values.

Table 8. Sample Obligated Party RINs Costs for 2010

Source: SAIC Analysis, EPA

 

20 As of February, biodiesel RINs, have continued to climb in price, currently well over $1 per gallon.

Renewable Fuel Type Standard

Gasoline & 

Diesel 

Production 

(gallons)

RVO # of 

RINs

RINS to 

Acquire

Mid 

September 

RIN Price 

($/gal) RIN Cost 

Cellulosic Biofuel 0.00004 1,000,000 40 40 $ 0.50 $ 20

Biomass Based Diesel 0.01100 1,000,000 11,000 11,000 $ 0.51 $ 5,610

Advanced Biofuels 0.00610 1,000,000 6,100 - $ 0.50 $ -

Renewable Fuels 0.08250 1,000,000 82,500 71,460 $ 0.04 $ 2,858

Total 82,500 $ 8,488

Total $/gallon $ 0.00849
 22

Other observations from the interview process revealed:

Some of the companies were incorrectly calculating their RVO. Some firms reported 

calculations that resulted in costs about one-third higher than shown in Table 8.

Interview participants generally could identify the administrative cost of complying with 

RFS2 in terms of Full Time Equivalent (FTE) personnel. The highest administrative 

burden reported was 1.5 FTE. One firm had automated its administrative costs and was 

unable to break out the compliance costs.

For the capital costs for compliance, the data was somewhat limited. One refiner 

reported costs of $200,000 to $1,000,000 to modify its terminals for ethanol blending. 

The range was a result of whether the terminal had a tank that could be converted to 

ethanol storage. One marketer reported costs of $3,000,000 to convert its three-lane truck 

rack to ethanol blending. The other participants either did not blend renewables or used

third-party logistics service providers who made the required capital investments. EPA 

has estimated that adding ethanol blending and truck unloading facilities at a terminal 

costs approximately $800 thousand.

21

In most states, biodiesel blending is limited because biodiesel feedstock is expensive and 

consumer resistance to the blend exists. Five States have biodiesel mandates: Louisiana, 

Massachusetts, Minnesota, Oregon, and Pennsylvania, which encourage biodiesel 

consumption22. The vast majority of biodiesel production occurs in the Midwest, where 

blending creates biodiesel RINs which may be purchased throughout the U.S. Several 

participants stated that future market conditions were highly uncertain due to the 

expiration of the biodiesel tax credit. With the renewal of the biodiesel tax credit through 

201123, this is no longer an issue, though biodiesel RIN prices are still over $1.00 per 

gallon. For those refineries that intend to blend biodiesel, EPA has estimated adding 

biodiesel blending capability at approximately $500 thousand per terminal24. This 

includes blending equipment and ancillary piping and other modifications. 

A 50,000 barrel per day refinery that produces about 36,000 barrel per day of gasoline 

and diesel incurs a one cent per gallon RINs purchase cost which equals approximately a 

$5.5 million annually. Much of this cost may be seen as a reduction in that refinery’s 

annual pretax profitability. However, since all firms without exemptions must comply 

with the RFS2 progam, product prices should rise to reflect the additional costs. The 

 

21 EPA-420-R-10-006,“Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis”, February 2010, pg 

775.

22 “Alternative Fuels and Advanced Vehicle Data Center”, http://www.afdc.energy.gov/afdc/laws/ accessed March 

8, 2011.

23The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Pub.L. 111-312, H.R. 

4853) retroactively extended the biodiesel tax credit through 2011.

24 Ibid, pg. 797.
 23

degree to which the costs burdening small refineries will be passed through to the market

depends on many factors, including the market power and the relative cost level of a 

small refiner relative to other market participants. Therefore, in the current lower 

refining margin environment, the cost of the RFS2 regulations could have a material 

effect on small refinery profitability.

The response to the RFS2 requirements depends in large measure on the size and scope 

of the operations of individual companies. Larger refiners have options available on a 

scale well beyond those available to smaller refiners. Large integrated refiners can more 

easily obtain financing for blending facilities, generate options, accommodate their needs 

efficiently and shift emphasis from one sector to another as opportunities indicate. For 

example, over the past couple of years, compliance strategies for larger companies 

included engaging in joint ventures with ethanol producers, investing in companies in the 

renewable sector, or conducting research on renewable fuels. As a result, RFS2 

compliance costs for the larger refiner may be a small part of overall operating costs.

Small companies are more limited in their options. They face a number of challenges and 

access to capital is generally limited or not available. Even when capital is available,

they may have to choose between making substantial investments in blending and

investing in other needed facilities to improve operating efficiencies to remain 

competitive. 

The cost for small refiners to comply with the RFS2 requirements can be substantial. 

Costs associated with consultants and attorneys to ensure compliance, and joining 

RINStar or similar services can be burdensome. Their limited product slates coupled 

with an inability to blend renewable fuels means that many of the small refiners must 

enter the market to buy RINs. The cost to meet their individual RVO makes this aspect 

the most significant cost of compliance. 

VII. Refinery Classification

The oil industry encompasses a broad spectrum of companies. At one extreme, the multinational super majors have full vertical integration. Their operations encompass upstream 

(exploration, development, and production), midstream (transportation and refining), and

downstream (refining, marketing, distribution, and sales). Some integrated companies also 

operate on a world-wide basis but tend to concentrate their refining and marketing operations in 

the United States. These integrated refiners also enjoy economies of scale from ownership of 

upstream operations, large refining operations, and interests in the refined product distribution 

supply chain. 

All independent refiners that process crude oil domestically do not directly engage in upstream 

operations, but some do own pipelines and storage facilities. Although large independent 

refiners do not extract or produce crude oil, some participate in joint ventures involving 
 24

integrated refiners and/or crude oil suppliers (for example Motiva,

25 WRB Refining26). 

Consequently, some large independent refiners are indirectly linked to the diversified operations 

of their owners and can benefit from their vertical integration (exploration, refining, and 

distribution). 

Small refiners operate with limited access to resources under constrained market conditions, and

comprise a heterogeneous group of businesses. They may be classified as:

A subsidiary of a large integrated corporation with both upstream and downstream activities,

A company owning one or more small refineries with other lines of business contributing 

significantly to their total operations, or

A company with a single small refinery which provides the vast majority of the value of the 

enterprise.

Refiner-Blender Integration

Some larger oil refiners have started integrating ethanol manufacturing with their existing 

operations. This action has the effect of reducing their feedstock availability risk and of 

capturing some of the profitability of renewable fuels production. During the recent economic 

downturn, several ethanol manufacturers went bankrupt and some oil refiners were able to 

purchase distressed ethanol facilities at low prices. Currently, major oil refiners control about 7

percent of the U.S. ethanol capacity.

Valero has acquired a number of ethanol plants and initiated construction of others, at least one 

of which is co-located at a refinery. Valero entered into ethanol production in 2008 when they 

started buying ethanol facilities from VeraSun. They now own ten facilities with a renewable 

production capacity of 1.1 billion gallons per year. Sunoco and Flint Hills Resources also 

entered into ethanol manufacturing. Sunoco purchased a bankrupt ethanol plant in Fulton, NY, 

located near their Northeast refineries. It is reported that the plant will meet about 20 percent of 

the company’s ethanol needs. Flint Hills Resources purchased two facilities from Hawkeye 

Energy Holdings, in Menlo and Shell Rock, IA. The ethanol facilities are located near a Flint 

Hills refinery.

VIII. Small Refinery Exemption

In preparation for the RFS1 rulemaking, EPA convened a Small Business Impact (SBRFA) panel 

to examine the impact of the RFS1 program on small businesses. Subsequent to the discussions 

of the SBRFA panel, EPA chose to exempt small refiners with fewer than 1,500 employees and 

less than 155,000 barrels per day crude processing capability from compliance with the RFS1 

 

25 Motiva is a joint venture of Shell and Saudi Aramco

26 WRB Refining is a joint venture of Conoco and Cenovus
 25

program. Small refineries, as defined above, were also exempted from the RFS1 mandate 

through 2010. EPA concluded that it did not have the authority to extend the duration of the 

exemption period from RFS1 for small refiners.

27

In addition to the general regulatory flexibility for small business inherent in the Clean Air Act, 

Congress specifically addressed the potential for an extension of the small refinery exemption in 

EPAct 2005. Under section 211(o)(9)(A)(ii) of the CAA, the Secretary of DOE is required to 

conduct a study for the EPA Administrator to determine whether compliance with the RFS2 

program would impose a “disproportionate economic hardship” on small refineries, as defined as 

those facilities with production capacities under 75,000 barrels per calendar day. If the study 

found that disproportionate economic hardship would occur, EPA is obligated to extend the 

exemption to the RFS2 program for at least two additional years. In addition, small refiners and 

small refineries still maintained the right to petition EPA for individual exemption from the 

program. 

As required by EPAct 2005, the final RFS1 regulations exempted gasoline produced by small 

refineries from the renewable fuels standard through December 31, 2010. Since EISA 2007 did 

not alter that exemption in any way, EPA retained the small refinery temporary exemption in the 

RFS2 final rule without change (except for the fact that all transportation fuel produced by small 

refineries will be exempt, as EISA 2007 also covers diesel and non-road fuels). The RFS1 final 

rule also offered a temporary exemption to small refiners to allow the few small refiners who 

owned refineries larger than the statutory limit to also receive the exemption. Similarly, the 

RFS2 rule continued the small refiner temporary exemption for transportation fuel produced by 

small refiners through December 31, 2010.28

Small refineries and small refiners may also apply for an extension of the temporary exemption, 

based upon disproportionate economic hardship, on a case-by-case basis. Any small refinery or 

small refiner may apply at any time. In evaluating applications for this hardship provision, EPA 

will take into consideration information from this report, annual reports, RIN system progress 

updates, petitioners and consultations with the DOE.

IX. PI-588 Survey

Existing survey data collected by EIA was insufficient to determine which small refineries 

merited an extension of their RFS1 exemptions. The data collected by EIA is mostly volumetric 

information regarding production, inputs, imports, and stocks. Some retail and wholesale price 

data are gathered, but not for the specific renewable-based transportation fuels. Collection of 

ethanol is evolving, but there are still some limitations on the coverage. Financial data are 

gathered annually for major refiners only. Consequently, a new data source was needed if the 

 

27 “Final Report of the Small Business Advocacy Review Panel on EPA’s Planned Proposed Rule Regulation of 

Fuels and Fuel Additives: Renewable Fuel Standard Program,” September 5, 2008.

28 EPA Compliance Guide 4-1
 26

Congressional requirements for a revised Small Refiner Exemption Study were to be met. The 

PI-588 survey was developed over the summer of 2010 to acquire the needed data. After public 

review in the Federal Register, the survey received clearance from the Office of Management 

and Budget on September 22, 2010. 

This one-time, voluntary survey was distributed electronically on September 27, 2010, to 59 

refineries. It contained five parts:

Respondent Identification

Submission/Resubmission

Financial Health of Refinery

Market Compliance

Market Issues

Many of the questions sought three years of data (2007, 2008, and 2009). Future-looking

questions sought data for three prospective years (2010, 2011, and 2012). The cover letter, 

survey form, survey instructions, and electronic filing instructions are provided in Appendix D.

The 59 refineries were selected because they currently hold a waiver from EPA under the RFS2

program. These refineries are geographically diverse (see Figure 6) and represent various 

company sizes and structures. They include:

[Redacted]

Figure 6. Small Refineries Receiving the PI-588 Survey

[Redacted]

[Redacted] of the refineries currently holding waivers belong to [Redacted] major refiners Two 

refiners, [Redacted], responded by declining to participate in the survey; stating that they would 

be unlikely to be classified as suffering disproportionate economic hardship. Many of the small 

refineries owned by [Redacted] chose not to respond to the PI-588 survey. A total of 22 

refineries had responded to the survey when the response period was closed on November 10, 

2010. Three additional refineries sent in surveys in February, 2011. Surveys received from five

refineries currently holding exemptions were deemed to exceed the small refineries RFS 

exemption size threshold and two surveys were found to be incomplete for analysis. All 

responses were validated against annual and monthly EIA surveys. Validated data from 18

surveys that met all criteria were the basis of the analysis of disproportionate economic hardship 

(see Table 9). More specifics on the classification of the survey responses and their validation 

are provided in Appendix E (Confidential Business Information), while short summaries of each 

refinery examined may be found in Appendix F (Confidential Business Information).
 27

Table 9. Refinery Survey Responses by PADD and Ownership [CBI] used in 

Disproportionate Economic Hardship Analysis

Company Name Refinery Name State PADD Ownership

[Redacted]

X. Refinery Viability

Over the last few decades, refining has become an increasingly challenging business due to low 

refining margins and increasing regulation29. Refiner viability refers to the ability of the refiners 

to remain competitive and profitable. For example, as survey responses were being received, four 

refineries indicated [Redacted]. These are:

[Redacted]

These refineries did not submit surveys but their economic situations reveal the fragility of 

refinery viability. To further address the economic hardship faced by these [Redacted]

refineries and the 22 respondents, a series of small refinery profiles were prepared that 

incorporated key PI-588 and EIA survey data, corporate press releases and other news. These 

profiles are provided in Appendix F (Confidential Business Information).

 

29 More information on environmental regulations and refinery shutdowns may be found in Appendix G.
 28

To have four refineries idled in one year is unusual in recent years. Historically, the petroleum 

industry witnessed considerably more shutdowns each year, especially 1990-1995. As presented 

in Figure 7, over the past two decades, U.S. refiners faced generally low refining margins. The 

exception was a window of time from 2005 through 2007. An unusual combination of rising 

global refined product demand, temporarily constrained global refining capacity and hurricanereduced U.S. Gulf Coast refinery production combined to increase global refining margins for 

this three year period. Since 2007, conditions have changed and margins have slumped, 

returning to lower, more typical levels. 

Figure 7. U.S. Refining Margins and Shutdowns, 1990-2010

Source: Table 15. Refineries Permanently Shutdown By PAD District Between January 1,1990 and January 1, 2009, 

EIA, http://www.eia.gov/pub/oil_gas/petroleum/data_publications/refinery_capacity_data/ current/table15.pdf, BP 

Statistical Review of World Energy – June 2010, USGC WTS Coking Cash Margins, 

http://www.bp.com/sectiongenericarticle.do?categoryId=9023777&contentId=7044465, Accessed 10/13/10

The refining cash margin is typically used by the oil industry to evaluate the profitability of a 

given refinery. Frequently expressed in terms of cents per gallon or dollars per barrel 

throughput, it provides a way to measure the relative performance of one refinery versus another. 

Publicly-traded refining companies generally publish their refining economics in their reports to 

the Securities and Exchange Commission in sufficient detail to arrive at a reasonable estimate of 

the refining margin of their respective refineries. The 10K reports from 2004 to 2009 for several 

refining companies were analyzed. Figure 8 presents the results of that analysis. 
 29

Figure 8. Sample Refining Margins for Large and Small Refiners 2004 – 2009

Source: Company 10k reports and Stillwater analysis

The data indicates that refining margins for large refining companies (Chevron, ConocoPhillips, 

ExxonMobil, Tesoro, and Valero) were similar in trend to the refining margins for several 

smaller refining companies (Calumet, Delek, Frontier, Holly, and Western) during this period.

30

 

However, the margins for the small refiner group were on average less than the large refiner 

group. Margins for both groups peaked in 2006 or 2007 and were zero or negative for 2009. 

U.S. refiners have complied with a series of environmental regulations over the past two decades

(see Figure 9). This series of regulations forced U.S. refiners to invest billions of dollars for 

process, logistics and other capital upgrades. In addition, compliance with environmental 

regulations has increased the fixed and variable costs of refinery operations.31 The cost of 

compliance contributed to economic stresses that resulted in the shutdown of 66 refineries from 

1990 through 2010.

 

30 For several refiners, individual refinery or refinery business unit data was available. Tesoro reports data for their 

four refining business units which contain seven refineries. Delek, CVR, Holly, and Alon report individual refinery 

data.

31 EIA examines the costs of compliances in the 1990s in 

http://www.eia.doe.gov/emeu/finance/usi&to/downstream/ch4.html. 
 30

Figure 9. U.S. Refined Product Environmental Regulations 1990-2010

Source: SAIC, 2010, EIA Table 15 - Refineries Permanently Shut Down, 2010.

The reduction in capacity is mostly due to the shutdown of small-to-medium-sized refineries 

with less than 40,000 barrels per day capacity. This size is approximately half the size of the 

average operating refinery, which has grown from 80,000 barrels per day in 1990 to 120,000 

barrels per day in 2010. The average U.S. refinery has grown in size by 60 percent over the past 

two decades, as smaller refineries progressively become increasingly rare. 

The experience of the refining industry over the past two decades offers insight into the costs of 

compliance during periods of economic distress.

The majority of the shutdown refineries (46) were privately held:

Average size (~ 20,000 barrels per day) was half as large as that of publicly-held 

refineries

37 were shut during the 1990s

17 were located in PADD 3 and 14 in PADD 5
 31

Twenty idled refineries were publicly-held:

Closings were distributed throughout the period

Located primarily in PADDs 1 and 3

Average capacity was 40,000 barrels per day

XI. Disproportionate Economic Hardship

Based on an analysis of recent public statements by a number of U.S. refiners of varying size,

refiners appear to be somewhat optimistic regarding near-term improvements in the U.S. 

economy. As a consequence of improving economic conditions, they anticipate an increase in 

demand for gasoline, jet fuel and diesel fuel accompanied by rising refinery utilization and 

margins. 

However, despite this somewhat optimistic view, there a number of factors that will work toward 

minimizing demand growth and may actually reduce domestic demand. First, the RFS2 program

acts to progressively reduce demand for refinery produced gasoline and diesel products in the 

United States as the requirements for renewable products increases. Second, changes in the 

Corporate Average Fuel Economy (CAFE) and EPA GHG standards for new light-duty vehicles 

will negatively impact the demand for transportation fuels, renewable and petroleum alike. The 

projected reduction in demand for refinery-produced petroleum products was discussed in 

previously in relationship to the blend wall and illustrated in Figure 5 (page 17). As a result, the 

hoped-for improvement in refinery utilization and margins may be less than those during prior 

economic recoveries.

Even though the general trend is less favorable for refining industry, local markets do have an 

impact on refinery outlook. Some U.S. refiners service niche product markets (such as 

lubricants) and can be less vulnerable to lower profit margins while others service 

geographically-remote niche markets to buffer themselves from lower overall U.S. refining 

margins.

At the PADD level, differences in margin are also clear. The 3-2-1 Differential is often used as 

an approximate indicator of refining gross margins because it can be calculated based on publicly 

available refined product and crude oil pricing. Figure 10 illustrates that the 3-2-1 Differential 

for refiners in the Rocky Mountain and Mid-Continent Regions is generally greater than in the 

U.S. Gulf Coast.32 

 

32 The 3-2-1 Differential is the difference in price between 2/3 barrel of gasoline plus 1/3 barrel of diesel less 1 

barrel of crude oil (typically a light sweet crude oil like West Texas Intermediate).
 32

Figure 10. Crack Spread Differentials

Source Data: EIA.

Independent U.S. refiners are highly focused on maintaining sufficient capitalization because

they operate in a capital intensive business with continuous expenditures and volatile refining 

margins. Sufficient capitalization allows them to purchase crude oil and other feedstocks on 

competitive terms, to remain in regulatory compliance and to survive periodic downturns in their 

refining business. 

Independent refiners typically operate under a variety of debt covenants, including debt to equity 

ratios and other restrictions. Independents may have limited access to public or private debt 

depending on the number, size, complexity and location of refineries they own and the degree to 

which they are integrated in their refined product transportation, storage and retail marketing 

systems.

Assessing Disproportionate Economic Hardship

A scoring matrix was designed to evaluate the full impact of disproportionate economic hardship 

on small refiners and used to assess the individual degree of potential impairment. The matrix is 

comprised of two major sections described individually below: one section combining the 

scoring for disproportionate structural and economic weightings, and a separate section regarding 

the impact of compliance with the RFS2 program on the viability of the firm. Each of the eight 

individual disproportionate structural and economic metrics is weighted equally to derive the 

disproportionate impact index. The index is then scaled from 0 to 5, with 5 indicating conditions 

likely to lead to disproportionate economic hardship. Similarly, the three metrics for the viability 
 33

index are then equally weighted and scaled to the same range. The lines shaded gray have not 

been used in this analysis, but should be maintained as part of the matrix for use in the future 

when other renewable fuels become commercially available. 

Disproportionate Impacts Index Analysis

Disproportionate impacts consist of Disproportionate Structural and Disproportionate Economic 

measures, which are described below. Table 10 shows the Disproportionate Structural Impacts 

metrics.

Table 10. Disproportionate Structural Impact Metrics

1 Disproportionate Structural Impact Metrics

a Access to capital/credit

0 = Good access (BB- or above credit rating),

5 = Moderate access (rating in B’s) 

10 = Poor access (C rating or 50% D/E)

b

Other business lines besides refining 

and marketing

0 = Other Lines, 

10 = No Other Lines

c

Local market acceptance of 

Renewables 

0 = Products accepted, 

10 = Product not accepted

i E10

0 = High acceptance, 

5 = Low acceptance

10= No acceptance

ii E85 Not scored because of small E85 volumes 

iii Biodiesel Not available

d Percentage of diesel production

0 = D/(G+D) < Industry Avg. 

5 = D/(G+D) > Ind. Avg<40%.

10=D/(G+D) > 40%

e

Subject to exceptional state 

regulations

0 = not subject, 

5= Some barriers for compliance

10 = subject to exceptional state regulations

2 Disproportionate Economic Impact Metrics

a Relative refining margin measure

0 = Above 3 year industry average 5 = positive, 

and below 3 year industry average 

10= Negative, 3 average,

b Renewable fuel blending (% of production)

i Ethanol blending 0 = 75%+, 5 = 25-74%, 10 = <25%

ii Biodiesel blending (not used) 0 = 1.1% of diesel production, 

1 = <1.1%

iii Other Advanced Biofuel 

blending (not used)

0 = some blending, 

10 = no blending

c In a niche market

0 = niche

5 = moderate niche impact

10 = no niche

d RINs net revenue or cost 0 = revenue > cost, 

10 = revenue < cost

Subtotal
 34

1a. Access to capital/credit. Restrictions on capital may significantly limit the compliance 

options for firms. If new blending facilities are needed, borrowing would likely be necessary. 

High borrowing costs would have a disproportionate impact on the ability of less credit-worthy 

firms to comply with RFS2. In the worst case, loan covenants may prevent firms from taking

cost-effective measures for compliance. Even if the firm would be purchasing RINs, additional 

working capital may be needed to effectively manage the RIN purchases. Access to capital was 

provided by the survey respondents and publically available data. In the absence of credit ratings, 

other financial information provided by the respondent (such as debt/equity ratios) were used to 

determine an individual refinery score. Those companies with poor access to capital were scored 

a 10 as demonstrated by a credit rating of C or below were scored a 10, below BB- were scored a 

5, and those companies above a BB- were scored a 0. 

1b. Other business lines besides refining and marketing. Refining margins tend to have 

considerable volatility. Additional lines of business, in particular upstream operations such as 

exploration and development that are less correlated with refining, would tend to smooth the 

firm’s cash flows, and improve its ability to borrow money at closer to the investment grade 

rates. Those refineries without additional lines of business score a 10.

1c. Local market acceptance of Renewable Fuels. Local conditions may inhibit blending as a 

compliance strategy for meeting RVOs. Blending category can be separated as follows: low 

ethanol blends (E10), biodiesel and E85. There was no scoring for E85 and biodiesel due to a 

lack of data.

i. Ethanol blending (E10). Not every state has switched completely to E10. Some 

locations, due to either logistical obstacles or consumer behavior, still sell clear 

(unblended) gasoline. Refiners who reside in states with less than 75 percent 

E10 blending receive a 5; those with less than 25 percent blending receive a 10. 

Given the current state of ethanol blending, no state which participants in the 

program would cause a refiner to receive the higher score.

ii. E85. Reserved for later evaluation

iii. Biodiesel. Reserved for later evaluation

1d. Percentage of Diesel Production. While ethanol blending at 10 percent is already common, 

biodiesel is normally blended at 5 percent or less due to a lack of market acceptance. Therefore, 

refineries that disproportionately favor diesel production over gasoline inherently have a more 

difficult compliance pathway, as the percentage of renewable fuel available to blend into diesel 

is much lower than the 10 percent of ethanol that can be blended into gasoline. Refineries that 

have greater than the industry average of approximately 32 percent diesel production receive a 

score of 5; those at 40 percent diesel or above have a score of 10.

1e. Subject to exceptional state regulations. Certain states such as Tennessee and North 

Carolina require refiners to sell unblended fuel. Refiners are required to purchase RINs to meet 

their obligations even though they have no blending opportunities with this fuel. Also, under 

certain unusual circumstances, the interplay between the State regulations (such as the California 
 35

Low Carbon Fuel Standard) and the Federal RFS may increase compliance costs. Those refiners 

subject to exceptional regulations receive a 10.

2a. Relative refining margin measure. Refining margins differ from refiner to refiner for many 

reasons. In order to eliminate market volatility, a three year average was calculated for each 

small refinery. Refineries with a negative net average margin were scored a 10; those below the 

industry average were scored a 5. 

2b. Renewable fuel blending (% of production). The degree to which a small refiner can 

actively blend refinery production with renewable fuels is a large component of economic 

impairment. Generally, for ethanol, (and biodiesel and other advanced biofuels) the lower the 

proportion of renewable fuel blending the greater the impairment.

i. Ethanol. Those refineries with between 25 and 75 percent of their gasoline at 

E10 were scored a 5; those with less than 25 percent were scored a 10. 

ii. Biodiesel. Reserved for later evaluation.

iii. Advanced Biofuels. Reserved for later evaluation.

2c. In a niche market. The rationale for utilizing the classification of “niche” refinery is 

necessary to determine if it has access to specific geographical markets with limited alternative 

finished product supply or access to distressed crude oil supply, thus creating higher than 

industry refining margins for the niche refiner. Other refineries classified as “niche” are those 

that produce a specialty slate of products (lube oils, greases, asphalt, etc.) in addition to gasoline 

and diesel. The sale of these types of products will also result in higher than industry refining 

margins. Landlocked refiners whose immediate market does not have access to a refined product 

pipeline are scored a 0 as are or those whose primary products are not transportation fuels. 

Landlocked refiners with direct access to single pipeline are scored a 5. Refiners with access to 

more than one pipeline are scored a 10. 

2d. RINs net revenue or cost. This criterion was not utilized in the current assessment due to 

lack of consistency among the survey participants. However, depending upon the business model 

of the small refiner, complying with their RVO can either be a net cost if they purchase all of 

their RINs or can generate revenue should they be able to actively trade RINs in the open 

marketplace. Firms that have a small refiner exemption and generate revenue by blending 

renewable fuels and selling RINs are not experiencing hardship related to the RFS. The windfall 

profit may be utilized to offset other margin related impairments. From the DOE small refiner 

survey, many (but not all) the respondents blended ethanol in 2009. These firms separated RINs 

and either sold them into the market or held them for future use. Indeed, one publically traded 

firm reported $4 million of revenue from RINs sales in 2009.33 

 

33 Frontier Annual Report 2009 
 36

Viability Index Analysis

Refiner viability refers to the ability of the refiners to remain competitive and profitable. That 

requires sufficient profits to make investments in the refinery to remain competitive. In general, 

small independent refiners generally lack the revenue streams generated by crude oil production 

and national product marketing to counteract the historic volatility in cash flows from the 

refining industry. Therefore, under some circumstances, a small refinery may face compliance 

costs that would significantly impact the operation of the firm, leading eventually to an inability 

to increase efficiency to remain competitive, eventually resulting in closure. These impacts are 

evaluated in the viability metric shown in Table 11.

Table 11. Viability Metrics

3 Viability Metrics

a

Compliance cost eliminates efficiency 

gains (impairment)

0 = no impact on efficiency, 

10 = impact on efficiency

b Individual special events 

0 = no special event, 

10 = special event impacting viability

c

Compliance costs likely to lead to shut 

down

0 = not likely to shut down, 

10 = likely to shut down

Subtotal

3a. Compliance cost eliminates efficiency gains (impairment). This metric evaluates whether 

the totality of factors, including both survey results and public information would reduce the 

profitability of the firm enough to impair future efficiency improvements. While this would not 

lead to immediate shutdown, given the increasingly competitive refining market, significant 

constraints on efficiency improvements would eventually leave many small refineries at risk.

Refineries that receive a extension of their exemption and do some blending, could sell RINs to 

improve their ability to position themselves to economically comply with RFS2 (through capital 

expenditures for blending or increasing capital for a RIN purchase program), thus reducing the 

impact of their future RFS2 compliance. Thus refineries that currently score high in this category 

and receive an extension will likely see a reduction in the scoring of this category in the future.

3b. Individual special events. Refinery specific events (such as a shutdown due to an accident, 

and subsequent loss of revenue) in the recent past that have a temporary negative impact on the 

ability of the refinery to comply with the RFS.

3c. Compliance costs likely to lead to shutdown. Some refineries have a unique vulnerability

such as a weak competitive position and any significant additional burden could cause 

bankruptcy or closure. This metric covers those refineries indicating that compliance may lead to 

such an outcome. 
 37

Recommendation for Exemption Extension

Utilizing the individual scoring metrics and the previously described index analysis, Figure 11

shows the disproportionate impacts and viability indices for each of the eighteen refineries that 

submitted sufficient data to be evaluated34. A recommendation of disproportionate impact was 

determined if both indices were greater than 1. This requires a score equivalent to at least four of 

the eight metrics for disproportionate impact at the moderate level (5), and a positive value for at 

least one of the three metrics for the viability index. Thirteen of the eighteen refineries scored a 1 

or higher in both indices, thus qualifying for a recommendation for extension of their RFS1 

exemption.

Figure 11. Refinery Rankings by PADD

[Redacted]

XII. Findings and Conclusion

EPAct 2005, through the establishment of the RFS1 program, mandated a minimum renewable 

fuel content of gasoline, while exempting certain small refineries from compliance from 2007

through 2010. EPAct 2005 also required DOE to conduct a study for the Administrator of the 

EPA assessing whether the RFS would impose a “disproportionate economic hardship” on the 

statutorily defined small refineries. On February 24, 2009, DOE transmitted its study with 

recommendations to EPA.

In October 2009, Congress directed DOE to seek input from small refineries and revisit the issue 

of disproportionate economic hardship for small refineries. A survey of local market and 

financial data from currently exempt small refineries revealed individual differences between 

refineries that allowed the identification of disproportionate economic hardship among the 

respondents. 

Eighteen refineries responded to the survey and fell within the scope of the study, and it is 

recommended that thirteen of them should receive an extension of their RFS1 exemption. The 

refineries recommended were geographically diverse: [Redacted]. The refineries recommended 

for the exemption are:

[Redacted]

 

34 The scoring for individual refineries is presented in Appendix H.
Appendix A A-1

Appendix A. Glossary

Barrel: A unit of volume equal to 42 U.S. gallons.

Biodiesel: A fuel typically made from soybean, canola, or other vegetable oils; animal fats; and 

recycled grease. It can serve as a substitute for petroleum-derived diesel or distillate fuel. For 

EIA reporting, it is a fuel composed of mono-alkyl esters of long chain fatty acids derived from 

vegetable oils or animal fats, designated B100, and meeting the requirements of ASTM 

(American Society for Testing materials) D 6751.

Biomass: Organic non-fossil material of biological origin constituting a renewable energy 

source.

Blend Wall: The limit to which a renewable fuel can be blended into its recipient motor fuel. 

Typically used in reference to limits on ethanol’s integration into the U.S. fuel supply.

Blenders’ Credit: See Volumetric Ethanol Excise Tax Credit.

Blending Components (Motor Gasoline Blending Components): Naphthas (e.g., straight-run 

gasoline, alkylate, reformate, benzene, toluene, xylene) used for blending or compounding into 

finished motor gasoline. These components include reformulated gasoline blendstock for 

oxygenate blending (RBOB) but exclude oxygenates (alcohols, ethers), butane, and pentanes 

plus.

Charge capacity: The input (feed) capacity of the refinery processing facilities.

Clean Air Act (CAA): The law that defines the EPA's responsibilities for protecting and 

improving the nation's air quality and the stratospheric ozone layer. Originally signed in 1970, 

the last major change in the law, the Clean Air Act Amendments of 1990, was enacted by 

Congress in 1990. Legislation passed since then has made several minor changes.

Code of Federal Regulations: A compilation of the general and permanent rules of the 

executive departments and agencies of the Federal Government as published in the federal 

register. The code is divided into 50 titles that represent broad areas subject to Federal 

regulation. Title 18 contains the FERC regulations.

Crude Oil: A mixture of hydrocarbons that exists in liquid phase in natural underground 

reservoirs and remains liquid at atmospheric pressure after passing through surface separating 

facilities. Depending upon the characteristics of the crude stream, it may also include:

Small amounts of hydrocarbons that exist in gaseous phase in natural underground 

reservoirs but are liquid at atmospheric pressure after being recovered from oil well 

(casing head) gas in lease separators and are subsequently comingled with the crude 

stream without being separately measured. Lease condensate recovered as a liquid from 
Appendix A A-2

natural gas wells in lease or field separation facilities and later mixed into the crude 

stream is also included;

Small amounts of nonhydrocarbons produced with the oil, such as sulfur and various 

metals; and

Drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil 

shale.

E10, E15, E85: A fuel containing a mixture of ethanol and gasoline in a particular ratio. The 

number is the percentage of the fuel that is ethanol. For example, E85 is 85 percent ethanol and 

15 percent gasoline.

Energy Independence and Security Act of 2007 (EISA, or EISA07): EISA, Public Law 110-

140, was signed into law in 2007 to establish the Renewable Fuel Standard – 2 (RFS2). Its 

purpose was to move the U.S. toward greater energy independence and security, increase the 

production of clean fuels, and promote research on and deploy greenhouse gas capture and 

storage options.

Energy Policy Act of 2005 (EPAct, or EPAct05): EPAct, Public Law 109-58, was signed in 

2005 to establish the Renewable Fuel Standard (RFS1). Its purpose was to “ensure jobs for our 

future with secure, affordable, and reliable energy.”

EPA-Moderated Transaction System (EMTS): Electronic system used for the generation, 

trading, and tracking of RINs. Established as part of RFS2.

Ethanol: A clear, colorless, flammable alcohol. Ethanol is typically produced biologically from 

biomass feedstocks such as agricultural crops and cellulosic residues from agricultural crops or 

wood. Ethanol can also be produced chemically from ethylene.

Form 10-K: A form used by publicly traded companies to disclose information on an annual 

basis to the U.S. Securities and Exchange Commission. The annual report on Form 10-K 

provides a comprehensive overview of the company's business and financial condition and 

includes audited financial statements.

Gasoline (Finished Motor Gasoline): A complex mixture of relatively volatile hydrocarbons 

with or without small quantities of additives, blended to form a fuel suitable for use in sparkignition engines. Motor gasoline, as defined in ASTM Specification D 4814 or Federal 

Specification VV-G-1690C, is characterized as having a boiling range of 122 to 158 degrees 

Fahrenheit at the 10 percent recovery point to 365 to 374 degrees Fahrenheit at the 90 percent 

recovery point. Motor Gasoline includes conventional gasoline; all types of oxygenated 

gasoline, including gasohol; and reformulated gasoline, but excludes aviation gasoline.

Greenhouse Gases (GHGs): Those gases, such as water vapor, carbon dioxide, nitrous oxide, 

methane, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride, that are 

transparent to solar (short-wave) radiation but opaque to long-wave (infrared) radiation, thus 

preventing long-wave radiant energy from leaving Earth's atmosphere. The net effect is a 

trapping of absorbed radiation and a tendency to warm the planet's surface.
Appendix A A-3

Low Sulfur Diesel (LSD) Fuel: diesel fuel containing more than 15 but less than 500 parts per 

million (ppm) sulfur.

Naphtha: A generic term applied to a petroleum fraction with an approximate boiling range 

between 122 degrees Fahrenheit and 400 degrees Fahrenheit.

Net Refining Margin: Often expressed in dollars per barrel. The net refining margin is the 

difference between the gross refining margin and the costs of producing and selling the 

petroleum products (e.g., refining energy costs and selling costs). The net margin measures 

before-tax cash earnings from the production and sale of refined products. The net margin 

excludes peripheral activities such as non-petroleum product sales at convenience stores.

No. 2 Diesel Fuel: A distillate fuel oil that has a distillation temperature of 640 degrees 

Fahrenheit at the 90-percent recovery point and meets the specifications defined in ASTM 

Specification D 975. It is used in high-speed diesel engines that are generally operated under 

uniform speed and load conditions, such as those in railroad locomotives, trucks, and 

automobiles.

Obligated Party: Refiners, blenders, and importers of gasoline that are subject to the 

requirements of the RFS program.

Petroleum Administration for Defense District (PADD): A geographic aggregation of the 50 

States and the District of Columbia into five Districts, with PADD I further split into three 

subdistricts. The PADDs include the States listed below:

PADD I (East Coast): 

o PADD IA (New England): Connecticut, Maine, Massachusetts, New Hampshire, 

Rhode Island, and Vermont.

o PADD IB (Central Atlantic): Delaware, District of Columbia, Maryland, New 

Jersey, New York, and Pennsylvania. 

o PADD IC (Lower Atlantic): Florida, Georgia, North Carolina, South Carolina, 

Virginia, and West Virginia.

PADD II (Midwest): Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, 

Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and 

Wisconsin. 

PADD III (Gulf Coast): Alabama, Arkansas, Louisiana, Mississippi, New Mexico, and 

Texas.

PADD IV (Rocky Mountain): Colorado, Idaho, Montana, Utah, and Wyoming.

PADD V (West Coast): Alaska, Arizona, California, Hawaii, Nevada, Oregon, and 

Washington.

PI-588: A one-time, voluntary survey used by the EIA to collect information about small 

refineries designed to provide the necessary information to make an informed decision regarding 

which small refineries merited an extension of their RFS waivers. The PI-588 was developed 

over the summer of 2010, and received clearance from the OMB on September 22, 2010. It was 

distributed electronically on September 27, 2010 to 59 refineries. It is an Excel file consisting of 
Appendix A A-4

five parts: Respondent Identification, Submission/Resubmission, Financial Health of Refinery, 

Market Compliance, and Market Issues.

Refiner: A firm or the part of a firm that refines products or blends and substantially changes 

products, or refines liquid hydrocarbons from oil and gas field gases, or recovers liquefied 

petroleum gases incident to petroleum refining and sells those products to resellers, retailers, 

reseller/retailers or ultimate consumers. "Refiner" includes any owner of products that contracts 

to have those products refined and then sells the refined products to resellers, retailers, or 

ultimate consumers.

Refinery: An installation that manufactures finished petroleum products from crude oil, 

unfinished oils, natural gas liquids, other hydrocarbons, and oxygenates.

Refining Cash Margin: Represents all product revenues minus the costs of feedstocks (crude oil 

plus other feedstocks) and minus other operating costs. It is frequently expressed in terms of 

cents per gallon1.

Renewable Energy Resources: Energy resources that are naturally replenishing but flowlimited. They are virtually inexhaustible in duration but limited in the amount of energy that is 

available per unit of time. Renewable energy resources include biomass, hydro, geothermal, 

solar, wind, ocean thermal, wave action, and tidal action.

Renewable Fuel Standard (RFS1, RFS2): RFS1 was established in 2005 (effective 2007) with 

the passage of EPAct. RFS1 created a specific annual level for minimum renewable fuel use that 

increases over time. RFS2 was established in 2007 (effective 2010) with the passage of EISA. 

RFS2 is the revised and expanded version of RFS1.

Renewable Identification Numbers (RINs): RINs are assigned to each batch of renewable fuel 

produced. RINs demonstrate an obligated party’s compliance with its RVO under the RFS 

program.

Renewable Volume Obligation (RVO): RVO expresses the minimum renewable fuel use that 

obligated parties must meet under the RFS program. The RVO is expressed as a percentage of 

total non-renewable gasoline sold by the obligated party in the specified calendar year. 

Compliance is demonstrated through the use of RINs.

Small Refinery: A refinery for which the average aggregate daily crude oil throughput for a 

calendar year does not exceed 75,000 barrels. This definition comes from Section 

211(o)(9)(A)(ii) of the Clean Air Act.

Super Major: Term used to describe the six largest private-sector oil companies in the world. 

These six companies are BP, Chevron, ConocoPhillips, ExxonMobil, Royal Dutch Shell, and 

Total.

 

1

Page 121 (page 127 of the electronic version) 

http://www.eia.doe.gov/pub/oil_gas/petroleum/analysis_publications/petroleum_issues_trends_1996/ENTIRE.PDF
Appendix A A-5

Ultra-Low Sulfur Diesel (ULSD) Fuel: diesel fuel containing a maximum 15 parts per million 

(ppm) sulfur.

Volumetric Ethanol Excise Tax Credit (VEETC): Commonly known as a “blenders’ credit,” 

VEETC was created as part of the American Jobs Creation Act of 2004. It provides oil 

companies with an economic incentive to blend ethanol with gasoline.
Appendix B B-1

Appendix B. RFS Market Operations, RINs

and the Fuel Supply Chain

Evaluating Industry Obligations 

Stillwater Associates conducted informal telephone surveys with oil industry participants in 

August and September 2010 to gain information around the cost of complying with the 

Renewable Fuel Standard. Feedback was received from survey participants about how they 

calculated their Renewable Volume Obligation (RVO). Subsequently, it was discovered that 

these calculations were incorrect and would lead to potential over-compliance with RVO. With 

DOE’s concurrence, Stillwater then worked with EPA to gain clarity around the regulation. The 

following sections review the compliance process and address some ambiguities in EPA 

regulations. 

Participation in the RFS may have a significant impact on profitability depending upon RIN 

pricing. We quantify the impact of variations in pricing through an example. 

Background

The Energy Independence and Security Act of 2007 (EISA07), Public Law 110-140 passed by 

the 110th Congress of the United States, was signed on December 19, 2007 to establish the 

Renewable Fuel Standard – 2 (RFS2). As a result, on May 26, 2009, the US EPA issued its 

Notice of Proposed Rule Making and invited the industry to provide comments. The comment 

period was initially to expire on July 27, 2009, but was extended by 60 days to September 25, 

2009, to allow the public additional time to provide comment on the proposed rule. 

On February 3, 2010, the US EPA announced it had set the RFS2 factors effective July 1, 2010 

and followed its announcement on March 26, 2010 with its 236 page Final Rule 40 CFR Part 80 

published in the Federal Register pages 14669-15320. 

The first 195 pages of the Final Rule constitute the Preamble where various discussions, 

explanations and background information occur. Page 14717, attached as Table A, contains the 

formulas by which the RFS2 percentage factors are calculated, but the Final Rule does not show 

the values used in the formulas1. 

 

1

Preliminary values for 2011 may be found in the Federal Register Vol. 75, No. 138 pg 42250. Tuesday, July 20, 

2010. The final percentages may be found at in the Federal Register at Vol. 75, No. 236 Thursday, December 9, 

2010 pg 76804.
Appendix B B-2

The last 41 pages of the Final Rule contain the rules and is entitled “Part 80-Regulation of Fuels 

and Fuel Additives”. It contains Sections 80.1400 through 80.1468, with Sections 1405, 1407, 

1415, 1425, 1426 and 1427 being the greatest concentration of rules.

General Approach for Meeting the 2010 RVOs

First, calculate the total volume of on-road and off-road gasoline and diesel that is refined, 

imported or blended from components and thus is subject to an RVO.

Second, calculate the RVO for D Code 3 Cellulosic and subtract any 2009 rollover RINs subject 

to the 20% maximum rollover cap. The remainder is the amount of 2010 Cellulosic RINs needed 

to meet the 2010 Cellulosic RVO.

Third, calculate the RVO for D Code 4 Biomass Based Diesel and subtract the "Used" 2008 and 

2009 Biomass Based Diesel RINs available and the "Unused" 2008 and 2009 Biomass Based 

Diesel RINs available subject to the two rollover cap limits. The remainder is the amount of 

2010 Biomass Based Diesel RINs needed to meet the 2010 Biomass Based Diesel RVO.

Fourth, for any Cellulosic Diesel RINs D Code 7 RINs available, decide how many should be 

applied to the Cellulosic RVO and how many should be applied to the Biomass Based Diesel 

RVO.

Fifth, calculate the RVO for Total Advanced Biofuels and then subtract the rollover 2009 and 

2010 Cellulosic RINs, the 2010 Biomass Based Diesel RINs and the "unused" 2008/2009 

Biomass Based Diesel RINs. The remainder is the amount of 2010 D Code 5 Other Advanced 

Biofuel RINs needed to meet the 2010 Total Advanced Biofuel RV0. As you will note, the 

"Used" 2008/2009 Biomass Based Diesel RINs can be used to meet the 2010 Biomass Based 

Diesel RVO but not the 2010 Total Advanced Biofuel RVO.

Sixth, calculate the RVO for Total Renewable Fuels and then subtract the rollover 2009 and 

2010 Cellulosic RINs, the 2010 Biomass Based Diesel RINs, the "Unused" 2008/2009 Biomass 

Based Diesel RINs, the 2010 Other Advanced Biofuel RINs and the rollover 2009 corn ethanol 

RINs. (The sum of all of the rollover RINs is limited to the rollover cap of 20% of the 2010 Total 

Renewable Fuel RVO). The remainder is the amount of 2010 corn ethanol RINs needed to meet 

the 2010 Biomass Based Diesel RVO.

Conference Calls with the US EPA

During the Stillwater industry surveys conducted to assess DEH, it became apparent the industry 

interpreted the Final Rule in different ways. A series of conference calls were made between 

David Korotney of the US EPA and David Bulfin of Stillwater Associates LLC during 

November and December of 2010 to review how an Obligated Party (OP) should use its RINs to 

meet its RVO. A summary of the rules is as follows:
Appendix B B-3

1. Biomass Based Diesel RINs generated in 2010 can be used to meet the entire 2010 Biomass 

Based Diesel RVO, and can also be used to meet the 2010 Total Advanced Biofuels and the 

2010 Total Renewable Fuel RVOs.

2. Biomass Based Diesel RINs generated in 2008 and 2009 that were previously used for 

meeting the 2008 or 2009 RFS1 mandate (status “Used”), can be reused to meet the 2010 

Biomass Based Diesel RVO with no rollover cap. However, they cannot be used to meet the 

2010 Total Advanced Biofuels RVO or the 2010 Total Renewable Fuel RVO. Thus, if an OP 

uses lots of "Used" 2008 and/or 2009 RINs, the OP could fall short of meeting 2010 Total 

Advanced Biofuels RVO. As a result, the OP would need D Code 5 cane ethanol RINs to 

meet the Total Advanced Biofuels RVO.

3. An OP cannot purchase another company’s Used RINs to meet its own RVO.

4. Biomass Based Diesel RINs generated in 2008 and 2009 that were not used for compliance 

in 2008 or 2009 (status "Unused"), can be used to meet the 2010 Biomass Based Diesel RVO 

but are limited by the two rollover caps defined in 80.1427(a)(7)(iii). These RINs can be 

used to meet the 2010 Advanced Total Biofuel RVO and the 2010 Total Renewable Fuel 

RVOs.

5. "Unused" RINs were unused because they were either excess or they were attached to 

renewable fuels that were used as, or blended into, non-road fuels (boiler fuel, jet fuel). 

These RINs were not valid under RFS1, but can be reinstated (reactivated) under RFS2 for 

2010 only.

6. An OP can purchase another company’s unused RINs to meet its own RVO.

7. The use on Unused RINs is subject to two rollover caps.

8. The first rollover cap relates to 2008 excess and retired-then-reinstated Biomass Based Diesel 

RINs and is set at a maximum of 8.7% of the 2010 Biomass Based Diesel RVO. The 

rationale behind the 8.7% is explained in the middle of the far-right-hand column of page 

14719 of the Final Rule. When meeting the 2009 Biomass Based Diesel RVO of 0.5 BG, 

2008 RINs were limited to the 20% rollover cap, or 0.1BG. Carrying forward this 2008 RIN 

limit of 0.1 BG into 2010, it represents 8.7% (0.1/1.15) of the total 2010 Biomass Based 

Diesel RVO of 1.15 BG.

9. The second rollover cap relates to the total combined 2008 and 2009 excess and retired-thenreinstated Biomass Based Diesel RINs and is set at a maximum of 20% of the 2010 Biomass 

Based Diesel RVO. The rationale behind the 20% is it is a compromise rate between the 

refiners wanting 50% and the RFA wanting 0%.

10. If the 20% rollover cap limits the use of available RINs to meet a subcategory RVO, an OP 

can use the rest of the available subcategory RINs to meet a higher category RVO until its 

higher volume 20% cap is met. However, the US EPA assumes an OP would sell the more 

valuable sub-category RINs for cash and then buy the less valuable higher category RINs. 
Appendix B B-4

11. Each 20% rollover cap includes the sum of all the RINs being carried over for all the 

categories.

12. The 1.5 multiplier for Biomass Based Diesel is not applicable if volumes are expressed in 

terms of paper Gallon-RINs instead of physical gallons.

13. A D Code 7 Cellulosic Diesel RINs can be applied to either the Cellulosic RVO or the 

Biomass Based Diesel RVO, but not both.

Other comments from the conference calls with the US EPA are as follows:

1. Although there is a provision in the Final Rule to carry over 57% of 2010 Biomass Based 

Diesel RVO into 2011, the degree of complexity experienced in 2010 is not anticipated to 

occur in 2011. This is because no more “Used” prior year RINs are allowed and no more 

“Unused” RINs from 2 years prior are allowed.

2. Based on Table IV.B.3-2 on page 14752 of the Final Rule, from a practical standpoint there 

will be little or no D Code 7 (Cellulosic Diesel) RINs generated during 2008 and 2009. At 

the time of this writing, the US EPA does not recognize D Code 7 or D Code 5 RINs under 

RFS1 which lasted until June 30, 2010. However, Brazilian sugar cane ethanol imports 

would qualify as an Other Advanced Biofuel with a 50% GHG reduction and a D Code 5 

RIN.

Average vs. Marginal Ethanol RINs: 

The impact on refiner margins of a rapid rise in RINs prices can be illustrated by discussing the 

economics of three refiners in different circumstances relative to the RFS. In the illustration, 

Company A blends all its production with ethanol, so it does not have to purchase ethanol RINs. 

Company B does not do any blending and must purchase RINs to meet all of its RVO. Company 

C has excess RINs to sell into the market. Company C could be a blender that does not have an 

RVO, i.e. a gasoline marketer, or it could be a refiner who blends in excess of its RVO.
Appendix B B-5

In the above example, the companies experience an average price for gasoline, ethanol and RINs 

for eleven months of a year. In the last month, December, RINs prices increase by ten times, 

from 1.5 cpg to 15 cpg. The average RIN price is 1.5 cpg and the marginal RIN price is 15 cpg.

The companies value their gasoline at 200 cents per gallon and ethanol at 190 cpg. Companies A 

& C have a fuel margin on a gallon of E10 of 1 cpg, (10 cpg gasoline price – ethanol price times 

10%.) They reduce their excise tax obligation with the VEETC by 4.5 cpg of E10. 

Company A does not have to buy any ethanol RINs, so its “Blender Margin” is the fuel margin 

of 1 cpg + the tax credit of 4.5 cpg or 5.5 cpg. This reduces the cost of its product to 194.5 cpg.

Company B does not blend and has to buy RINs. Its total cost is 200.15 cpg. Company C blends 

ethanol, reduces its taxes and sells a RIN. This reduces its cost to 193.00 cpg.

On average, Company A has a cost advantage over Company B of 5.65 cpg and Company C has 

an advantage over Company B of 5.8 cpg. 

In the final month, when RINs prices go to 15 cpg, Company A’s advantage vs. Company B 

grows to 7.00 cpg and Company C’s advantage grows to 8.50 cpg. Assuming a net refining 

margin of 5 cpg, high RIN prices could significantly impair the profitability of non-blending 

small refineries.

Values in Cents per Gallon

Company A 

Blends to 

meet RVO

Company B Buys 

RINs to meet 

RVO

Company C 

has RINs to 

sell

Company A 

Blends to 

meet RVO

Company B 

Buys RINs to 

meet RVO

Company C 

has RINs to 

sell

Gasoline Price 200.00 200.00 200.00 200.00 200.00 200.00

Ethanol Price 190.00 n/a 190.00 190.00 n/a 190.00

Price Difference 10.00 n/a 10.00 10.00 n/a 10.00

Fuel margin/gallon of E10 1.00 n/a 1.00 1.00 n/a 1.00

VEETC (cpg of E10) 4.50 n/a 4.50 4.50 n/a 4.50

RINs Price (cpg of ethanol) n/a 1.50 1.50 n/a 15.00 15.00

RINs Price (cpg of E10) n/a 0.15 0.15 n/a 1.50 1.50

Blender Margin (cpg of E10) 5.50 n/a 5.65 5.50 n/a 7.00

Total Cost (cpg of E10) 194.50 200.15 194.35 194.50 201.50 193.00

Advantage vs. B (cpg of E10) 5.65 5.80 7.00 8.50

Average Values (over 11 months) Marginal Values (December)
Appendix B B-6

Table A. Calculation of RVO Percentages

Source: Vol. 75, No. 58 / Friday, March 26, 2010 pgs 14717- 14718.
Appendix B B-7

A Comparison of the Physical Flow of Product with the Flow of RINs

Figures B-1 and B-2 illustrate the physical flow of gasoline and ethanol in the distribution 

system. In Figure B-3, the flow of RINs is overlaid on the illustration of the physical flow. 
Appendix B B-8

Figure B-1. Physical Flow – Refinery Truck Rack

• The refiner manufactures gasoline 

and moves it to gasoline tanks 

connected to a truck loading rack

• Truck racks at refineries only supply a minor amount 

of fuel. Most production is pipelined away from the 

refinery to more distant truck rack terminals

• Ethanol is moved to an ethanol tank 

connected to the truck rack

• Ethanol and gasoline are blended together 

on the truck and are delivered to the service 

station

• The oval indicates that the refinery, tanks 

and rack are all at the refinery
Appendix B B-9

Figure B-2. Physical Flow – Off-Refinery Truck Rack

• The refiner manufactures gasoline 

and moves it to gasoline tanks 

connected to a truck rack

pipeline

• Ethanol is moved to an ethanol tank 

connected to the truck rack

• Ethanol and gasoline are blended 

together on the truck and are 

delivered to the service station

• The oval indicates that the tanks 

and rack are not located at the 

refinery
Appendix B B-10

Figure B-3. RIN Flow

Use for

Sell into

• Since the owner of the ethanol at the time of blending controls the RIN, 

refiners who do not blend all of their production with owned ethanol will have 

to buy RINs to meet their RVO

• The RIN is attached to ethanol 

when it ships from the ethanol plant

• The RIN remains attached to the 

ethanol while it is in the terminal tank. 

The RIN is the property of the entity 

who owns the ethanol volume. 

• Once the ethanol is blended onto 

the truck, the RIN is detached

• The owner of the RIN can use it to 

meet his RVO or sell it into the RIN 

market, or bank it to use at a later 

time
Appendix C C-1

Appendix C. DOE Ethanol Model 

Description

Through the use of an econometric model we investigate the impact of the combination of

precipitation, crude oil prices, and discretionary blending on the ethanol supply and demand 

market in the next two years, as well as the variables upon which ethanol depends: corn and 

ethanol prices. This appendix provides a five equation model determining ethanol supply and 

demand quantities and prices, price of corn, and the retail price of gasoline. The equations are 

estimated using two stage least squares with standard errors robust to heteroskedasticity and 

autocorrelation using yearly data from 1986 to 2009. The parameter estimates are intended to be 

used as a basis for examining policy questions regarding the ethanol market, RFS, and waivers 

within a stochastic framework. 

The model equations are presented below. 

Ethanol Supply (Equation 1)

ETHPROD t PETHANOL t PCORN t ETHPLANTS tln   0 1 2005  2ln 2005  3ln

Ethanol Demand (Equation 2)

t

t t t t

TREND PROD

ETHPROD PETHANOL D PGASOLINE MANDATE

_

ln 2005 ln 2005

4

0 1 2 3



   



   

Retail Gasoline Price Excluding Taxes (Equation 3)

PGASOLINE t REFINE UTILt RAC2005 tln 2005   0   1ln _   2ln

Corn Price (Equation 4)

PCORN t ETHPRODt CORNYIELDtln 2005   0  1ln  2ln

Corn Yield (Equation 5)

ln CORNYIELD tln PRECIPt(ln PRECIP)t 3TREND _CY 2 0  1  2  

All

 i

,  i,

i

 , i

,  icoefficients are calculated from regression analysis of the explanatory 

variables provided in each equation. Equations 3, 4, and 5 can be substituted into equations 1 

and 2, equated, and then solved for the PETHANOL2005D (price of ethanol in 2005 constant 

dollars).

Table C-1 summarizes the variables within the model, their units, and their dependencies. For 

example, historical precipitation data was used to create the regression model, and assumptions 

are made about the possible rainfall in 2011 and 2012. On the other hand, production of ethanol 

in billion gallons per year (Ethanol Supply and Demand) is calculated by the regression model, 
Appendix C C-2

and therefore an output of the model and directly and indirectly dependent on all model 

variables1. 

Table C-1. Model Variables

Variable Units Function of: Historical 

Data

Assumption 

(Input)

Regression 

(Output)

Precipitation Inches/Month --- Yes Yes ---

Ethanol 

Supply and 

Demand

Billion 

Gallons/Year 

Ethanol Price, 

Gasoline Price,

Corn Price,

Ethanol Mandate, 

Number of Ethanol 

Plants

Yes --- Yes 

Refiner 

Acquisition 

Cost (RAC) 

$/Barrel --- Yes Yes ---

Gasoline 

Price 

$/Gallon Refinery Utilization, 

Refiner Acquisition 

Cost (RAC)

Ethanol Price2

Yes --- Yes 

Ethanol 

Mandate 

Billion 

gallons/Year 

--- Yes Yes ---

Corn Price $/Bushel Ethanol Production, 

Corn yield 

Yes --- Yes 

Volumetric 

Ethanol 

Excise Credit

(VEETC)

$/Gallon --- Yes Yes ---

Ethanol Price $/Gallon Corn price, Refiner 

Acquisition Cost

Yes --- Yes 

Nominal monthly ethanol prices are average rack prices in Nebraska obtained from Nebraska’s 

Energy Statistics website and averaged to produce yearly prices. Ethanol production and the 

number of ethanol plants were obtained online from the Renewable Fuels Association. Nominal 

monthly corn prices are average prices received by farmers in the U.S. from USDA’s Economic 

Research Service (USDA/ERS) and converted to yearly prices. Corn yields were also collected 

 

1 Ethanol supply and demand are determined through equation one and two, but some variables of equations one and 

two are outputs of equation 3, 4 and 5.

2 Elasticity of ethanol price (as related to gasoline price) is determined to be 0.19 through regression analysis, for 

every 1% increase in ethanol demand price, all else constant, an increase of 0.19% is observed in the gasoline price. 

This elasticity is applied in model run post-processing. 
Appendix C C-3

from USDA/ERS. The nominal retail price of gasoline (exclusive of taxes) is the U.S. city 

average retail price for regular unleaded gasoline taken from EIA’s Monthly Energy Review and 

averaged to produce a yearly price. The nominal refiner acquisition cost is the U.S. crude oil 

composite acquisition cost by refiner and was collected from EIA. Refinery utilization rate is the 

annual refinery utilization rate provided by EIA. Precipitation figures for the U.S. corn-belt were 

gathered from the National Climatic Data Center website. All nominal dollar values were 

converted to constant 2009 dollars using the GDP deflator from the 2010 Economic Report of the 

President.

Historical values for all variables are presented from 1999-2010 and independent variables are 

projected into the future (2011 and 2012) in Figures C-1 through C-6, and dependent variables 

calculated by the regression model are presented in Figures C-7 through C-10. 

Figure C-1 details historical annual rainfall within the U.S. corn-belt for the last decade. As 

expected, rainfall varies each year. Rainfall data from 1986-2009 is used within the regression 

analysis, and over that time period the average annual rainfall is found to be 2.91 inches/month. 

Corn yield is intimately tied to the precipitation in any given year (equation 5) and maximum 

corn yield is attained at the average annual rainfall, thus allowing for modeling of drought and 

flood conditions. Any deviation from the average will yield a less than optimal corn yield, and 

Figure C-2 illustrates the affect on expected corn yield for 2011. 

Figure C-3 outlines the historical and projected Volumetric Ethanol Excise Credit (VEETC). 

Congress has recently passed legislation for continued VEETC of $0.45 per gallon, and this 

value is assumed for 2011 and 2012. The VEETC has decreased over the last decade in real and 

constant dollars, and is projected to be $0.45 (real dollars) in the near future. The VEETC is 

$0.44 and $0.43 in 2009 constant dollars for 2011 and 2012, respectively.

Refiner Acquisition Cost (RAC) is used as a regression variable to account for the influence of 

crude oil on ethanol production and consumption within the U.S. Typical RAC is a few dollars 

more than the WTI crude oil price. RAC is projected to be $82 for 2011 and $84 for 20123in the 

base case ($90 and $92.2 in 2009 constant dollars for 2011 and 2012, respectively). Figure C-4 

provides the RAC historical and projected values in constant 2009 dollars.

Figure C-5 provides the historical and projected number of ethanol plants within the U.S. 

Number of ethanol plants is used as a proxy for ethanol production capacity within the United 

States. As the U.S. production capacity gets close to the maximum mandate of corn ethanol (15 

billion gallons per year) new construction should slow and total number of plants should reach a 

maximum value4; thereafter, number of plants should decrease due to increased plant efficiency 

and economies of scale. 

Figure C-6 shows the historical and regression values for corn yield (bushels/acre). Corn yield 

has increased over the past decade and is expected to grow in the future. Corn yield is primarily

 

3 The RAC price represents the crude oil price as of December 2010.

4 The model uses a constant value of 170 plants in 2011 and 2012. 
Appendix C C-4

a function of rainfall and increasing efficiency of corn growers. Change in corn yield due to 

variability in rainfall has been demonstrated in Figure C-2. 

Figure C-7 provides historical and regression values for corn prices. Within Equation 4 corn 

price is a largely a function of corn yield and the volume of ethanol produced. However, 

Equations 1,2,3, and 4 have interdependent variables, thus corn yield is effectively a function of 

all model variables. Corn price varies with market and meteorological conditions, although 

general trend over the last decade indicates an increase in price. Under optimal rainfall 

conditions, and a crude oil price of approximately $90-$92.2 dollars, regression analysis projects 

a corn price of $4.40-$4.42 per bushel over the next two years.

Figure C-1. U.S. Average Annual Precipitation – Corn Belt
Appendix C C-5

Figure C-2. Projected Corn Yield vs. Rainfall (2010)

Figure C-3. U.S. Volumetric Ethanol Excise Tax Credit (VEETC)
Appendix C C-6

Figure C-4. Refiner Average Crude (RAC) Oil Acquisition Cost

Figure C-5. Number of Ethanol Plants in the U.S.
Appendix C C-7

Figure C-6. U.S. Corn Yield

Figure C-7. U.S. Corn Prices
Appendix C C-8

Figure C-8. U.S. Yearly Ethanol Production

Figure C-9. U.S. Retail Gasoline Price
Appendix C C-9

Figure C-10. U.S. Ethanol Supply Price

Figure C-8 details the historical ethanol production over the last decade and the regression results 

of ethanol production for 2011 and 2012 under optimal rainfall and approximately $90-$92.2

dollars crude oil price. Under optimal conditions ethanol production is expected to rise steadily 

to meet and exceed the corn ethanol mandate of 12.6 and 13.2 billion gallons per year.

Historical price of gasoline over the last decade and regression results for 2011 and 2012 are 

provided in Figure C-9. Retail gasoline price is a function of ethanol and crude oil price and 

under $90-$92.2 dollar crude oil price retail gasoline price is expected to be $2.68-$2.78 per 

gallon. 

Figure C-10 provides historical price of ethanol over the last decade and the regression results 

for 2011 and 2012. Ethanol price is a function of all of the model variables, and under $82-$84 

dollar crude oil price and optimal rainfall conditions ethanol price is expected to be 2.37-2.39

without the VEETC subsidy.

The DOE model describes the ethanol supply and demand market in the next two years, as well 

as corn, ethanol, and gasoline prices. Under optimal rainfall conditions and crude oil price of 

$82-$84 per barrel, the model predicts ethanol production above the mandated levels in 2011 and 

2012, within the motor gasoline pool and therefore the quantity of Renewable Identification 

Number (RINs) generated should exceed the Renewable Volume Obligation (RVO) comfortably

and RINs traded between parties should cost no more than the transaction cost. However, if 
Appendix C C-10

market and meteorological conditions are worse, then it is possible for reduced levels of ethanol 

production and blending which will lead to an increase in RIN prices. 

In the following analysis the DOE model is used to identify conditions that may be conducive to 

generating high RIN prices within the marketplace. Parametric analysis reveals that High RIN 

prices can be expected due to a period of drought or flooding, or over-blending of ethanol by 

obligated parties among other factors. 

The four cases in Table C-2 represent four states of the world that may exist in 2011 and 2012, 

and the assumptions for the cases. Scenario A represents a “Best Case Scenario” where optimal 

rainfall creates conditions for low ethanol price due to a high corn yield, crude oil price is 

maintained at December 2010 levels ($82-$84 per barrel), and ethanol production is 

unconstrained. Scenario B dampens the expectations of a high corn yield by introducing poor 

rainfall, leaving all other conditions the same as Scenario A. Poor rainfall is defined by reducing 

the average annual rainfall (in inches per month) from the optimal (2.91 inches/month) to rainfall 

amount two standard deviations below the normal (2.07 inches/month)5. Scenario C requires 

blending to increase to RVO, while under the poor rainfall condition described in Scenario B. 

Scenario D considers a situation where obligated parties blend above the RVO under poor 

rainfall conditions, in anticipation of future RIN shortages. 

Table C-2. RIN Scenarios Description

Scenario Precipitation

(Inches/Month)

Crude Oil Price

($/Barrel) Blending Level

A Optimal (2.91) ($82-$84) Unconstrained 

B Poor Rainfall (2.07) ($82-$84) Unconstrained

C Poor Rainfall (2.07) ($82-$84) Constrained (RVO- 9.0% in 

2011, 9.2% in 2012) 

D Poor Rainfall (2.07) ($82-$84) Constrained (9.5%)

Under Scenario A optimal rainfall and $82-84 crude oil prices ample existing ethanol production 

capacity within the U.S. allows for ample ethanol production in 2011 and 2012. 13.57 billion 

gallons of ethanol produced under optimal rainfall condition represents 9.7% blending of ethanol 

by volume in motor gasoline (139.3 billion gallons6) expected to be consumed within the U.S. in 

2011. Ethanol production is expected to increase to 14.02 billion gallons (10.1% blending of 

ethanol) in 2012 due to increases in overall ethanol production capacity under optimal rainfall 

conditions. Under Scenario A, the level of blending is above the required mandate of 12.6 

and 13.2 billion gallons in 2011 and 2012, respectively; therefore, over-compliance should 

lead to a surplus of RINs in the marketplace and RIN price can be expected to be negligible 

in 2011 and 2012.

 

5 The definition of a drought is beyond the scope of this paper. In order to approximate a drought condition, rainfall 

was set to two standard deviations below the mean, covering approximately 95% of all outcomes.

6 EIA AEO2011
Appendix C C-11

Under Scenario B, annual rainfall is expected to be two standard deviations lower than the 

optimal case (Scenario A). As expected, poor rainfall leads to a lower corn yield which puts 

upwards pressure on corn prices. Higher corn prices lead to reduced ethanol production and 

higher ethanol and gasoline prices. If ethanol blending is allowed to occur without regards to the 

RVO in 2011 and 2012 (no ethanol mandate), the model predicts reduction of 1.40 billion 

gallons of ethanol production an increase in corn price of $2.21 per bushel and an increase in 

ethanol price of $0.62 per gallon in 2011 when compared to Scenario A. Since the projected 

amount of ethanol produced in Scenario B is below the ethanol mandate (12.6 and 13.2 

billion gallons in 2011 and 2012) and obligated parties are required to blend to the RVO, 

Scenario B would require addition consumption of ethanol.

Scenario C forces obligated parties to blend to the RVO under poor rainfall conditions in order to 

comply with the RFS program, thus boosting ethanol production to 12.6 and 13.2 billion gallons 

in 2011 and 2012, respectively, as compared to Scenario B. A RIN cost of $0.35 per ethanol 

gallon blended is introduced within the model to increase ethanol production to 12.6 billion 

gallons in 2011 and from $.58 from 12.91 to 13.2 billion gallons in 2012. The other key prices 

and market metrics may be found in Table C-3 below. RIN prices of $0.32 and $0.58 may exist

in 2011 and 2012 in order to increase ethanol production to meet the mandate due to poor 

rainfall conditions outlined in Scenario C.

Scenario D investigates the possibility of over-blending under poor rainfall conditions. If 

obligated parties over-blend in order to accumulate RINs for future compliance, the increased 

production (and consumption) of ethanol may lead to higher RIN prices. Scenario D predicts a 

RIN price of $0.81 and $0.87 per ethanol gallon blended in 2011 and 2012, if the obligated

parties blend ethanol at 9.5% (by volume) within the motor gasoline pool. Corresponding 

corn, ethanol and gasoline prices may be found in Table C-3. 

All prices reported in Table C-3 are in constant 2009 dollars.
Appendix C C-12

Table C-3. RIN Price Scenarios for 2011 and 2012

 

7 EIA AEO2011 Rainfall VEETC

RIN

Price

Ethanol 

Mandate

MoGas

Use

7

Crude Oil 

Price

Ethanol 

Production

Ethanol % 

in MoGas

Ethanol 

Price

Corn Price

Wholesale 

Gasoline 

Price

Inches/ 

Month

$/ Gallon$/ Gallon

Billion 

Gallons/ 

Year

Billion 

Gallons/ 

Year

$/Barrel

Billion 

Gallons/ 

Year

Percent

$/ Gallon

$/ Bushel

$/Gallon

2011

A 2.91 $0.44 $0.00 12.6 139.3 90 13.57 9.7% $2.94 $4.40 $2.60

B 2.07 $0.44 $0.00 12.6 139.3 90 12.17 8.7% $3.58 $6.83 $2.73

C 2.07 $0.44 $0.38 12.6 139.3 90 12.60 9.0% $3.75 $6.95 $2.76

D 2.07 $0.44 $0.92 12.6 139.3 90 13.23 9.5% $4.02 $7.12 $2.80

2012

A 2.91 $0.43 $0.00 13.2 143.0 92.2 14.02 9.8% $3.05 $4.42 $2.61

B 2.07 $0.43 $0.00 13.2 143.0 92.2 12.46 8.7% $3.69 $6.87 $2.73

C 2.07 $0.43 $0.64 13.2 143.0 92.2 13.20 9.2% $4.00 $7.08 $2.78

D 2.07 $0.43 $0.95 13.2 143.3 92.2 13.59 9.5% $4.14 $7.18 $2.80
Appendix D D-1

Appendix D. PI-588 Survey Form

Introduction

The 2010 Small Refineries Exemption Study was developed to determine if small refiners suffer 

“disproportionate economic hardship” through compliance with the Renewable Fuel Standard 

(RFS). In an effort to collect input from small refineries for use in the study, the Department of 

Energy’s Office of Policy and International Affairs (PI) developed an original survey instrument 

to gather data on specific characteristics of individual small refineries. The optional survey 

allowed respondents to submit data that provided technical support for a determination of 

disproportionate economic hardship. 

The survey elements, in conjunction with previously collected and other public data were used to 

characterize the firm’s cost of compliance and its financial resilience in the face of estimated 

compliance costs associated with the RFS2 regulation. Data elements from the survey, including 

capital costs, operating costs, ability to generate Renewable Identification Numbers (RINs) and 

projected RIN costs were used to estimate the cost of compliance in cents per gallon of product. 

The survey was submitted to the Office of Management and Budget (OMB) for review and 

clearance on July 8, 2010. A Federal Register Notice1and 30 day public comment period were 

opened on July 15, 2010. 

The survey received clearance from the Office of Management and Budget on September 22, 

2010 and was distributed electronically via email to 59 small refineries on September 27, 2010. 

The survey was to be completed and returned electronically using a designated PI website by 

October 25, 2010.

The survey consisted of five parts:

Respondent Identification

Submission/Resubmission

Financial Health of Refinery

Market Compliance

Market Issues

Time series questions sought three years of data (2007, 2008, 2009 for historical series and 2010, 

2011, 2012 for future looking series). The cover letter, survey form, survey instructions, and 

electronic filing instructions are provided in this appendix.

 

1

Federal Register: July 15, 2010 (Volume 75, Number 135). http://edocket.access.gpo.gov/2010/2010-17288.htm
Appendix D D-2

Figure D-1. Survey Cover Letter
Appendix D D-3

Figure D-2. PI-588 Survey Form
Appendix D D-4
Appendix D D-5
Appendix D D-6
Appendix D D-7
Appendix D D-8

Figure D-3. PI-588 Survey Instructions
Appendix D D-9
Appendix D D-10
Appendix D D-11
Appendix D D-12

Figure D-4. Survey Submit Instructions
Appendix E E-1

Appendix E. PI-588 Survey Response

Survey Responses

The EPA list of refineries holding RFS exemptions served as the basis of identifying potential 

respondents to the PI-588 survey. Of the 59 refineries that met the qualifications for possible 

extension of exemption, [Redacted] submitted a Form PI-588. [Redacted] and [Redacted]

responded by declining to participate in the survey. One company, [Redacted], responded that 

[Redacted] they were not able to respond to the survey. Three companies advised DOE that 

their four refineries were either not producing transportation fuels or no long in operation due to 

financial hardship: 

[Redacted]

DOE permitted these four to forego submitting the survey. An additional [Redacted] refineries 

did not respond to the survey or communicate with DOE. Reminder emails were sent but no 

calls were made to non-respondents.

DOE received surveys from [Redacted] refineries. During validation efforts, five refineries 

were found to exceed the “small” threshold established for compliance with RFS2 guidelines:

[Redacted]

In addition, [Redacted] submitted incomplete surveys for its two refineries in [Redacted] and 

[Redacted]. These surveys could not be used in the analysis.

As a result, 18 surveys were considered valid and used in the disproportionate economic 

hardship analysis (see Table E-1). The refineries are distributed across all five PADDs, with five 

located in PADD 3 and four located in PADD 4. Nine of the refineries are privately held and 

eight belong to public companies (see Table E-2). 

Table E-1. Valid Refinery Responses by PADD and Ownership

[Redacted]
Appendix E E-2

Table E-2. Summary Responses by PADD and Ownership

[Redacted]

Validation of Form PI-588

To ensure the integrity of the data submitted on the Form PI-588,”RFS2 Small Refinery Survey 

2010,” responses to the survey were validated against information from other sources including 

survey data from the Energy Information Administration (EIA), corporate financial data 

submitted to the Security Exchange Commission (SEC), and information from previous studies. 

Edits that checked for possible inconsistencies or errors within the submitted forms were also 

developed and performed. In addition, analysts with extensive knowledge of the refinery 

industry reviewed the data for inconsistencies or possible errors. 

The validation of the Form PI-588 included:

Part 3, Financial Health of the Refinery

For publicly traded companies, responses to “Part 3, Financial Health of the Refinery” were 

compared to data reported to the SEC on Form 10-K. Edits were also developed and applied 

to all responses to insure the reasonableness of the data (e.g. the reported Gross Refining 

Margin is greater than the reported Net Refining Margin, the reported Rate of Return on 

capital projects greater than the reported Average Cost on capital projects,)

Part 4. Cost of RFS2 Compliance – Refinery Level

EIA data were used to validate responses to parts 4 and 5 of the PI-588 survey. The Office of 

Policy and International Affairs (PI) of DOE signed a Memorandum of Understanding with 

EIA that allowed PI to have access to petroleum data submitted to EIA from 2002 to the most 

current data available on appropriate weekly, monthly, and annual petroleum survey forms. 

The EIA data provided analysts with detailed respondent level data for analysis and 

background information, for use in portions of the report, and for validation of data provided 

by the respondents to the PI-588 survey. 

EIA refinery and terminal level receipts, inputs, and production data for motor gasoline 

blending components (MGBC), low and mid sulfur distillates, fuel ethanol, and bio-diesel 

submitted on Form EIA-810, “Monthly Refinery Report” and Form EIA-815, “Monthly Bulk 

Terminal and Blender Report” were used to validate refinery and terminal level input and 

blending cost of compliance data in Part 4 of Form PI-588. 

Part 5. Market Share – Refinery Level
Appendix E E-3

EIA refinery level operable capacity, crude inputs, and throughput data from Form EIA-810 

were used to validate how much of the transportation fuel produced at the refinery could 

accept renewable fuels and then be sold as gasoline, gasoline blendstock, or diesel fuel. 

EIA refiner level data on Form EIA-782C, “Monthly Report of Prime Supplier Sales of 

Petroleum Products Sold for Local Consumption” were used to validate the responses to the 

market share questions for sales of gasoline and diesel fuel. 

Validation Results

Data cells that failed edits or validation were reviewed by analysts. In some cases, the value was 

manually adjusted. This usually occurred because of an incorrect unit of measure, e.g. the form 

asked for thousands of barrels per day and the respondent obviously reported barrels per day. 

One question was disqualified from the PI-588 survey responses. Question 4.13 “How many 

RINS did you separate through blending in 2009?” was the source of 13 invalid and 7 valid 

responses. The overwhelmingly problematic response was not included in the analysis. With the 

removal of question 4.13, the overall invalid response rate for the survey was 13.4 percent.

For other edit or validation errors, the analysts determined if the response was reasonable or 

consistent with other available information or if the difference between the expected response 

and reported response was significant enough to change the determination of disproportionate 

economic hardship. None of the edit or validation failures were found to be significant enough 

to impact the refinery ranking scores in the scoring matrix developed to evaluate the individual 

degree of impairment of disproportionate economic hardship. A summary of the responses by 

participant may be found in Table E-3.
Appendix E E-4

Table E-3. PI-588 Survey Response and Disposition

[Redacted]
Appendix F F-1

Appendix F. Small Refinery Profiles

These profiles contained Business Confidential information and have been redacted.
Appendix G G-1

Appendix G. Shutdown Refineries

The past two decades have witnessed the permanent shutdown of 66 refineries in the United 

States. This appendix expands the discussion of shutdowns that appeared in Section X “Refinery 

Viability”.

Shutdown U.S. Refining Capacity 

As discussed in the Section X, refiners have experienced increasing costs due to environmental 

regulations and periods of low U.S. refining margins over the past two decades. During the 

period from 1990 to 2010 approximately 1.7 million barrels per day of U.S. refining capacity 

was shut down (see Figure G-1). The majority of the shut down capacity consisted of small to 

medium sized refineries. The loss of these smaller refineries, as well as existing refinery 

expansions, contributed to an increase in the average U.S. refinery size – up by approximately 60

percent over the last 20 years. 

Figure G-1. Average U.S. Refinery and Shutdown Refinery Sizes 1990 - 2010

Source: SAIC Analysis, EIA, Table 15. Refineries Permanently Shutdown By PAD District 

http://www.eia.gov/pub/oil_gas/petroleum/data_publications/refinery_capacity_data/current/table15.pdf, BP Statistical 

Review of World Energy – June 2010, U.S. Refining Capacities, 

http://www.bp.com/sectiongenericarticle.do?categoryId=9023777&contentId=7044465 The Growing Threat to US 

Refiners – U.S. Policy, Regulation and Low Cost Imports seen Triggering Rationalization, Brian L. Milne, 

http://oilspot2.dtnenergy.com/e_article001715841.cfm, Accessed 10/13/10.
Appendix G G-2

This analysis considered the ownership, geographic location, capacity, and last year of operation

for the shutdown refineries. This history can help explain current stresses on refineries suffering 

“disproportionate economic hardship.” Key features of the refinery shutdowns over the past 20 

years (from Tables G-1) include:

Total shutdown capacity of almost 1.7 million barrels per day was nearly equally divided 

between privately and publicly-owned refineries

Approximately twice as many private refineries were shut down than public ones

Almost three quarters (72 percent) of the refineries were shut down in the 1990’s. This 

includes:

o 81 percent of the lost capacity (37 of 46 refineries) operated by privately-owned

o 40 percent of the lost capacity (11 of 20 refineries) operated by publicly-owned 

refineries was shut down during the 1990s

Average size of privately-owned shutdown refineries were half as large as publiclyowned shutdown refineries

Average size of shutdown refineries increased over time as the smaller-sized facilities 

were shuttered

Large publicly-owned refineries became shutdown targets in 2009

Table G-1. U.S. Shutdown Refineries by Ownership and Date Shutdown, 1990-2010

Measure Ownership Date of Shutdown Total 1990-1994 1995-1999 2000-2004 2005-2010 Unknown

Number 

Private 23 14 5 3 1 46

Public 7 4 4 4 1 20

MBD 

Capacity

Private 326,450 375,350 123,315 32,500 6,100 863,715 

Public 229,675 98,500 83,880 414,000 3,000 829,055 

Average 

Size 

(MBD)

Private 14,193 26,811 24,663 10,833 6,100 18,776 

Public 32,811 24,625 20,970 103,500 3,000 41,453 

In addition to the timing of the shutdowns, the geographic distribution of those shutdowns is 

important (see Table G-2).

Most of the shutdown privately-owned refineries were located in PADDs 3 and 5

Most of the shutdown publicly-owned refineries were located in PADDs 1 and 3

Privately-owned shutdown refineries appear to be smaller than 33,000 barrels per day on 

average regardless of the location

Shutdown privately-owned refineries were largest in PADD 2 are on average, twice as 

large as those in PADD 1 and three times as large as those in PADDs 3 and 4

Publicly-owned shutdown refineries were largest in PADD 1 (over 82,000 barrels per 

day) and PADD 2 (almost 45,000 barrels per day)

Publicly-owned refineries with capacities averaging 20,000 barrels per day were shut 

down in PADDs 3, 4, and 5
Appendix G G-3

Table G-2. U.S. Shutdown Refineries by Ownership and PADD, 1990-2010

Measure Ownership PADD Total 1 2 3 4 5

Number 

Private 4 10 17 1 14 46

Public 5 4 6 2 3 20

MBD 

Capacity

Private 57,350 323,815 187,700 10,000 284,850 863,715 

Public 413,000 177,500 132,680 48,000 57,875 829,055 

Average 

Size 

(MBD)

Private 14,338 32,382 11,041 10,000 20,346 18,776 

Public 82,600 44,375 22,113 24,000 19,292 41,453 

Refinery data presented in this appendix was developed from EIA listings of shutdown 

refineries, enhanced by information gathered from corporate and news websites. The complete 

listing is shown on Table G-3.
Appendix G G-4

Table G-3. Refinery Shutdowns 1990-2010
Appendix G G-5
Appendix G G-6

Notes: Most refineries become terminals after shut down, likely due to expensive cleanup when EPA licenses are revoked. 

By converting to terminals, sites keep their licenses, do not have to perform expensive cleanups, and can restart operations without requiring new permits. 

Refineries in bold were owned by public companies.

Sources: EIA, corporate and news websites.
Appendix H H-1

Appendix H. Disproportionate Economic 

Hardship

Refinery Rankings

The scoring matrix contained within the report evaluates the full impact of disproportionate 

economic hardship on small refiners and assesses the individual degree of potential impairment. 

The matrix is comprised of two major sections: one section combining the scoring for 

disproportionate structural and economic weightings, and a separate section regarding the impact 

of compliance on the viability of the firm. The ranking methodology is fully described within 

the report. Table H-1 provides the detailed scores, and Figure H-1 provides the disproportionate 

impacts and viability indices for each of the eighteen refineries that submitted sufficient data to 

be evaluated.
Appendix H H-2

Table H-1. Refinery Ranking Estimates

[Redacted]
Appendix H H-3

Figure H-1. Refinery Rankings by PADD

[Redacted]