Department of Energy Analyses in Support of the EPA 

Evaluation of Waivers of the Renewable Fuel Standard

November 2012

Ethanol Demand Curve for 2012 and 2013

In support of EPA analyses of the 2012 RFS waiver requests, DOE developed an 

ethanol demand curve (Figure 1) to be used as an input assumption for stochastic 

modeling and assessment of ethanol demand, corn supply and demand and 

economic impacts. The approach in developing the demand curve follows the 

same approach adopted in support of a RFS waiver request from the State of 

Texas in 2008; the ethanol demand curve is developed based on the price ratio of 

ethanol vs. gasoline (E/G Price Ratio). The differences between the constructions

of the 2008 vs. 2012 ethanol demand year reflect the following factors: the 

relative levels of ethanol blending into gasoline, the expected markets for ethanol 

blending after the ethanol low level blend wall is encountered, and the expectation 

that any waiver of the RFS program would be for only one year. The ethanol 

demand curve was developed by analyzing the value of ethanol as a blending 

component relative to other gasoline blending components in the refinery linear 

program (LP). The refinery LP contains detailed representation of refinery 

processing units, raw material inputs costs and qualities, and variable and fixed 

operating costs and detailed gasoline blending representation to capture both 

product environmental and performance specifications for the winter and summer 

gasoline seasons.1 Additionally, DOE assessed the capability of refiners, 

terminal operators, and pipeline companies to change the transportation, 

distribution, and terminal blending infrastructure facilities to reduce or increase 

the amount of ethanol use in the short term. 

Refinery Blending Economics

DOE conducted a detailed analysis of the gasoline blending economics of ethanol 

relative to other high octane blending components available within refinery. The 

analysis was done for both the winter and summer gasoline seasons, and for 

refineries that produce either a mix of reformulated, sub-specification gasoline 

blendstocks for ethanol blending (CBOB) and conventional gasoline for ethanol 

“splash” blending, or produce only conventional gasoline and conventional 

gasoline blendstocks for ethanol blending. The refinery LP model indicated that 

for a typical cracking refiner that produces both winter and summer conventional 

and CBOB gasoline, the ethanol value is about equivalent to the octane 

replacement costs from refinery feedstocks. The marginal cost of production of 

the primary octane replacement is almost equivalent to an E/G ratio of 1.1. The 

refinery LP analysis also indicates that the ethanol value to a refinery is higher at 

lower ethanol consumption levels than it is when ethanol reaches the low level 

gasoline ethanol blend wall. 

 

1

See Appendix A for more information on analysis conducted using the refinery linear program.
2

E10 Refueling Infrastructure Issues

The analysis below describes how the gasoline supply infrastructure can limit 

refiners’ and blenders’ capability to quickly change the proportion of ethanol 

blended gasoline they produce and market. Refiners and gasoline blenders have 

increased their production of 10 percent ethanol gasoline blends (E10) over the 

last eight years for several reasons. First, the ethanol value as a blending 

component has increased as the crude oil price has increased and, subsequently,

the gasoline price, and as significant volumes of new ethanol production capacity 

came online in response to the renewable fuel standard (RFS) enacted in the 

EPACT 2005 and were increased in the EISA 2007. Further ethanol production 

also came online as the ethanol excise tax exemption made blending ethanol into 

gasoline a valuable gasoline blendstock relative to gasoline blendstock derived 

from crude oil. Second, refiners gained experience handling ethanol when in 

2006, they chose to replace MTBE as a blending component to address concerns 

with MTBE causing water quality issues in areas where gasoline leaked from 

underground fuel storage tanks. This MTBE-to-ethanol transition resulted in 

some retail operators having to drain storage tanks to remove excess amount of 

water and replace refueling equipment filters that swelled due to water 

contamination. 

Third, refiners and blenders in 2008 exercised discretionary blending of ethanol at 

levels significantly above the RFS mandate level due to good economics. When 

the price of ethanol rose to a level where it became uneconomic for refiners they 

reduced the amount of ethanol they blended with gasoline. During this transition, 

some refiners and blenders learned that some of their terminals and ethanol 

blending equipment were not sophisticated enough for optimized blending or 

blending at multiple sub-specification grades, which allows varying the demand 

for E10. Finally, when refiners and blenders chose to reintroduce ethanol blended 

gasoline to retail stations that had stopped selling ethanol blended grades, some 

storage tanks had to be drained completely to remove water and some refueling 

equipment required the changing of filters. 

Ethanol Supply Contracts

Another issue limiting refiners’ and blenders’ ability to quickly change the 

quantity of ethanol they blend into gasoline is the structure of their contracts with 

ethanol suppliers. Many of these contracts are long-term with a predetermined 

price and volume over a given period of time. That is, the contracts require the 

purchaser of ethanol to pay for contracted delivery of ethanol whether or not 

market conditions have changed.
3

These transition issues surrounding the proposition of introducing ethanol blended 

gasoline into retail markets, removing ethanol blended gasoline from the market, 

and then reintroducing it increases transition costs. The result is that refiners and 

blenders are unlikely to switch between providing ethanol blended grades of 

gasoline and non-ethanol grades of gasoline in markets in the short run. The only 

exceptions would be during the transition from winter to summer specification 

grades of gasoline or from summer to winter gasoline when stocks of gasoline are 

brought down to accommodate the seasonal gasoline specification changes.

RFS Compliance Beyond 2013

The ability of refiners and blenders to comply with the RFS requirements beyond 

the 2012 and 2013 compliance years will likely play an important role in how 

they comply with the RFS requirements in 2012 and 2013, even if the 2012 or 

2013 RFS requirements are changed as a result of the RFS waiver request.

This is because the low level ethanol gasoline blend wall may soon limit, the 

incremental volumes of ethanol that refiners and blenders can blend into gasoline. 

Other RFS compliance strategies would increase the blending of biomass-based 

diesel and increase the volume of ethanol sold as E85 or possibly introduce E15 

blends for use in 2001 model year or newer vehicles. Widespread adoption of E15 

blends that would significantly increase ethanol demand in the next year is not 

considered feasible or evaluated as a possible compliance strategy due to issues 

that still need to be resolved. 

Assuming the only viable compliance strategy for 2014 in generating incremental 

RINs is either blending non-ethanol renewable fuels such as biomass-based diesel 

or selling incremental volumes of E85, the value of RINs could easily approach 

$1.00 or more per ethanol-equivalent gallon. This is because E85 compliance 

would require ethanol to sell at a price that is reflective of its lower energy 

content, plus an additional discount to compensate for consumers’ need to refuel 

more often. This discount could be on the order of $1.00 or more per gallon 

assuming spot gasoline prices are in the $2.50 to $3.00 per gallon range and 

ethanol production costs are in the $2.20 to $2.80/gallon range.

Given the issues outlined above, the ethanol demand curve between the E/G 

ration of 1.0 to 1.5 was reduced to a level at which refiners would begin to 

remove ethanol from markets where they are currently splash blending ethanol on 

top of finished gasoline. Refiners would limit removing ethanol from markets 

where there is optimized blending for octane compliance. The demand curve 

incrementally backs out ethanol demand as ethanol prices rise above gasoline to a 

maximum of 3 billion gallons, which accounts for all the splash-blended ethanol 

market and a small portion of the optimized-blended ethanol markets. 
4

E85 Retail Economics

Marketing E85 to flexible-fuel vehicle owners will require retailers to adjust the 

price of fuel to account for both ethanol’s lower energy content relative gasoline 

and the reduced number of miles a tank of E85 will achieve relative to gasoline or 

E10 blends. A gallon of E85 provides about 75 percent of the energy a gallon of 

gasoline provides and a tank of E85 will only take a consumer 225 miles while a 

tank of gasoline would provide 300 miles of travel. Consumers will notice this 

difference and will require the price of E85 to be lower to make up the difference. 

Additionally, many consumers will likely want an additional incentive to account 

for the more frequent refueling that E85 requires. In the end, E85 may need to be 

priced at a greater discount than it would be based on the energy content 

differential between E85 and gasoline alone. Additionally, retailers that make 

investments in E85 refueling tanks and pumps will likely require that the retail 

margins for E85 be higher than those for gasoline because sales volumes will 

likely be lower than what could be achieved with investments in gasoline 

refueling infrastructure. 

DOE incorporated the E85 retail economics into a short-term ethanol demand 

curve for the RFS waiver request analysis using the following assumptions. First,

the RFS waiver analysis is being performed over the 2012 to 2013 motor fuel 

demand time frame, it was assumed that incremental E85 sales would only take 

place at existing E85 retail outlets. Second, it was assumed that incremental 

investments in E85 refueling infrastructure would not change appreciably over the 

next 12 months. Third, the demand curve for ethanol was expanded to 

accommodate the incremental quantity of E85 that could be sold at existing retail 

E85 stations as the price of ethanol drops relative to gasoline. The maximum 

volume was limited to retailers refueling their E85 tanks (assumed to be about 

5000 gallons) from the current once per month refill rate to about a once per week 

refill rate, which is the approximately “average” refill rate of retail gasoline 

storage tanks in the U.S. This would result in the potential demand increase for 

E85 from approximately 125 million gallons annually to 600 million gallons 

annually.
5

Figure 1 Ethanol Demand Curve

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

0.00 2.00 4.00 6.00 8.00 10.00 12.00 14.00 16.00

E/G Price Ratio

B gallons /Yr

Ethanol Demand Curve for 2012 and 2013 

Compliance Years Only

Bgal vs E/G Price Ratio
6

Appendix: Refining Economics of Reducing Ethanol 

with Rising Ethanol Prices

Introduction

As a result of the Renewable Fuel Standard (RFS), industry made the necessary 

investments to blend ethanol into gasoline, and most gasoline today contains 10-

percent ethanol (by volume). With the drought this past growing season, the price 

of corn, the major feedstock for fuel ethanol, increased, and thus the price of 

ethanol increased. The Environmental Protection Agency (EPA) was asked to 

consider waiving the RFS, with the underlying assumption being that fuel demand 

for ethanol would decline, thus lowering both corn demand and the price of corn. 

The price of ethanol relative to gasoline is a key measure of when refiners might 

find it economic to back ethanol out of gasoline, should such a waiver be issued, 

and setting aside the hurdles and economics of transporting and storing additional 

gasoline “types”.2 As a result, DOE’s Office of Policy and International Affairs 

sponsored an analysis to explore the economics of reducing ethanol use at a 

refinery as the cost of ethanol rises relative to gasoline.

Many refiners have changed their operations to make use of ethanol’s high 

octane. They produce a sub-octane blending component that, when blended with 

10-percent ethanol, produces a finished gasoline with the appropriate octane and 

other driveability and emission properties. For these refiners, there is a cost to 

change back to producing a gasoline without ethanol. It was assumed that 

reformulated gasoline (RFG) would continue to be produced with ethanol, as it is 

easier and less expensive to remove ethanol from conventional gasoline. 

The study focused on Gulf Coast refineries3. Gulf Coast refineries represent about 

half of U.S. refinery capacity, and they produce mainly conventional gasoline, 

which represented almost 83% of the gasoline and blending component output in 

2012. These refiners supply the Gulf Coast area as well as East Coast and 

Midwest consumers with gasoline, and thus represent a large potential for ethanol 

reduction. 

 

2 We recognize that the distribution system is where the largest challenge may lie in changing the 

level of ethanol content in gasoline, but we also need to understand the costs at the refining level. 

3 Gulf Coast for this memo is Petroleum Administration for Defense District (PADD) 3. 
7

Analysis

The purpose of the study was to obtain a rough estimate of the level of cost 

changes refiners might see when reducing ethanol, which could then be used to 

explore relative ethanol price levels necessary to provide incentives to reduce 

ethanol volumes. A representative Gulf Coast refinery was analyzed using a

detailed refinery linear programming model (LP) developed by Jacobs 

Consultancy for the Department of Energy (DOE). The representative refinery 

runs a moderately heavy, high sulfur crude mix, and is equipped with fluid 

catalytic cracking (FCC), alkylation, coking, reforming, and full desulfurization 

units to accommodate the streams produced from the crude oil feed. 

Ethanol has a very high octane number, which adds to its value as a gasoline 

blend stock; however, it has a high vapor pressure and lower energy content than 

most other gasoline blend components. These properties impact how and at what 

cost refineries are impacted with reduction in ethanol use. 

The analysis examined the economics when refineries switch a portion of their 

production from conventional gasoline blend stock for oxygenate blending 

(CBOB), which is a sub-octane blend that will only meet all finished gasoline 

quality requirements when ethanol is added at the terminal in the sales region, to 

finished conventional gasoline that will meet quality specifications without 

ethanol being added. 

Crude oil was priced at $107 per barrel, gasoline was $123 per barrel, and ultralow sulfur diesel (ULSD) $128 per barrel, with typical summer/winter variations. 

Ethanol was priced equal to gasoline to isolate the added refinery variable cost 

resulting when ethanol volume is reduced. 

The base LP model run made 100% CBOB, meaning 10% ethanol would be 

added to every gallon of CBOB produced at the refinery. Then ethanol use was 

progressively reduced in subsequent cases. Three reduction cases were explored: 

1) CBOB production at 67% of total gasoline and 33% conventional, 2) 33% 

CBOB and 67% conventional, and 3) 100% conventional with no ethanol use. 

When the high-octane ethanol volume is reduced, the refinery compensates by 

finding more octane in other streams, primarily in reformate. Reformate is the 

gasoline blending component made in the reformer where molecules in the lowoctane naphtha feed are reformed into higher-octane aromatic molecules. The 

refiner can increase the aromatic content of the product, increasing the product 

octane, but in doing so the volume of reformate product decreases, and the 

volumes of light lower-priced refinery gases increase. The result is an increase in 

operating costs and a decrease on refinery margins both as operating costs 

increase and volumes of higher margin product decline. But if a refinery must 

pay a higher price for ethanol, it may be more economical to reduce ethanol and 
8

increase reformate octane (with its associated loss of volume for the gasoline 

pool).

Table 1 summarizes the economics for this Gulf Coast refiner. The table shows 

that as the refiner reduces ethanol use, the compensating cost increases from 1.1 

cents per gallon at the 33% conventional gasoline level to 3.7 cents per gallon 

when all the ethanol is removed. 

The model runs kept ethanol priced equal to gasoline, but we can calculate a 

break-even price, above which it is more economic for the refiner to reduce 

ethanol volumes and alternatively produce more octane within the refinery. As 

the table shows for the 33% conventional case with its 33% reduction in ethanol 

use, if ethanol prices rose 26.4 cents per gallon above the price of gasoline, then 

ethanol volume reduction becomes attractive. The table shows the increasing 

variable margin penalty and the increase in ethanol prices required to make 

ethanol reduction economic. 

Table 1. Summary Economic Results for Three Ethanol Reduction Cases

Base

Ethanol Reduction

Moderate Large Full

Percent CBOB 100 67 33 0

Percent Conventional (No Ethanol) 0 33 67 100

Average Percent Ethanol in Gasoline Pool 10 7 3 0

Added Variable Cost/Gallon of Gasoline (cpg) 1.1 2.4 3.7

Breakeven Ethanol Price Increase (cpg) 26.4 29.8 32.8

Ethanol/Gasoline Price Ratio 1.09 1.10 1.11

 Note: cpg – cents per gallon

Additional model runs were made for a Gulf Coast refinery making 20% RFG and 

the balance CBOB in the base case. The results showed only a small change 

compared to the table above. Based on conversations with several refiners, it 

seems likely many would experience results similar to those shown in the table. 

Some, however, will have more challenging economics for ethanol reduction. For 

example, refiners with poor gasoline octane pools and those who bring in large 

volumes of low-octane blending material such as “pentanes plus” streams would 

see less attractive economics. 
9

Conclusion

Our assessment based on analysis at the refinery level only is that, if the 

distribution system were able to handle variations on ethanol blends and if there 

was a waiver of the RFS program beyond one year, substantial ethanol could 

potentially be removed from U.S. refineries (mainly Gulf Coast). For reductions 

in ethanol blending to be profitable to refiners, however, the price of ethanol

would have to increase significantly; more than 26 cents per gallon of ethanol to 

incentivize an ethanol reduction of 33% and increasing ethanol costs to further 

reduced ethanol blending.